Form 10-K Securities and Exchange Commission Washington, D.C. 20549 (Mark One) [ X ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended DECEMBER 31, 1993 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 1-1217 Consolidated Edison Company of New York, Inc. (Exact name of registrant as specified in its charter) New York 13-5009340 (State of Incorporation) (I.R.S. Employer Identification No.) 4 Irving Place, New York, New York 10003 (Address of principal executive offices) (Zip Code) Registrant's telephone number: (212) 460-4600 - 2 - Securities Registered Pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered Consolidated Edison Company of New York, Inc. $5 Cumulative Preferred Stock, without par value New York Stock Exchange Cumulative Preferred Stock, 4.65% New York Series C ($100 par value) Stock Exchange Cumulative Preference Stock, 6% New York Convertible Series B ($100 par value) Stock Exchange Common Stock ($2.50 par value) New York, Midwest and Pacific Stock Exchanges The Edison Electric Illuminating Company of New York First Consolidated Mortgage Gold Bonds, New York 5%, due July 1, 1995 Stock (non-callable) Exchange Kings County Electric Light and Power Company, Purchase Money, 6%, 99 Years Gold Bonds, New York due October 1, 1997 Stock (non-callable) Exchange Securities Registered Pursuant to Section 12(g) of the Act: Title of each class Consolidated Edison Company of New York, Inc. Cumulative Preferred Stock ($100 par value): 4.65% Series D 5-3/4% Series E 6.20% Series F 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, and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive proxy statement incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ] - 3 - The aggregate market value of the voting stock held by non-affiliates of the registrant, as of January 31, 1994, was $7,467,331,738. Excluded from this figure is $2,694,969 representing the market value of 86,239 shares of Common Stock held by the registrant's Trustees (directors). The registrant's Trustees are the only stockholders of the registrant, known to the registrant, who might be deemed "affiliates" of the registrant. As of February 28, 1994, the registrant had outstanding 234,477,014 shares of Common Stock. Documents Incorporated By Reference Portions of the registrant's Proxy Statement for its 1994 Annual Meeting of Stockholders, to be filed with the Commission pursuant to Regulation 14A not later than 120 days after December 31, 1993, the close of the registrant's fiscal year, are incorpo- rated in Part III of this report. - 4 - TABLE OF CONTENTS Page PART I ITEM 1. Business . . . . . . . . . . . . . . . . . . . . 5 ITEM 2. Properties . . . . . . . . . . . . . . . . . . . 27 ITEM 3. Legal Proceedings . . . . . . . . . . . . . . . 31 ITEM 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . None Executive Officers of the Registrant . . . . . . . . . . 40 PART II ITEM 5. Market for the Registrant's Common Equity and Related Stockholder Matters . . . . . . . . 47 ITEM 6. Selected Financial Data . . . . . . . . . . . . 47 ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . 48 ITEM 8. Financial Statements and Supplementary Data. . . 60 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . None PART III ITEM 10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . * ITEM 11. Executive Compensation . . . . . . . . . . . . * ITEM 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . * ITEM 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . * PART IV ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . 102 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . 113 ___________________ *Incorporated by reference from the Company's definitive proxy statement for its Annual Meeting of Stockholders to be held on May 16, 1994. - 5 - PART I ITEM 1. BUSINESS Contents of Item 1 Page THE COMPANY . . . . . . . . . . . . . . . . . . . . . 5 INDUSTRY SEGMENTS . . . . . . . . . . . . . . . . . . 5 ELECTRIC OPERATIONS . . . . . . . . . . . . . . . . . 6 GAS OPERATIONS . . . . . . . . . . . . . . . . . . . 10 STEAM OPERATIONS . . . . . . . . . . . . . . . . . . 11 CAPITAL REQUIREMENTS AND FINANCING . . . . . . . . . 12 FUEL SUPPLY . . . . . . . . . . . . . . . . . . . . 12 REGULATION AND RATES . . . . . . . . . . . . . . . . 15 COMPETITION . . . . . . . . . . . . . . . . . . . . . 17 ENVIRONMENTAL MATTERS AND RELATED LEGAL PROCEEDINGS . . . . . . . . . . . . . 18 GENERAL . . . . . . . . . . . . . . . . . . . . . . . 22 EMPLOYEES . . . . . . . . . . . . . . . . . . . . . . 22 RESEARCH AND DEVELOPMENT . . . . . . . . . . . . . . 22 OPERATING STATISTICS . . . . . . . . . . . . . . . . 23 FIVE-YEAR FORECAST . . . . . . . . . . . . . . . . . 25 THE COMPANY Consolidated Edison Company of New York, Inc. (the Company), incorporated in New York State in 1884, supplies electric service in all of New York City (except part of Queens) and most of Westchester County, a service area with a population of more than 8 million. It also supplies gas in Manhattan, The Bronx and parts of Queens and Westchester, and steam in part of Manhattan. Most governmental customers within the Company's service territory receive electric service from the New York Power Authority (NYPA) through the Company's facilities. In 1993, electric, gas and steam operating revenues were 81.9 percent, 12.9 percent and 5.2 percent, respectively, of the Company's operating revenues. INDUSTRY SEGMENTS For information on operating revenues, expenses and income for the years ended December 31, 1993, 1992 and 1991, and assets at those dates, relating to the Company's electric, gas and steam operations, see Note H to the financial statements in Item 8. - 6 - ELECTRIC OPERATIONS ELECTRIC SALES. Electric operating revenues were $5.1 billion in 1993 or 81.9 percent of total Company operating revenues. The percentages were 82.4 and 83.4, respectively, in the two preceding years. Electricity sales in the Company's service area in 1993, including usage by customers served by NYPA and the New York City and Westchester County municipal electric agencies, but excluding sales to other utilities, increased 3.3 percent from 1992, after decreasing 2.7 percent in 1992 and increasing 2.0 percent in 1991. After adjusting for variations, principally weather, electricity sales volume increased 1.0 percent in 1993, decreased 0.3 percent in 1992 and increased 0.8 percent in 1991. Weather-adjusted sales represent the Company's estimate of the sales that would have been made if historical average weather conditions had occurred. In 1993, 80.5 percent of the electricity sold in the Company's service area was sold by the Company to its customers, and the balance was sold by NYPA and municipal electric agencies to their customers. Of the Company's sales, 29.0 percent was to residential customers, 66.3 percent was to commercial customers, 3.0 percent was to industrial customers and the balance was to railroads and public authorities. For further information about amounts of electric energy sold, see "Operating Statistics", below. For a forecast of electric energy sales, see "Five-Year Forecast", below. ELECTRIC SUPPLY. The Company either generates the electric energy it sells, purchases the energy from other utilities or independent power producers (IPPs) pursuant to long-term firm power contracts or purchases non-firm economy energy. The sources of electric energy generated and purchased during the years 1989-1993 are shown below: 1989 1990 1991 1992 1993 Generated: Fossil-Fueled . . . . . 64.7% 59.8% 51.4% 42.3% 35.5% Nuclear (Indian Point 2) 10.9% 13.3% 9.8% 20.4% 14.8% Total Generated . . . 75.6% 73.1% 61.2% 62.7% 50.3% Firm Purchases: NYPA . . . . . . . . . 8.0% 8.1% 8.9% 4.8% 6.0% Hydro-Quebec . . . . . 6.5% 3.3% 1.9% 2.9% 4.3% IPPs . . . . . . . . . 0.9% 0.9% 1.0% 8.9% 11.9% Other Purchases . . . . . 9.0% 14.6% 27.0% 20.7% 27.5% Generated & Purchased . . 100% 100% 100% 100% 100% - 7 - For information about the Company's generating facilities, see "Electric Facilities - Generating Facilities" in Item 2. For information about the Company's purchases of electric energy, see "NYPA", "Hydro-Quebec", "Independent Power Producers" and "New York Power Pool", below. For further information about amounts of electric energy generated and purchased, see "Operating Statistics", below. ELECTRIC PEAK LOAD AND CAPACITY. The electric peak load in the Company's service area occurs during the summer air conditioning season. The 1993 one-hour peak load in the Company's service area, which occurred on July 8, 1993, was 10,667 thousand kilowatts (MW), including an estimated 9,032 MW for the Company's customers and 1,635 MW for NYPA's customers and municipal electric agency customers. It is estimated that the service area peak load was reduced by 39 MW of curtailable load reduction. The record one-hour peak for the service area occurred on July 23, 1991 - 10,752 MW, including an estimated 9,229 MW for the Company's customers. The peak in 1993, if adjusted to design weather conditions, would have been 10,650 MW, 50 MW higher than the peak in 1992 and 100 MW higher than 1991's record peak, each similarly adjusted. "Design weather" for the electric system is a standard to which the actual peak load is adjusted for evaluation. The capacity resources available to the Company's service area at the time of the system peak in the summer of 1993 totalled (before outages) 13,165 MW, of which 10,882 MW represented net available generating capacity (including the capacity of NYPA's Poletti and Indian Point 3 Units) and 2,283 MW represented net firm purchases by the Company and NYPA. For a forecast of peak load and capacity, see "Five-Year Forecast", below. For information about the Company's generating, transmission and distribution facilities, see "Electric Facilities" in Item 2. For information about the Company's plans to meet its requirements for electric generating capacity, see "Liquidity and Capital Resources - Electric Generating Capacity" in Item 7. - 8 - NYPA. NYPA supplies its customers in the Company's service area with electricity from its Poletti fossil-fueled unit in Queens, New York, its Indian Point 3 nuclear unit in Westchester County and other NYPA sources. Electricity is delivered to these NYPA customers through the Company's transmission and distribution facilities, and NYPA pays a delivery charge to the Company. NYPA is contractually obligated to the Company to provide the capacity needed to meet the present and future electricity requirements of its customers, except that upon 17 years' prior notice to the Company, NYPA may elect not to provide for future growth of its customers' requirements. The Company purchases portions of the output of Poletti and Indian Point 3 on a firm basis. The Company also purchases firm capacity from NYPA's Blenheim-Gilboa pumped-storage generating facility in upstate New York. The Company and NYPA also sell to each other energy through the New York Power Pool. See "New York Power Pool", below. HYDRO-QUEBEC. The Company has an agreement with NYPA to purchase, through a contract between NYPA and Hydro-Quebec (a government-owned Canadian electric utility), 780 MW of capacity and associated kilowatt-hours of energy each year during the months of April through October until October 31, 1998 (the Diversity Purchase). The amount and price of a "basic amount" of energy the Company is entitled to purchase each year are subject to negotiation with Hydro-Quebec and approval by the National Energy Board of Canada, a Canadian regulatory agency. However, the capacity commitment is firm and the Company may draw upon the capacity in accordance with the contract even if the energy received by the Company exceeds the basic amount, provided the Company returns the excess energy to Hydro-Quebec during the following November-through-March period. The Company, NYPA and Hydro-Quebec have signed agreements for the continuation of the Diversity Purchase from April 1, 1999 through October 31, 2018. Unlike the agreements for the current Diversity Purchase, under the new agreements the annual amount of energy would be fixed and the price for the energy would be established in accordance with formulas and procedures set forth in the agreements. Because of changes in the wholesale power market that have occurred since the new agreements were signed, the new agreements have become uneconomic. In March 1994, the Company and NYPA announced their intention to cancel the new agreements (as is permitted under the new agreements). - 9 - INDEPENDENT POWER PRODUCERS. Federal and state regulations encourage competition in the market for generation of electric power. These laws generally require electric utilities to purchase electric power from and sell electric power to qualifying IPPs. The Federal Energy Regulatory Commission (FERC) has issued rules requiring utilities to purchase electricity from all qualifying facilities at a price equal to the purchasing utility's "avoided cost." In addition, the Energy Policy Act of 1992 broadened the FERC's authority to require electric utilities to provide others with access to their transmission systems and reduced regulation of certain IPPs. See "Liquidity and Capital Resources - Electric Generating Capacity and Competition" in Item 7. NEW YORK POWER POOL. The Company and the other major electric utilities in New York State, including NYPA, are members of the New York Power Pool. The primary purpose of the Power Pool is to coordinate planning and operations, including the purchase and sale of non-firm economy energy. As a member of the Power Pool, the Company is required to maintain its capacity resources (net generating capacity and net firm purchases) at a minimum reserve margin of 18% above its peak load, and to pay penalties if it fails to maintain the required level. The Company met the reserve requirement in 1993 and expects to meet it in 1994. See "Five-Year Forecast", below. MUNICIPAL ELECTRIC AGENCIES. Westchester County and New York City maintain municipal electric agencies to purchase electric energy, including hydroelectric energy from NYPA. The Company has entered into agreements with the County and City agencies whereby the Company is delivering interruptible hydroelectric energy from NYPA's Niagara and St. Lawrence projects to electric customers designated by the agencies. These agreements may be terminated by either party on or after December 31, 1995 upon either one year's prior notice or, in certain circumstances, upon 10 days' notice. A similar agreement, covering energy from NYPA's Fitzpatrick nuclear plant, terminates in 2003. For information on the amount of energy delivered, see "Operating Statistics", below. - 10 - GAS OPERATIONS GAS SALES. Gas operating revenues in 1993 were $808.4 million or 12.9 percent of total Company operating revenues. The percentages were 12.3 and 11.5, respectively, in the two preceding years. Gas sales volume to firm customers increased 0.6 percent in 1993 from the 1992 level. After adjusting for variations, principally weather, firm gas sales volume to these customers increased 3.9 percent. Including sales to interruptible customers, actual sales volume increased 1.6 percent in 1993. Natural gas is delivered by pipeline to the Company and is distributed to customers through the Company's system of distribution mains and services. For information about the Company's gas facilities, see "Gas Facilities" in Item 2. Regulatory changes, which have resulted in the unbundling of services in the natural gas industry, are enabling users of gas to purchase gas directly from suppliers and arrange for its transportation by the appropriate pipeline and local utility companies. In 1993, the Company established an unregulated subsidiary to market gas and related services. In compliance with regulatory restrictions, the subsidiary does not market gas within the Company's gas service area. During 1993, 53 large-volume customers in the Company's service territory purchased gas directly from suppliers. The customers pay a transportation charge to the Company for delivering the gas. For information on the quantities of gas sold, transported for others and used by the Company as boiler fuel to generate electricity and steam, see "Operating Statistics" and "Fuel Supply", below. GAS REQUIREMENTS. Demand for gas in the Company's service area tends to peak during the winter heating season. The design criteria for the Company's gas system assume severe weather conditions that have not occurred in the Company's service area since 1934. Under these criteria, the Company estimates that the requirements to supply its firm gas customers, together with the minimum amount essential for the electric and steam systems, would amount to 71,300 thousand dekatherms (mdth) of gas during the 1993/94 winter heating season and that gas available to the Company would amount to 94,200 mdth. For the 1994/95 winter, the Company estimates that the requirements would amount to approximately 73,300 mdth and that the gas available to the Company would amount to approximately 92,400 mdth. As of March 22, 1994, the 1993/94 winter peak day sendout to the Company's customers was 800 mdth, which occurred on January 19, 1994. The Company estimates that, under the design criteria, the peak day requirements for firm customers during the 1994/95 winter season would amount to approximately 845 mdth and expects that it would have sufficient gas available to meet these requirements. - 11 - GAS SUPPLY. The Company has contracts for the purchase of firm transportation and storage services with seven interstate pipeline companies. The Company also has contracts with nine pipeline and non-pipeline suppliers and three Canadian suppliers for the firm purchase of natural gas. The Company also has interruptible gas purchase contracts with numerous suppliers and interruptible gas transportation contracts with interstate pipelines. Based on its current projections of demand and prices for gas and oil, the Company expects for at least the next several years to be able to supply its firm gas customers' requirements, maintain an adequate inventory of storage gas and meet most of the requirements of its large-volume interruptible customers. STEAM OPERATIONS STEAM SALES. The Company sells steam in Manhattan south of 96th Street, mostly to large office buildings, apartment houses and hospitals. In 1993, steam operating revenues were $325.3 million or 5.2 percent of total Company operating revenues. The percentages were 5.3 and 5.1, respectively, in the two preceding years. Steam sales volume was unchanged in 1993 from the 1992 level. After adjusting for variations, principally weather, steam sales decreased 0.1 percent. STEAM SUPPLY. 74 percent of the steam sold by the Company is produced in the Company's electric generating stations, where it is first used to generate electricity. For information about the Company's steam facilities, see "Steam Facilities" in Item 2. STEAM PEAK LOAD AND CAPABILITY. Demand for steam in the Company's service area tends to peak during the winter heating season. The one-hour peak load during the winter of 1993/94 (through March 22, 1994) occurred on January 20, 1994 when the load reached 12.2 million pounds. The Company estimates that for the winter of 1994/95 the peak demand of its steam customers would be approximately 12.4 million pounds per hour under design criteria, which assume severe weather. On December 31, 1993, the steam system had the capability of delivering about 13.4 million pounds of steam per hour. This figure does not reflect the unavailability or reduced capacity of generating facilities resulting from repair or maintenance. The Company estimates that, on a comparable basis, the system will have the capability to deliver approximately 13.4 million pounds of steam per hour in the 1994/95 winter. - 12 - CAPITAL REQUIREMENTS AND FINANCING For information about the Company's capital requirements and financing, the refunding of certain securities and the Company's securities ratings, see "Liquidity and Capital Resources" in Item 7. Securities ratings assigned by rating organizations are expressions of opinion and are not recommendations to buy, sell or hold securities. A securities rating is subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating. For a forecast of certain operating and financial data, see "Five-Year Forecast", below. FUEL SUPPLY GENERAL. In 1993, 28 percent of the electricity supplied to the Company's customers was obtained by the Company through economy purchases of energy produced from a variety of fuels. Of the remaining 72 percent, which was either generated by the Company or obtained through long-term firm purchases of energy (see "Electric Operations", above), on the basis of British thermal units (Btu) consumed, oil was used to generate 10.5 percent of the electricity, natural gas 36.2 percent, nuclear power 20 percent, hydroelectric power 4.3 percent, and refuse 1.0 percent. The fuel used to produce steam during 1993 was 63.5 percent oil and 36.5 percent natural gas. A comparison of the cost, in cents per million Btu, of fuel used by the Company to generate electricity and steam during the years 1989-1993 is shown below: 1989 1990 1991 1992 1993 Residual Oil . . . . . 315 398 355 345 348 Distillate Oil . . . . 447 558 491 501 499 Natural Gas . . . . . 263 283 288 285 286 Nuclear . . . . . . . 50 63 50 43 37 Weighted Average . . . 268 297 281 232 229 The Company is prohibited from using fuels that do not conform to the requirements of the New York State air pollution control code and, in the case of its in-city plants, the New York City air pollution control code. In the City, the Company is not permitted to burn coal or to burn residual fuel oil having a sulfur content of more than 0.3 percent. - 13 - RESIDUAL OIL. Based on anticipated consumption rates, the Company has an adequate supply of residual fuel oil for its generating stations and the Company's shares of generating capacity at the Roseton and Bowline Point stations jointly-owned by the Company and other utilities. See "Electric Facilities" in Item 2. Oil consumption rates vary widely from month to month. The oil burned at Company facilities in 1993, including the Company's shares of generating capacity at Roseton and Bowline Point, totaled 11.8 million barrels. The Company has contracts for oil supply that have staggered termination dates and has options for additional oil supply sufficient to cover all of its expected requirements for residual oil through September 1994. The Company anticipates covering the balance of its 1994 requirements through new contracts, exercise of existing contract options and purchases on the spot market. The Company estimates that more than 90 percent of its residual oil originates from foreign sources of crude oil. Supplies could be jeopardized by events such as the oil embargo imposed in 1973 or the 1979 supply disruption resulting from the revolution in Iran. The Company experienced no supply interruption during the 1991 Persian Gulf hostilities. NATURAL GAS. During 1993, the Company burned approximately 122,981 mdth of gas for the production of electricity and steam, including 14,828 mdth attributable to the Company's share of generating capacity at the Roseton and Bowline Point stations. Burning gas instead of oil reduced the Company's 1993 fuel oil requirements by about 20 million barrels. The Company expects to continue to have substantial amounts of gas available in 1994 for the production of electricity and steam. DISTILLATE OIL. The Company's estimated 1994 requirements for distillate oil for gas turbine fuel are about 400,000 barrels. The Company expects to be able to satisfy these requirements through purchases on the spot market. COAL. The Company does not burn coal. In 1983, the New York State Department of Environmental Conservation (DEC) ruled on an application by the Company for permission to convert three electric generating units, Ravenswood 3 in Queens and Arthur Kill 2 and 3 on Staten Island, to coal-burning. The DEC ruled that the Company would be permitted to burn coal at each location only if flue gas desulfurization (FGD) systems were installed. The Company's studies showed that it would not be economical to pursue coal conversion with FGD systems. However, the Company has installed most of the necessary facilities (without FGD systems) at Ravenswood 3 and Arthur Kill 3 to provide for coal-burning in emergency circumstances such as an oil supply interruption. Even in such an emergency, a special permit, or waiver of existing restrictions, would be required to allow the Company to burn coal at these units. - 14 - NUCLEAR FUEL. The nuclear fuel cycle for power plants like Indian Point 2 consists of (1) mining and milling of uranium ore, (2) chemically converting the uranium in preparation for enrichment, (3) enriching the uranium, (4) fabricating the enriched uranium into fuel assemblies, (5) using the fuel assemblies in the generating station and (6) storing the spent fuel. The Company has contracts covering its expected requirements for uranium and conversion for Indian Point 2 through 1995, with options extending through 1999, and for fuel fabrication through 2001. The Company has contracts covering most of its requirements for uranium enrichment services for the operating life of Indian Point 2. For information about certain assessments to be paid to the United States Department of Energy (DOE) by utilities that have used nuclear fuel, see "Liquidity and Capital Resources - Uranium Enrichment Decontamination and Decommissioning Fund" in Item 7. Under normal operating conditions, scheduled refueling and maintenance outages are generally required for Indian Point 2 after each cycle of approximately 22 months of operation. The last such outage ran from January 30, 1993 to April 22, 1993. Mid-cycle inspection and maintenance outages may also be required from time to time. The Company has a contract with the DOE, under the Federal Nuclear Waste Policy Act of 1982, which provides that, starting in 1998, the DOE will take title to spent fuel, transport it to a Federal repository and store it permanently. The contract provides for a schedule of payments by the Company for storing existing and future spent fuel. Although the Company's contract has not been changed, the DOE has announced that it will probably not take possession of spent fuel before 2010. Spent fuel storage facilities at Indian Point have been expanded and currently have the capacity to hold all the fuel expected to be discharged from the unit through 2005. The Company is planning to provide for further on-site storage of spent fuel as required until DOE storage becomes available. - 15 - The Company has arranged for the disposal through June 1994 of low-level radioactive wastes (LLRW) generated at Indian Point 1 and 2 at the only domestic licensed disposal facility currently accepting LLRW for permanent disposal. Under a 1985 Federal law, by January 1996 New York State is to provide for permanent disposal of the Company's LLRW. The Company is planning to provide for further on-site storage of LLRW as required until New York State establishes a storage facility or adopts some other LLRW management method. REGULATION AND RATES GENERAL. The New York State Public Service Commission (PSC) regulates, among other things, the Company's electric, gas and steam rates, the siting of its transmission lines and the issuance of its securities. Certain activities of the Company are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). The Nuclear Regulatory Commission (NRC) regulates the Company's nuclear units. In addition, various matters relating to the construction and operation of the Company's facilities are subject to regulation by other governmental agencies. ELECTRIC, GAS and STEAM RATES. The Company's rates are among the highest in the country. In March 1994, the PSC approved a $55 million increase in electric rates to become effective April 1, 1994. The increase reflects recovery over a three-year period of costs associated with the termination of IPP contracts. For additional information about the Company's rates, see "Liquidity and Capital Resources - 1990 Electric Rate Settlement Agreement, 1992 Electric Rate Settlement Agreement, and Gas and Steam Rate Increases" in Item 7. In February 1993, an intervenor in the proceeding in which the PSC approved the 1992 electric rate settlement instituted a lawsuit in the New York State Supreme Court seeking an order setting aside the PSC's April 1992 approval of the settlement, directing refunds by the Company and directing the PSC to reconsider the Company's electric rates. In December 1993, the lawsuit was dismissed by the Appellate Division, Third Department, of the New York State Supreme Court. - 16 - GENERIC PROCEEDINGS. In 1991, the PSC initiated a proceeding to review the financial policies it uses to set utility rates. In May 1993, the Company agreed with the PSC staff, the other New York State electric and gas utilities and intervenors that the PSC should establish an "A" bond rating as the appropriate financial integrity target in order to give utilities needed access to financial markets on reasonable terms. Under this agreement, no action would be taken to reduce the rating of utilities above the "A" level unless the PSC found that the higher rating was inconsistent with the public interest. In June 1993, the utilities, the PSC staff and one intervenor in this proceeding agreed to a new method of calculating the cost of common equity in rate cases. The new method is less volatile because it is less sensitive to changes in interest rates than the method the PSC traditionally has used. The PSC is expected to rule on these agreements in 1994. For several years the PSC has required utilities to favor demand side resources in evaluating the cost-effectiveness of such resources by crediting such resources with 1.4 cents per kilowatt-hour for avoided adverse environmental impacts ("externalities"). In 1992, the PSC instituted a proceeding to reexamine the appropriate value for externalities. Consideration is being given to the application of externalities to supply side resources and the use of environmental (as opposed to economic) dispatch. This proceeding could have a significant impact on the cost of electricity. In March 1993, the PSC instituted a proceeding to examine competitive opportunities in the energy marketplace. In January 1994, the PSC staff recommended that utilities be permitted to offer discounted rates to customers with alternative sources of energy and that a utility's shareholders bear such portion of the costs of the discounts as is established for that utility in a rate proceeding. The staff also noted that the PSC could consider instituting a new proceeding to examine "retail wheeling". In a notice issued on March 17, 1994, the PSC requested that the parties to the proceeding address the scope of a possible PSC investigation into "...the appropriate market structure and regulatory regime for the future, including such fundamental changes as de-tarriffing for certain customers, deregulating the generation function and retail competition." The PSC is expected to issue a final decision in this proceeding in 1994. - 17 - In late 1993, the PSC instituted a proceeding to examine the impact of the emerging competitive gas market on gas utility rates and services. In particular, the PSC wanted to explore the impact of "unbundling" of sales and transportation services by interstate pipeline companies pursuant to FERC Order 636. The PSC has targeted the 1994/95 winter for implementation of any changes resulting from this proceeding. GAS TAKE-OR-PAY PROCEEDING. In 1988, the PSC instituted a generic proceeding to consider whether, and to what extent, New York gas utilities should be permitted to recover take-or-pay charges levied upon them by pipeline suppliers with the approval of the FERC. The PSC mandated that certain gas take-or-pay costs be deferred, with interest, pending a determination of disposition and that the remaining take-or-pay costs be collected from customers subject to refund. In September 1993, the PSC approved a settlement between the Company and the PSC staff pursuant to which amounts already collected from customers will no longer be subject to refund and the Company is permitted to bill customers for the deferred take-or-pay costs associated with the electric and steam departments over a two-year period and for the costs associated with the gas department over a four-year period. At December 31, 1993, deferred take-or-pay costs, including interest, amounted to $35 million. As part of the settlement, the Company will not accrue additional interest on unbilled deferred costs during the recovery period. STATE ENERGY PLAN. In March 1994, the New York State Energy Planning Board, comprised of the Chairman of the PSC and the Commissioners of the New York State Energy Office and the Department of Environmental Conservation, released a draft State Energy Plan which is designed to provide "an intelligent framework for evaluating the proper course for energy policy, environmental protection and economic development." The goal of the energy planning process is to "assure that New Yorkers will have a safe, affordable and reliable supply of energy that will promote future economic growth and protect our environment." The Company and other interested parties will have the opportunity to submit comments on and suggest changes to the draft Plan. COMPETITION For information concerning competition in the electricity and gas businesses, see "Liquidity and Capital Resources - Electric Generating Capacity and Competition" in Item 7 and "Gas Operations - Gas Sales" above. The PSC has issued rules requiring competitive bidding to be the primary means by which additional electric capacity and energy is obtained by utilities, although the PSC has indicated that utilities should pursue other alternatives when justified. - 18 - ENVIRONMENTAL MATTERS AND RELATED LEGAL PROCEEDINGS GENERAL. During 1993, the Company's capital expenditures for environmental protection facilities and related studies were approximately $22 million. The Company estimates that its capital expenditures for such facilities and related studies will amount to approximately $34 million in 1994 and $16 million in 1995. INDIAN POINT. The Company believes that a serious accident at its Indian Point 2 nuclear unit is extremely unlikely, but despite substantial insurance coverage, the losses to the Company in the event of a serious accident could materially adversely affect the Company's financial position and results of operations. For information about Indian Point 2 and the Company's retired Indian Point 1 nuclear unit, see "Electric Operations" and "Fuel Supply - Nuclear Fuel" above, "Cooling Towers" below, "Electric Facilities - Generating Facilities" in Item 2, "Liquidity and Capital Resources - Capital Requirements and Uranium Enrichment Decontamination and Decommissioning Fund" in Item 7 and Notes A and F to the financial statements in Item 8. SUPERFUND. The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (Superfund) by its terms imposes joint and several strict liability, regardless of fault, upon generators of hazardous substances for resulting removal and remedial costs and environmental damages. In the course of the Company's operations, materials are generated that are deemed to be hazardous substances under Superfund. These materials include asbestos and dielectric fluids containing polychlorinated biphenyls (PCBs). Other hazardous substances may be generated in the Company's operations or may be present at Company locations. Also, other hazardous substances may have been generated at the manufactured gas plants which the Company and its predecessor companies used to operate. For information about claims or possible claims against the Company under Superfund, see "Superfund" in Item 3 and "Superfund Claims" in Note F to the financial statements in Item 8. ASBESTOS. Asbestos is present in numerous Company facilities. In 1989, a Company steam main exploded in the Gramercy Park area of Manhattan, causing asbestos contamination of nearby buildings and requiring a major cleanup. Most of the costs were covered by insurance. See "Gramercy Park" in Item 3. For information with respect to suits against the Company involving asbestos, see "Asbestos Claims" in Note F to the financial statements in Item 8 and "Asbestos Litigation" in Item 3. - 19 - TOXIC SUBSTANCES CONTROL ACT OF 1976. Virtually all electric utilities, including the Company, own equipment containing PCBs. PCBs are regulated under the Federal Toxic Substances Control Act of 1976. The Company has reduced substantially the amount of PCBs in electrical equipment it uses, including transformers located in or near public buildings. AIR QUALITY. For information about the Federal Clean Air Act amendments of 1990, see "Liquidity and Capital Resources - Clean Air Act Amendments" in Item 7. The flue gases from oil combustion furnaces, including the Company's generating stations as well as home heating furnaces, contain microscopic particles of ash and soot. Some chemical constituents of these particles have been designated as "Hazardous Air Pollutants" under the Clean Air Act Amendments of 1990. Utility boilers are exempt from regulation as sources of hazardous air pollutants until the United States Environmental Protection Agency (EPA) completes a study of the hazards to public health reasonably anticipated to occur as a result of emissions by electric generating units. The EPA is expected to make a determination concerning the need for control of hazardous air pollutants from utility facilities in 1994. The New York State Department of Environmental Conservation (DEC) in March 1991 issued a notice of intent to prepare a draft environmental impact statement (DEIS) concerning a DEC draft of regulations that would establish standards of performance, effective beginning in the year 2000, for steam electric generating units that are operated beyond their "useful design life." The DEC draft regulations define "useful design life" as 45 years from the date of initial operation. All of the Company's steam electric generating units in New York City will have reached that point by 2014. The draft regulations would impose operating efficiency requirements (heat rates) that many of these units may not be able to meet, and stringent nitrogen oxides and particulate matter emissions limitations. - 20 - The DEIS process will afford the Company and other interested parties the opportunity to submit comments and suggest changes to the draft regulations. The Governor of New York has directed the DEC to integrate the requirements of the Clean Air Act Amendments with the proposed life extension regulations in a manner that meets the objectives of the State Energy Plan and considers the impact on utilities and ratepayers. See "Regulation and Rates - State Energy Plan", above. Upon completion of the DEIS, the DEC may propose regulations for adoption. If the DEC proposes regulations in their current draft form and they are adopted, the regulations could require the retirement of many of the Company's in-City electric generating units earlier than planned, starting in the year 2000. The Company and the New York Power Pool will oppose adoption of any regulations that would impose unreasonable standards of performance on electric generating units or require the premature retirement of such units. The Company is unable to predict the final form of the regulations. The New York City air pollution control code contains limitations on the allowable sulfur content of fuels and on emissions of sulfur dioxide, particulate matter, oxides of nitrogen and various trace elements. Certain provisions of the code, specifically those pertaining to standards for emissions of nitrogen oxides, may be impracticable to meet at some of the Company's generating stations located in New York City unless variances or other relief from such provisions are granted. COOLING TOWERS. The Federal Clean Water Act provides for effluent limitations, to be implemented by a permit system, to regulate the discharge of pollutants, including heat, into United States waters. In 1981, the Company entered into a settlement with the EPA and others that relieved the Company for at least 10 years from a proposed regulatory agency requirement that, in effect, would have required that cooling towers be installed at the Bowline Point, Roseton and Indian Point units. In return the Company agreed to certain plant modifications, operating restrictions and other measures and surrendered its operating license for a proposed pumped-storage facility that would have used Hudson River water. - 21 - In September 1991, after the expiration of the 1981 settlement, three environmental interest groups commenced litigation challenging the permit status of the units pending renewal of their discharge permits, which expired in October 1992. Under a consent order settling this litigation, certain restrictions on the units' usage of Hudson River water have been imposed on an interim basis until September 1994. Permit renewal applications were filed in April 1992, after which the DEC determined that the Company must submit a DEIS to provide a basis for determining new permit conditions. The DEIS, submitted in July 1993, includes an evaluation of the costs and environmental benefits of potential mitigation alternatives, one of which is the installation of cooling towers. After its review, the DEC will release for public comment the DEIS and draft permit conditions. Pending issuance of final renewal permits, the terms and conditions of the expired permits continue in effect. ELECTRIC AND MAGNETIC FIELDS. Electric and magnetic fields (EMF) are found wherever electricity is used. Several scientific studies have raised concerns that EMF surrounding electric equipment and wires, including power lines, may present health risks. Although no studies have established a cause-and-effect relationship between EMF and adverse health effects, the Company conducts research on EMF and also supports studies by the Electric Power Research Institute and by the Empire State Electric Energy Research Corporation. In the event that a causal relationship between EMF and adverse health effects is established, there could be a material adverse effect on the electric utility industry, including the Company. Under certain circumstances, there might be a material adverse effect even if no causal relationship is established. In October 1993, the New York State Court of Appeals held that to recover consequential damages in an eminent domain proceeding for the loss of value of the portion of claimants' property not taken for the construction of a high voltage power line, claimants had only to prove that there was some prevalent perception of a danger emanating from the power line that diminished the market value of the remainder of their property. Claimants did not have to prove the reasonableness of this perception. - 22 - GENERAL STATE ANTITAKEOVER LAW. New York State law provides that a "resident domestic corporation," such as the Company, may not consummate a merger, consolidation or similar transaction with the beneficial owner of a 20 percent or greater voting stock interest in the corporation, or with an affiliate of the owner, for five years after the acquisition of the voting stock interest, unless the transaction or the acquisition of the voting stock interest was approved by the corporation's board of directors prior to the acquisition of the voting stock interest. After the expiration of the five-year period, the transaction may be consummated only pursuant to a stringent "fair price" formula or with the approval of a majority of the disinterested stockholders. EMPLOYEES The Company had 17,586 employees on December 31, 1993. Approximately two-thirds of the employees are represented by a union whose collective bargaining agreement with the Company expires on June 22, 1996. An additional 2.5 percent of the employees are represented by another union whose collective bargaining contract expires on June 21, 1997. RESEARCH AND DEVELOPMENT For information about the Company's research and development costs, see Note A to the financial statements in Item 8. - 23 - OPERATING STATISTICS ===============================================================================================
Year Ended December 31 1993 1992 1991 1990 1989 - ----------------------------------------------------------------------------------------------- ELECTRIC Energy Generated Purchased and Sold (MWhrs): Generated 20,079,995 24,157,503 23,989,334 28,578,580 30,799,214 Purchased from Others 19,813,654 14,360,373 15,238,100 10,497,311 9,817,167 Total Electric Energy Generated and Purchased 39,893,649 38,517,876 39,227,434 39,075,891 40,616,381 Less: Electric energy supplied without direct charge 74 75 74 72 71 Electric energy used by Company (a) 183,903 173,834 157,079 164,274 164,863 Distribution losses and other variances 2,863,828 2,781,046 2,786,547 2,543,025 3,099,154 Total Electric Energy Sold (b) 36,845,844 35,562,921 36,283,734 36,368,520 37,352,293 Electric Energy Sold (MWhrs): Residential 10,512,496 9,845,397 10,380,814 9,861,492 9,699,143 Commercial and Industrial 25,118,125 24,680,600 24,930,864 25,066,438 24,709,127 Railroads and Railways 49,542 50,934 46,726 47,057 35,226 Public Authorities 560,836 542,358 531,272 499,243 491,114 Total Sales to Con Edison Customers 36,240,999 35,119,289 35,889,676 35,474,230 34,934,610 Delivery Service to NYPA Customers 8,441,624 8,187,292 8,241,174 8,205,452 8,138,268 Service for Municipal Agencies 361,854 287,489 681,791 250,913 113,982 Total Sales in Franchise Area 45,044,477 43,594,070 44,812,641 43,930,595 43,186,860 Sales to other electric utilities (c) 604,845 443,632 394,058 894,290 2,417,683 Average Annual kWhr Use Per Residential Customer (d) 4,104 3,872 4,116 3,928 3,884 Average Revenue Per kWhr Sold (cents): Residential (d) 16.0 15.0 14.7 14.4 13.8 Commercial and Industrial (d) 12.6 12.0 11.9 11.6 11.1 (a) Electric Energy used by the Company in 1993, 1992, 1991, 1990 and 1989 includes MWhrs of 29,233; 30,859; 9,354; 22,483 and 21,748 supplied to NYPA. (b) Includes sales to other electric utilities. (c) 1993, 1992, 1991, 1990 and 1989 include MWhrs of 2,142; 52,929; 4,982; 38,149 and 539,942 which were sold to NYPA and are also included in the Delivery Service to NYPA. (d) Includes Municipal Agency sales. - 24 - OPERATING STATISTICS =============================================================================================== Year Ended December 31 1993 1992 1991 1990 1989 - ----------------------------------------------------------------------------------------------- GAS (Dth): Purchased 214,719,241 221,181,200 222,730,835 226,222,779 200,498,993 Underground storage-net 222,559 752,561 (2,691,256) (7,119,602) (2,210,788) Used as boiler fuel at Electric and Steam Stations (108,153,436)(116,951,577)(121,773,852)(120,971,124) (93,140,739) Gas Purchased for Resale 106,788,364 104,982,184 98,265,727 98,132,053 105,147,466 Less: Gas used by Company 203,793 153,537 150,387 145,521 209,035 Distribution losses and other variances 3,998,234 3,856,836 5,563,386 3,001,176 7,781,704 Total Gas Sold 102,586,337 100,971,811 92,551,954 94,985,356 97,156,727 Gas Sold (Dth) Firm Sales Residential 52,624,331 52,626,406 46,200,725 46,471,766 48,670,195 General 37,214,994 36,656,433 33,539,780 33,968,421 34,508,071 Total Firm Sales 89,839,325 89,282,839 79,740,505 80,440,187 83,178,266 Interruptible Sales 12,747,012 11,688,972 12,811,449 14,545,169 13,978,461 Total Sales to Con Edison Customers 102,586,337 100,971,811 92,551,954 94,985,356 97,156,727 Transportation of Customer- Owned Gas 20,891,649 25,448,441 26,823,303 23,142,014 17,169,728 Total Sales and Transportation 123,477,986 126,420,252 119,375,257 118,127,370 114,326,455 Average Revenue Per Dth Sold: Residential $ 9.27 $ 8.41 $ 8.76 $ 8.78 $ 8.33 General $ 6.71 $ 6.03 $ 6.07 $ 6.28 $ 6.61 STEAM Sold (Mlbs): 29,394,335 29,381,922 28,531,067 28,492,095 31,081,097 Average Revenue per Mlbs Sold $11.06 $10.63 $10.45 $10.39 $ 9.03 Customers - Average for Year Electric 2,964,716 2,950,614 2,938,201 2,928,559 2,908,764 Gas 1,028,048 1,026,546 1,027,933 1,028,018 1,026,152 Steam 1,973 1,970 1,975 1,981 1,994 - 25 - FIVE-YEAR FORECAST The following pages show actual 1993 amounts for certain operating and financial data and the Company's forecasts of such data for the years 1994 through 1998. Footnotes appear following the forecast. The forecast data are estimates and not statements of fact. These estimates were developed by the Company for its planning purposes, based on information available on or shortly after December 31, 1993, including information and estimates provided by others. These estimates are reviewed and revised by the Company periodically. Like all projections, they are subject to, and may be rendered inaccurate by, future events. The forecast data could be affected by weather variations, changes in economic conditions or trends, changes in laws or regulations, and other unknown or unforeseen factors.
Actual Forecast Forecast Forecast Forecast Forecast 1993 1994 1995 1996 1997 1998 ENERGY SALES (a) Electric - millions of kilowatthours Con Edison customers: Total before DSM (b) 38,357 39,034 40,028 40,695 41,297 DSM (c) (2,267) (2,734) (3,116) (3,490) (3,848) Net Con Edison Customers 36,241 36,090 36,300 36,912 37,205 37,449 NYPA customers (d) 8,441 8,489 8,619 8,776 8,905 9,045 Municipal Electric Agencies (e) 362 382 391 393 397 451 Total Service Area 45,044 44,961 45,310 46,081 46,507 46,945 Gas - firm customers (f) (thousands of dekatherms) 89,839 93,300 95,400 99,000 101,100 104,500 Steam (million of pounds) 29,394 29,790 29,800 30,300 30,350 30,640 PEAK LOAD (g) Electric - peak hour load - megawatts Con Edison customers: Total before DSM (b) 9,736 9,955 10,176 10,400 10,603 Curtailable Electric Service (h) (i) (50) (25) 0 0 0 DSM (j) (675) (820) (941) (1,061) (1,173) Net Con Edison Customers 9,032 9,011 9,110 9,235 9,339 9,430 NYPA customers (d) 1,601 1,553 1,569 1,586 1,605 1,624 Municipal Electric Agencies (e)(k) 34 86 92 101 107 129 Net Service Area Peak Load 10,667(l) 10,650 10,771 10,922 11,051 11,183 Gas - firm customers (m) (thousands of dekatherms per day) 800 845 865 890 915 940 Steam (millions of pounds per hour)(n) 12.2 12.4 12.4 12.5 12.5 12.6 CAPABILITY Electric (net megawatts at summer peak) Con Edison generation 9,073 8,668 8,461 8,442 8,442 8,442 Firm purchases - IPPs (o) 648 665 2,020 2,359 2,359 2,359 Firm purchases - NYPA & Hydro-Quebec (p) 1,351 1,513 1,113 1,113 1,113 1,113 Con Edison capacity resources 11,072 10,846 11,594 11,914 11,914 11,914 Capacity for NYPA customers(d) 2,093 2,204 2,212 2,210 2,217 2,266 Total Service Area 13,165 13,050 13,806 14,124 14,131 14,180 Gas - firm purchases (thousands of dekatherms per day) 894 894 894 925 973 973 Steam (million of pounds per hour) 13.4 13.4 13.4 13.4 13.4 13.4 - 26 - Actual Forecast Forecast Forecast Forecast Forecast Forecast 1993 1994 1995 1996 1997 1998 5 Year Total CAPITAL REQUIREMENTS AND MATURING SECURITIES (millions of dollars) Construction Expenditures Electric $ 530 $501 $459 $450 $448 $385 $2,243 Gas 106 112 120 124 127 127 610 Steam 32 48 33 30 29 30 170 Common 121 109 131 125 112 100 577 Total Construction Expenditures (q) 789 770 743 729 716 642 3,600 Enlightened Energy program - net 59 64 6 (1) (10) 3 62 Power contract termination costs - net (r) 68 (36) (13) (3) (5) (7) (64) Nuclear Decommissioning Trust (s) 19 12 12 12 12 12 60 Nuclear Fuel Expenditures 14 53 13 52 14 55 187 Subtotal 949 863 761 789 727 705 3,845 Retirements of Long-Term Debt and Preferred Stock (t) 178 134 11 184 106 200 635 Total $1,127 $997 $772 $973 $833 $905 $4,480 PRINCIPAL NON-CASH CHARGES AND CREDITS TO INCOME (million of dollars) Book Depreciation and Amortization 404 425 448 468 492 514 2,347 Amortization of Nuclear Fuel 20 27 18 26 24 25 120 Deferred Taxes 94 70 80 60 50 60 320 Allowance for Equity and Borrowed Funds Used During Construction 11 13 10 11 10 9 53 - -------------------------------- FOOTNOTES TO FIVE-YEAR FORECAST (a) Forecasts for 1994-1998 assume normal weather conditions. (b) Does not include sales to other utilities. (c) For 1994-1998, this represents anticipated sales reduction resulting from Company sponsored demand side management and non-rebate induced conservation, cumulative since 1990. (d) See "Electric Operations - NYPA," above. (e) See "Electric Operations - Municipal Electric Agencies", above. (f) Actual sales to interruptible gas customers in 1993 amounted to 12,747 thousands of dekatherms (including 250 thousands of dekatherms sold to NYPA). (g) Forecasts for 1994-1998 assume design weather conditions. (h) For 1994-1995, this represents anticipated load reduction resulting from the Company sponsored curtailable electric service program. The program is scheduled to be terminated after 1995. (i) At 1993 peak, an estimated 39 MW of load reduction resulted from the Company sponsored curtailable electric service program. (j) For 1994-1998, this represents anticipated load reduction resulting from Company sponsored demand side management and non-rebate induced conservation, cumulative since 1990. (k) Includes electric demand of economic development customers. (l) At design weather conditions, the 1993 peak electric load would have been 10,650 MW. (m) Reflects the gas supply year which begins on November 1 of each calendar year shown. "Actual" peak day demand shown for 1993 assumes that peak day demand for the period occurred prior to March 22, 1994. (n) Reflects the winter season beginning in the year shown. "Actual" peak steam demand shown for 1993 assumes that peak day demand for the winter occurred prior to March 22, 1994. (o) For 1993 and 1994, includes capacity from Cogen Technologies (645 MW). Selkirk Cogen Partners, L.P. (265 MW), is expected to commence operational testing of its generating plant during the second quarter of 1994 and could commence commercial operation as early as August 1994. Sithe/Independence Power Partners, L.P. (740 MW) is expected to commence commercial operation late in 1994. Certain other IPPs (approximately 685 MW) are expected to commence commercial operation during 1995 and 1996. See "Liquidity and Capital Resources - Electric Generating Capacity" in Item 7. (p) See "Electric Operations - NYPA and Hydro-Quebec", above. (q) Assumes cost escalation at an average annual rate of 4.5 percent throughout the forecast period. (r) Does not reflect recovery provisions approved by the PSC in March 1994. See "Regulation and Rates - Electric, Gas and Steam Rates", above. (s) Reflects current rate allowance for nuclear portion of decommissioning costs. See Note A to the financial statements in Item 8. (t) Does not reflect refundings in advance of maturity. /TABLE - 27 - ITEM 2. PROPERTIES At December 31, 1993, the capitalized cost of the Company's utility plant, net of accumulated depreciation, (and excluding $70.4 million of nuclear fuel assemblies) was as follows: Net Capitalized Cost Percentage of Classification (millions of dollars) Net Utility Plant In Service: Electric: Production $ 1,770.6 18% Transmission 1,152.4 11% Distribution 4,602.8 46% Gas 1,052.2 10% Steam 329.8 3% Common 760.5 8% Held For Future Use 28.2 - Construction Work in Progress 389.2 4% Net Utility Plant $10,085.7 100% ELECTRIC FACILITIES GENERATING FACILITIES. As shown in the following table, at December 31, 1993, the Company's net maximum generating capacity (on a summer rating basis) was 8,674 MW, without reduction to reflect the unavailability or reduced capacity at any given time of particular units because of maintenance or repair or their use to produce steam for sale. For information about the electric energy purchased by the Company, see "Electric Operations" in Item 1. Net Generating Capacity Percentage of Electric Generating at December 31, 1993 Energy Generated and Stations (Megawatts-Summer Rating) Purchased in 1993 Fossil-Fueled Ravenswood (3 Units) 1,742 11.3% Astoria (3 Units) 1,075 9.4% Arthur Kill (2 Units) 826 1.6% East River (3 Units) 430 1.5% Bowline Point (2 Units) - two-thirds interest 808 4.5% Roseton (2 Units) - 40% interest 484 3.6% Other (8 Units) 291 2.9% Subtotal 5,656 34.8% Nuclear - Indian Point 931 14.8% Gas Turbines (39 Units) 2,087 0.7% Total 8,674 50.3% - 28 - The percentage of electric energy generated and purchased in 1993 shown on the table above for the Astoria station, 9.4 percent, includes energy generated by two units that were retired at the end of 1993. The Company's fossil-fueled plants burn natural gas or residual oil. Most of the gas turbines burn distillate oil. Certain units have the capability to burn either natural gas or oil, and certain units can be converted to burn coal. See "Fuel Supply" in Item 1. For information about the Company's Indian Point 2 nuclear unit, see "Electric Operations", "Fuel Supply - Nuclear Fuel", "Environmental Matters and Related Legal Proceedings - Indian Point and Cooling Towers" in Item 1, "Liquidity and Capital Resources - Capital Requirements" in Item 7 and Notes A and F to the financial statements in Item 8. The Company's generating stations are located in New York City with the exception of the Indian Point station in Westchester County, New York; the Bowline Point station in Rockland County, New York; and the Roseton station in Orange County, New York. The Company's electric and steam generating stations are held in fee with the following exceptions: (i) Orange and Rockland Utilities, Inc. (O&R) has a one-third interest and the Company has a two-thirds interest as tenants in common in the Bowline Point station, which is operated by O&R; (ii) Central Hudson Gas & Electric Corporation (Central Hudson) has a 35 percent interest, Niagara Mohawk Power Corporation (Niagara Mohawk) has a 25 percent interest and the Company has a 40 percent interest as tenants in common in the Roseton station (which is operated by Central Hudson), with Central Hudson having the right to acquire the Company's interest in 2004; and (iii) the Company leases from trusts in which it owns the remainder interests certain gas turbine generating facilities of which the Company can assume direct ownership upon expiration of the leases between 1995 and 1997. The Company has acquired property in the mid-Hudson valley, at a cost of approximately $12.8 million, as a possible location for baseload plants in the next century. Pursuant to the 1992 Electric Rate Settlement Agreement (see "Liquidity and Capital Resources - 1992 Electric Rate Settlement Agreement" in Item 7), the Company is conducting a study, expected to be completed in 1994, regarding whether to retain or dispose of the mid-Hudson site. - 29 - TRANSMISSION FACILITIES. The Company has interconnections for the transmission of power with Niagara Mohawk, Central Hudson, O&R, New York State Electric and Gas Corporation, Connecticut Light and Power Company, Long Island Lighting Company and Public Service Electric and Gas Company. At December 31, 1993, the Company's capacity to receive power from other systems to supply service area load at the time of the summer peak was approximately 3,400 MW, in addition to the transmission capacity needed to deliver to the Company's service area its share of the output of the Roseton and Bowline Point stations. The Company's transmission facilities are located in New York City and Westchester, Orange, Rockland, Putnam and Dutchess counties in New York State. At December 31, 1993, the Company's transmission system had approximately 427 miles of overhead circuits operating at 138, 230, 345 and 500 kilovolts and approximately 378 miles of underground circuits operating at 138 and 345 kilovolts. There are approximately 267 miles of radial subtransmission circuits operating at 138 kilovolts. The Company's transmission and area substations, supplied by circuits operated at 69 kilovolts and above, have a total transformer capacity of 40,759 megavolt amperes. DISTRIBUTION FACILITIES. The Company owns various substations and distribution facilities located throughout New York City and Westchester County. At December 31, 1993, the Company's distribution system had 56 distribution substations, with a transformer capacity of 22,021 megavolt amperes, 32,093 miles of overhead distribution lines and 82,348 miles of underground distribution lines. GAS FACILITIES Natural gas is delivered by pipeline to the Company at various points in its service territory and is distributed to customers by the Company through approximately 4,200 miles of mains and 355,000 service lines. The Company owns a natural gas liquefaction facility and storage tank at its Astoria property in Queens, New York. The plant can store approximately 1,000 mdth of which a maximum of about 250 mdth can be withdrawn per day. The Company has about 1,230 mdth of additional natural gas storage capacity at a field in upstate New York, owned and operated by Honeoye Storage Corporation, a corporation in which the Company and two neighboring utilities own a controlling interest. The Company has a wholly-owned subsidiary, Edison Liberty Transmission Corporation, which holds a 3 1/3 percent interest in a partnership planning to build a gas pipeline across the Lower New York Bay to a delivery point in New York City. - 30 - STEAM FACILITIES The Company generates steam for distribution at five electric generating stations and two steam-only generating stations and distributes steam to customers through approximately 88 miles of mains and 16 miles of service lines. OTHER FACILITIES The Company also owns or leases various pipelines, fuel storage facilities, office equipment, a thermal outfall structure at Indian Point, and other properties located primarily in New York City and Westchester, Orange, Rockland, Putnam and Dutchess counties in New York State. THE COMPANY MORTGAGE Substantially all the properties and franchises of the Company, other than expressly excepted property, are subject to the liens securing the Company's First and Refunding Mortgage Bonds and the mortgage bonds of acquired companies. As of December 31, 1993, $302.9 million aggregate principal amount of such mortgage bonds remained outstanding, of which $125 million is scheduled to mature in 1994, $175 million in 1996 and the balance by 1998. The Company has not issued mortgage bonds since 1974. - 31 - ITEM 3. LEGAL PROCEEDINGS SUPERFUND For a discussion of claims and possible claims against the Company under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (Superfund) and the estimated liability accrued for certain Superfund claims, see "Environmental Matters and Related Legal Proceedings - Superfund" in Item 1, and "Superfund Claims" in Note F to the financial statements in Item 8. The following is a discussion of the significant proceedings pending under Superfund or similar statutes involving sites for which the Company has been asserted to have a liability. The listing is not exhaustive and additional proceedings may arise in the future. MAXEY FLATS NUCLEAR DISPOSAL SITE. The United States Environmental Protection Agency (EPA) advised the Company by letter, dated November 26, 1986, that it is one of 832 potentially responsible parties (PRPs) under Superfund for the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky. The site is owned by the State of Kentucky and was operated as a disposal facility for low level radioactive waste from 1963 through 1977 by the Nuclear Engineering Corporation (now known as U.S. Ecology Corporation). EPA's letter alleges that various radionuclides and organic chemicals have been released from the site into the environment. In 1987, the Company joined a PRP steering committee that agreed to perform an EPA-approved study of the site. The study has been completed. On September 30, 1991, the EPA published its cleanup program for the Maxey Flats Site. The cleanup program calls for the installation of impervious covers over the waste disposal areas of the site. The Company's share of the cleanup costs is expected to be about $516,000 based on the Company's 0.67 percent share of the total waste at the site plus administrative costs. EASTERN DIVERSIFIED METALS SITE. The EPA advised the Company by letter, dated March 5, 1987, that it is one of 118 PRPs under Superfund for the investigation and cleanup of the Eastern Diversified Metals Site in Hometown, Pennsylvania. Between 1966 and 1977, Diversified Industries used the site for a copper wire salvaging operation which involved the disposal of shredded wire insulation in a waste pile located on the site. The EPA alleges that various metals and organic chemicals have been released from the waste pile into the environment. A preliminary ranking list appended to the EPA's letter indicates that the Company is responsible for less than 0.03 percent of the waste insulation material at the site. An EPA-approved site study has been performed by the site owner and a PRP allegedly responsible for about 77 percent of the waste. However, it is not possible to estimate the cleanup costs at this time because the EPA has not issued a final cleanup program for the site. - 32 - CURCIO SCRAP METAL SITE. The EPA advised the Company, in a letter received on August 11, 1987, that it had documented the release of hazardous substances into the environment at the site of Curcio Scrap Metal, Inc. in Saddle Brook, New Jersey, and that the EPA had information indicating that the Company sent hazardous substances (PCBs) to the site. The Company provided the EPA with records that indicated that the Company sold scrap electric transformers to a metal broker who in turn sold them to the owner of the site. A site study indicated that chemical contamination has occurred on a portion of the site. Elevated concentrations of PCBs and various organic compounds and metals have been detected in the soil and PCBs and organic compounds and metals have also been detected in the shallow groundwater beneath the site. On September 30, 1991, the EPA issued a Unilateral Administrative Order which requires the Company and three other PRPs to commence a soil cleanup of this site pursuant to the EPA's Record of Decision, dated June 28, 1991. This soil cleanup has been completed. The EPA has not yet formulated a cleanup program for the groundwater under and around the Curcio site. The Company's estimate of the cost of the additional groundwater studies is $100,000. The EPA has only designated five PRPs for this site and, as a result, the Company will be expected to pay a major share of the cleanup costs. METAL BANK OF AMERICA SITES. The EPA advised the Company by letter dated October 26, 1987 that it has reason to believe that the Company was a supplier of used transformers to Metal Bank of America Inc.'s recycling sites in Philadelphia during the late 1960s and thereafter. One of the sites has been placed on the EPA's national priority list under Superfund as a result of a leak in a storage tank containing PCBs. The EPA alleges that PCBs have been found in the ground water, soils and in the sediments of the adjoining Delaware River. The Company has provided the EPA with documents which indicate that the Company sold approximately 81 scrap transformers to a broker who, in turn, delivered them to the site. Under a steering committee participation agreement, the Company will be responsible for 1.48% of the expense of a remedial investigation and feasibility study, the scope of which has been negotiated with the EPA. The steering committee members, including the Company, have entered into an EPA administrative consent order to implement the study. Based on the committee's budget for the study, the Company's share of the cost of the study will be about $100,000. - 33 - NARROWSBURG SITE. In 1987, the New York State Attorney General notified the Company that he has evidence that the Company is a PRP under Superfund for hazardous substances that have been released at the Cortese landfill in Narrowsburg, Sullivan County, New York. The Cortese landfill is listed on the EPA's national priorities list. Company records indicate that drums containing non-nuclear waste were shipped from Indian Point to the Cortese landfill for disposal. The Attorney General has commenced an action under Superfund in the United States District Court for the Southern District of New York against the Cortese site owner and operator and SCA Services, an alleged transporter of hazardous substances to the site. On January 17, 1989, SCA Services commenced a third-party action for contribution against the Company and five other parties whose chemical waste was allegedly disposed of at the site. In 1990, SCA served a second amended third-party complaint in which it sued the Company and 27 other third-party defendants for contribution. The Company and SCA Services have reached a settlement of the third-party action under which the Company's sole responsibility will be to pay 6% of the first $25 million of remedial costs at the site. SCA Services has agreed to indemnify the Company for any other remedial costs that it has to pay. CARLSTADT SITE. On August 20, 1990, the Company was served with a third-party complaint in a Superfund cost contribution action for a former waste solvent and oil recycling facility located in Carlstadt, New Jersey. The complaint, which is pending before the United States District Court for the District of New Jersey, alleges that the Company shipped 120,000 gallons of waste oil to this site and that the Company is one of several hundred parties who are responsible under Superfund for the study and cleanup of the facility. The plaintiffs in the action, which include a group of former customers of the facility, have completed a $3 million remedial investigation and feasibility study for the site. They estimate that 7 to 15 million gallons of waste solvents and oil were recycled at the site. Based on this estimate, the Company's share of the cleanup costs is expected to be about one percent. The costs of the cleanup alternatives that were evaluated in the remedial investigation and feasibility study range from $48 million to $321 million. In 1990, the EPA selected an interim remedy, expected to cost about $3 million, to control release from the site while the EPA evaluates and develops a final cleanup remedy. The interim remedy calls for, among other things, the construction of a slurry wall around the site and an infiltration barrier over the site. - 34 - HELEN KRAMER LANDFILL SITE. In September 1991, Orange and Rockland Utilities, Inc. (O&R) was served with third-party complaints in consolidated Superfund cost recovery contribution actions for the Helen Kramer Landfill Site in Mantau, New Jersey. The complaints, which are pending before the United States District Court for the District of New Jersey, allege that, in 1974, Marvin Jonas, Inc. transported hazardous substances for O&R and disposed of those substances in the Helen Kramer Landfill. Preliminary investigation by O&R indicates that waste materials generated during the construction of the Bowline Point generating station were hauled and disposed of by Marvin Jonas, Inc. in 1974. The Company owns a two-thirds interest in Bowline Point. O&R, which operates Bowline Point, owns the remaining one-third interest. Bowline Point liabilities are shared by the Company and O&R in accordance with their respective ownership interests. The EPA has commenced cleanup of this site and the total site cleanup cost is estimated at $150 million. Assuming that all of the Bowline wastes alleged to have been disposed of at the site were so disposed of, they represent about 0.4% of the total volume of waste-in at the site. On this basis, the Company's share of the cleanup cost is estimated at $400,000. GLOBAL LANDFILL SITE. The Company has been designated a PRP under Superfund and the New Jersey Spill Compensation and Control Act (Spill Act) for the study and cleanup of the Global Landfill Site in Old Bridge, New Jersey. This 65-acre municipal and industrial waste landfill is included on the Superfund National Priorities List and is being administered by the New Jersey Department of Environmental Protection and Energy (NJDEPE) pursuant to an agreement between the EPA and the State of New Jersey. The Company provided EPA with records indicating that it had disposed of approximately ten cubic yards of waste asbestos at the site in February 1984. In August 1989, the NJDEPE served the Company with a Spill Act directive that required the Company and 40 other PRPs to fund a $1.5 million remedial investigation and feasibility study for the site. A PRP Group was formed and the Group entered into a settlement agreement and an administrative consent order with NJDEPE that, among other things, required the PRP Group's members to contribute $500,000 towards the cost of the study. The Company's share of the PRP Group's payment to the NJDEPE was $5,000. - 35 - In February 1991, the EPA and the NJDEPE proposed a $30 million interim remedy for the site. This remedy calls for the installation of gas and leachate collection and treatment systems at the landfill and the construction of an impervious cover over the landfill (Phase I). It also calls for further studies to determine the alternatives for addressing groundwater and wetlands contamination in the vicinity of the landfill (Phase II). In March 1991, the NJDEPE served the Company with a second Spill Act Directive that requires the Company and the other members of the PRP Group to pay for the implementation of the Phase I remedy for the site. The PRP Group negotiated a settlement of this directive with the NJDEPE and the Company's share of the cost is estimated at $150,000. CHEMSOL SITE. By letter dated December 20, 1991, the EPA advised the Company that it had documented the release of hazardous substances at the Chemsol Site in Piscataway, New Jersey and that it had reason to believe that the Company sent waste materials to the site during the 1960 to 1965 period. In response to EPA's demand for records, including any relating to Cenco Instruments Corp., the Company submitted to EPA records of payments to Central Scientific Company, a Division of Cenco Instruments Corp. during the 1960-1965 period. The Company is unable at this time to determine either the purpose of the payments to Central Scientific Company or the connection of that company to the site. The EPA has not designated the Company as a PRP and has not yet selected a final cleanup program for the site. However, the EPA has selected an interim remedy, expected to cost about $8 million, for the site groundwater contamination and has ordered several designated PRPs to implement that remedy. ECHO AVENUE SITE. In December 1987, the DEC classified the Company's former Echo Avenue Substation Site in New Rochelle, New York as an "Inactive Hazardous Waste Disposal Site." The basis for this classification was the presence of PCBs in the soil and in the buildings on the site. Although the Company has cleaned up the PCBs on the site, the DEC requires a thorough site survey before it will remove the site from the Inactive Hazardous Waste Disposal Site list. Under a consent order with the DEC a new site survey was done and remedial action taken. The cost to the Company of this additional work was $213,000. The DEC has asked for additional studies. The Company does not know whether any additional cleanup at the site will be required. In January 1992, the owners of Echo Bay Marina filed suit in Federal court alleging that PCBs were being discharged from the Echo Avenue site into Long Island Sound. Plaintiffs are seeking a declaration that the Company is in violation of the Clean Water Act, civil penalties of $25,000 per day for each violation, remediation costs, an injunction against further discharges, legal fees, and compensatory damages of $24 million. Pretrial discovery is continuing. - 36 - C&D RECYCLING SITE. On July 13, 1992, the Company received a letter from EPA stating that it is a PRP with respect to the C&D Recycling site located in Foster Township, Luzerne County, Pennsylvania. In 1979, the Company retained C&D Recycling Company to recover copper and lead from a shipment of 30,560 pounds of scrap electric cable. It appears that the bulk of the scrap cable sent to this site was generated by AT&T Nassau Metals, a subsidiary of AT&T. Information available to the Company indicates that the AT&T subsidiary shipped in excess of five million pounds of scrap cable to this site. The Company has not been asked to contribute to the cost of the remedial investigation and feasibility study or cleanup costs. Thus, the Company is unable to estimate its exposure to liability with respect to this site. The total cleanup cost is estimated at $12.5 million. PELHAM MANOR SITE. Prior to 1968, the Company and its predecessor companies operated a manufactured gas plant (MGP) on a site located in Pelham Manor, Westchester County. Soil and groundwater tests by the current owners and lessees indicate the presence of hazardous substances which are associated with the MGP process. The Company has agreed to participate with the site owners and lessees in further site studies to develop and implement a cleanup plan that will be acceptable to the DEC. ASTORIA SITE. The Federal Resource Conservation and Recovery Act delegates to the states licensing authority for PCB storage. As a condition to renewal by the DEC of the Company's permit to store PCBs at the Company's Astoria generating station, the Company is required to conduct a site investigation and, where necessary, a remediation program. The site investigation is expected to commence in April 1994 and to cost approximately $800,000. The extent and cost of the remediation program will depend on the results of the investigation. - 37 - GRAMERCY PARK On August 19, 1989, a Company steam main exploded in the Gramercy Park area of Manhattan, releasing debris containing asbestos into that area. The Company took responsibility for the asbestos cleanup and most of the cost of that cleanup was covered by the Company's insurance. A Federal Grand Jury in the Southern District of New York issued an indictment on December 16, 1993, charging the Company and two of its retired employees with criminal acts relating to the reporting of the release of asbestos resulting from the steam main explosion. The indictment contains four counts against the Company. The first count alleges a conspiracy to conceal facts relating to the release. The second count alleges a failure to report immediately the known release of asbestos. The third and fourth counts allege false statements to governmental agencies concerning the asbestos release. The Company will vigorously contest these charges, which it believes are without merit. Regardless of the ultimate disposition of the charges, the Company believes that they will not have a material adverse effect on the Company's financial condition or business operations. DEC PROCEEDINGS On June 9, 1992, the Company received notice of two civil administrative proceedings instituted by the DEC staff against the Company. One complaint alleged violations of the Company's permits issued under the State Pollutant Discharge Elimination System (SPDES) relating to the cooling water intake structures at certain of the Company's generating stations. This complaint was settled with the DEC under a consent order signed on December 28, 1992, requiring the Company to pay a civil penalty of $100,000. The other complaint alleged numerous "causes for enforcement action" relating to alleged SPDES violations, discharges of oil and other pollutants at various Company facilities and operation of certain facilities allegedly without required authorization. The acts complained of occurred over a period of years, and had for the most part been reported to the DEC by the Company contemporaneously with their occurrence. In the pending proceeding, the DEC staff requests the DEC to assess a civil penalty of $20 million and to require the Company, among other things, to undertake remedial, restorative and preventative measures, to perform environmental audits at all of its facilities, and to implement a hazardous waste generation and release minimization plan and a "best management practices" plan. Settlement negotiations for this proceeding are ongoing. For additional information about this proceeding, see "DEC Proceeding" in Note F to the financial statements in Item 8. - 38 - ASBESTOS LITIGATION For a discussion of asbestos and suits against the Company involving asbestos, see "Environmental Matters and Related Legal Proceedings - Asbestos" in Item 1, and "Asbestos Claims" in Note F to the financial statements in Item 8. The following is a discussion of the significant suits involving asbestos in which the Company has been named a defendant. The listing is not exhaustive and additional suits may arise in the future. MASS TORT CASES. Numerous suits have been brought in New York State and Federal courts against the Company and many other defendants for death and injuries allegedly caused by exposure to asbestos at various Company premises. Many of these suits have been disposed of without any payment by the Company, or for immaterial amounts. The amounts specified in the remaining suits, including the Moran v. Vacarro suit and the pending United States of America v. Con Edison suit discussed below, total billions of dollars, but the Company believes that these amounts are greatly exaggerated, as were the claims already disposed of. UNITED STATES OF AMERICA, LOCAL 1-2 UTILITY WORKERS' UNION OF AMERICA, AND THOMAS MORAN V. CON EDISON. This suit was commenced on January 7, 1988 by the United States in the United States District Court for the Eastern District of New York. The complaint alleged that on various occasions and at various Company facilities the Company violated the Federal Clean Air Act and regulations issued pursuant to the Act in connection with asbestos removal activities. On May 31, 1988, Local 1-2 of the Utility Workers Union of America (a union representing Company employees) intervened in the action, and, on November 15, 1988, Thomas Moran, an employee, intervened. With the court's approval, the Company and the Federal government have settled this action with the Company paying $219,500. MORAN, ET AL. V. VACARRO, ET AL. On May 9, 1988, the Company was served with a complaint in an action in the New York State Supreme Court, New York County, in which approximately 184 Company employees and their union allege that the employees were exposed to dangerous levels of asbestos as a result of alleged intentional conduct of supervisory employees. Each of the employee plaintiffs seeks $1 million in punitive damages, unspecified additional compensatory damages, and to enjoin the Company from violating EPA regulations and exposing employees to asbestos without first taking certain safety measures. On May 16, 1988, the complaint was amended to add a claim by each employee plaintiff for $1 million in damages for mental distress. In November 1988, the complaint was amended to add four additional employee plaintiffs. On July 9, 1990, the complaint was amended to add the spouses of 131 plaintiffs as additional plaintiffs. Each spouse seeks $1 million for emotional distress and $1 million for punitive damages. - 39 - UNITED STATES OF AMERICA V. CON EDISON. This suit was commenced on March 7, 1994 by the United States in the United States District Court for the Southern District of New York. The complaint alleges that the Company violated hazardous emissions provisions of the Federal Clean Air Act in connection with asbestos removal activities at the Company's Waterside generating station during 1989. The complaint seeks civil penalties of $25,000 per day per violation and injunctive relief. The Company is in the process of reviewing the complaint and preparing its answer which is to be filed with the court in early May 1994. RATE PROCEEDINGS For information concerning proceedings relating to the Company's rates, see "Regulation and Rates" in Item 1. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. - 40- EXECUTIVE OFFICERS OF THE REGISTRANT The names of the executive officers of the Company together with their ages and the positions and offices with the Company held by them as of March 1, 1994, the respective dates they became executive officers and their business experience during the past five years (or since they became executive officers, if earlier) are set forth below. Under the Company's By-laws, officers of the Company are elected to hold office until the next election of Trustees (directors) of the Company and until their respective successors are chosen and qualify, subject to removal at any time by the Company's Board of Trustees. Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an and Date First Became an Executive Officer, Executive Officer If Longer Eugene R. McGrath - 52 9/90 to present - Chairman of Chairman of the Board, the Board, President, Chief President, Chief Executive Executive Officer and Trustee Officer and Trustee; 2/89 to 8/90 - President, Chief 9/1/78 Operating Officer and Trustee 10/87 to 1/89 - Executive Vice President - Operations and Trustee 9/82 to 9/87 - Executive Vice President - Central Operations 3/81 to 8/82 - Senior Vice President - Power Generation 9/78 to 2/81 - Vice President - Power Generation Raymond J. McCann - 59 2/89 to present - Executive Vice Executive Vice President President and Chief Financial and Chief Financial Officer, and Trustee Officer, and Trustee; 10/87 to 1/89 - Executive Vice 5/15/72 President, Finance and Law, and Trustee 8/80 to 9/87 - Executive Vice President - Division Operations 6/77 to 8/80 - Vice President - Manhattan Division 6/76 to 5/77 - Vice President - Accounting and Treasury 3/74 to 5/76 - Controller 5/72 to 3/74 - General Auditor - 41 - Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer J. Michael Evans - 48 9/91 to present - Executive Vice Executive Vice President President - Central Operations - Central Operations; 7/89 to 8/91 - Senior Vice 9/1/91 President and Chief Operating Officer - Kansas City Power and Light (KCP&L) 5/87 to 7/89 - Senior Vice President - System Operations - KCP&L Charles F. Soutar - 57 2/89 to present - Executive Vice Executive Vice President President - Customer Service - Customer Service; 3/85 to 1/89 - Executive Vice 9/1/77 President - Central Services 5/80 to 2/85 - Senior Vice President - Construction, Engineering and Environmental Affairs 9/77 to 4/80 - Vice President - Central Services Thomas J. Galvin - 55 2/93 to present - Senior Vice Senior Vice President President - Central Services - Central Services; 6/89 to 1/93 - Senior Vice 6/1/78 President - Administration 8/86 to 5/89 - Vice President - Employee Relations 3/83 to 7/86 - Vice President - Purchasing 6/78 to 2/83 - General Auditor Carl W. Greene - 58 7/92 to present - Senior Vice Senior Vice President President - Accounting and - Accounting and Treasury; Treasury 6/1/76 6/82 to 6/92 - Vice President and Controller 6/76 to 5/82 - Controller Edward W. Livingston - 59 9/92 to present - Senior Vice Senior Vice President President - Executive - Executive Assistant to Assistant to the Chairman the Chairman; 6/89 to 8/92 - Senior Vice 3/1/79 President - Public Affairs 3/79 to 5/89 - Vice President - Government & Community Relations - 42 - Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an and Date First Became an Executive Officer, Executive Officer If Longer Mary Jane McCartney - 45 10/93 to present - Senior Vice Senior Vice President President - Gas Operations - Gas Operations; 2/93 to 10/93 - Vice President 12/1/90 - Gas Supply 7/92 to 1/93 - Vice President - Gas Business Development 12/90 to 6/92 - Vice President - Queens 2/89 to 11/90 - Assistant Vice President - Environmental Affairs and Fuel Supply 11/80 to 1/89 - Director - Fossil Fuel Supply Horace S. Webb - 53 9/92 to present - Senior Vice Senior Vice President President - Public Affairs - Public Affairs; 1/90 to 8/92 - Vice President 9/1/92 - Communications and Public Affairs, Hoechst Celanese Corp. 9/84 to 1/90 - Vice President - Hill & Knowlton, Inc. T. Bowring Woodbury, II - 56 6/89 to present - Senior Vice Senior Vice President President and General Counsel and General Counsel; 7/87 to 5/89 - Senior Vice 6/1/89 President, General Counsel and Secretary, Commercial Union Insurance Company Archie M. Bankston - 56 6/89 to present - Secretary and Secretary and Associate Associate General Counsel General Counsel; 1/74 to 5/89 - Secretary and 1/7/74 Assistant General Counsel John F. Cioffi - 60 7/92 to present - Treasurer Treasurer; 6/87 to 6/92 - Assistant Vice 7/1/92 President Lawrence F. Travaglia - 55 3/93 to present - General Auditor General Auditor; 10/80 to 2/93 - Assistant 3/1/93 Treasurer - 43 - Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an and Date First Became an Executive Officer, Executive Officer If Longer Robert A. Bell - 60 6/81 to present - Vice President Vice President - Research & Development Research & Development; 6/1/81 Arthur J. Bennett - 58 3/93 to present - Vice President Vice President - Brooklyn Customer Service - Brooklyn Customer; 6/91 to 2/93 - Vice President Service; 3/1/83 - Transportation & Stores 3/83 to 6/91 - Vice President - Bronx Division David G. Bosland - 57 6/91 to present - Vice President Vice President - Staten Island Customer Service - Staten Island 3/83 to 6/91 Vice President Customer Service; - Transportation & Stores 3/1/83 Stephen B. Bram - 51 12/87 to present - Vice President Vice President - Nuclear Power - Nuclear Power; 9/82 to 11/87 - Vice President 8/1/79 - Fossil Power 7/80 to 8/82 - Vice President - Central Substation, Systems Operations and Technical Services 8/79 to 6/80 - Vice President - Central Substation and System Operations Kevin M. Burke - 43 3/93 to present - Vice President Vice President - Corporate Planning - Corporate Planning; 3/90 to 2/93 - Vice President 12/1/87 - Brooklyn Customer Service 12/87 to 2/90 - Vice President - Construction Richard P. Cowie - 47 3/94 to present - Vice President Vice President - Employee Relations - Employee Relations; 2/91 to 2/94 - Director - Central 3/1/94 Customer Service 9/90 to 1/91 - Assistant to the Executive Vice President - Customer Service 9/86 to 8/90 - Director - Credit & Collections - 44 - Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an and Date First Became an Executive Officer, Executive Officer If Longer Robert F. Crane - 57 3/94 to present - Vice President Vice President - Fuel Supply - Fuel Supply; 10/93 to 2/94 - Vice President 12/1/82 - Gas Supply 2/93 to 10/93 - Vice President - Gas Business Development 4/91 to 1/93 - Vice President - Gas Supply 12/84 to 3/91 - Vice President - Manhattan Division 12/82 to 11/84 - Vice President - Queens Division George J. Delaney - 58 12/78 to present - Vice President Vice President - Westchester Customer Service - Westchester 9/74 to 11/78 - Vice President Customer Service; - Bronx Division 5/28/74 5/74 to 8/74 - Vice President - Staten Island Division Robert W. Donohue, Jr. - 51 2/94 to present - Vice President Vice President - Queens Customer Service - Queens Customer Service; 3/90 to 1/94 - Vice President 3/1/90 - Construction 12/84 to 2/90 - Assistant Vice President - Electrical Distribution Charles J. Durkin, Jr. - 50 12/93 to present - Vice President Vice President - Fossil Power - Fossil Power; 1/88 to 12/93 - Vice President 9/1/82 - Engineering 9/82 to 12/87 - Vice President - System and Transmission Operations Jacob Feinstein - 50 4/91 to present - Vice President Vice President - System & Transmission - System & Transmission Operations Operations; 4/1/91 12/88 to 3/91 - Plant Manager - 45 - Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an and Date First Became an Executive Officer, Executive Officer If Longer Joan S. Freilich - 52 7/92 to present - Vice President Vice President and and Controller Controller; 12/1/90 12/90 to 6/92 - Vice President - Corporate Planning 12/89 to 11/90 - Assistant Vice President - Corporate Planning 2/89 to 11/89 - Executive Assistant to President David F. Gedris - 45 2/94 to present - Vice President Vice President - Maintenance and Construction - Maintenance and 7/92 to 1/94 - Assistant Vice Construction; President - Power Generation 2/1/94 Maintenance 3/90 to 6/92 - Assistant Vice President - Steam Operations 11/89 to 2/90 - Project Manager - Steam Operations 7/85 to 10/89 - Plant Manager Garrett W. Groscup - 53 2/94 to present - Vice President Vice President - Energy Services - Energy Services; 4/91 to 1/94 - Vice President 12/1/82 - Manhattan Customer Service 1/88 to 3/91 - Vice President - System & Transmission Operations 12/82 to 12/87 - Vice President - Engineering William A. Harkins - 48 2/89 to present - Vice President Vice President - Planning and Inter-Utility - Planning and Inter- Affairs Utility Affairs; 9/86 to 1/89 - Assistant Vice 2/1/89 President - Environmental Affairs and Fuel Supply Paul H. Kinkel - 49 12/93 to present - Vice President Vice President - Engineering - Engineering; 12/87 to 12/93 - Vice President 5/24/83 - Fossil Power 5/83 to 11/87 - Vice President - Construction - 46 - Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an and Date First Became an Executive Officer, Executive Officer If Longer Laurence V. Kleinman - 51 9/86 to present - Vice President Vice President - Corporate Communications and - Corporate Communications Public Information and Public Information; 9/1/86 Thomas A. McGovern - 60 6/89 to present - Vice President Vice President - Services - Services; 6/1/89 9/82 to 5/89 - Assistant Vice President - Services John A. Nutant - 58 2/94 to present - Vice President Vice President - Manhattan Customer Service - Manhattan 7/92 to 1/94 - Vice President Customer Service; - Queens Customer Service 5/27/80 9/86 - 6/92 - Vice President - Purchasing 7/80 to 8/86 - Vice President - Environmental Affairs 5/80 to 6/80 - Vice President James P. O'Brien - 46 3/94 to present - Vice President Vice President - Systems and Information - Systems and Information Processing Processing; 3/1/94 6/89 to 2/94 - Assistant Vice President - Employee Relations 5/87 to 5/89 - Director - Personnel Operations Edwin W. Scott - 55 6/89 to present - Vice President Vice President and Deputy and Deputy General Counsel General Counsel; 10/85 to 5/89 - Assistant Vice 6/1/89 President and Associate General Counsel Minto L. Soares - 57 6/91 to present - Vice President Vice President - Bronx Customer Service - Bronx Customer Service; 11/88 to 5/91 - Plant Manager 6/1/91 Alfred R. Wassler - 49 3/94 to present - Vice President Vice President - Purchasing, Transportation - Purchasing, Trans- and Stores portation and Stores; 7/92 to 2/94 - Vice President 8/15/80 - Purchasing 8/80 to 6/92 - Treasurer - 47 - PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's Common Stock ($2.50 par value) is the only class of common equity of the Company. The Common Stock is traded on the New York, Midwest and Pacific Stock Exchanges. MARKET PRICE RANGE IN CONSOLIDATED REPORTING SYSTEM AND DIVIDENDS PAID ON COMMON STOCK On January 25, 1994, the Board of Trustees of the Company declared a quarterly dividend of 50 cents per share of Common Stock payable on March 15, 1994 to holders of record on February 16, 1994. ITEM 6. SELECTED FINANCIAL DATA
1993 1992 ------------------------------ ---------------------------- Dividends Dividends High Low Paid High Low Paid - ---------------------------------------------------------------------------------------------- 1st Quarter $35-7/8 $31-1/2 $.48-1/2 $28-5/8 $25 $.47-1/2 2nd Quarter 37-3/8 32-1/2 .48-1/2 28-3/4 26-1/4 .47-1/2 3rd Quarter 37-3/4 35-1/8 .48-1/2 31-5/8 27-3/4 .47-1/2 4th Quarter 36-3/8 30-1/4 .48-1/2 32-7/8 30-1/4 .47-1/2 As of January 31, 1994 there were 166,011 holders of record of common stock. ===============================================================================================
=============================================================================================== Year Ended December 31 (Millions of Dollars) 1993 1992 1991 1990 1989 - ----------------------------------------------------------------------------------------------- Operating revenues $ 6,265.4 $ 5,932.9 $ 5,873.1 $ 5,738.9 $ 5,550.6 Fuel and purchased power and gas purchased for resale 1,707.5 1,562.2 1,663.9 1,689.2 1,632.5 Operating income 951.1 880.4 813.1 800.8 783.7 Net income for common stock 622.9 567.7 530.1 534.4 568.7 Total assets 13,483.5* 11,596.1 11,107.9 10,685.6 10,349.5 Long-term obligations Long-term debt 3,643.9 3,493.6 3,364.8 3,312.7 3,072.2 Capitalized leases 50.4 52.9 55.5 58.0 77.7 Preferred stock subject to mandatory redemption 100.0 100.0 41.3 43.5 45.8 Common shareholders' equity 5,068.5 4,886.9 4,608.3 4,502.1 4,382.4 - ----------------------------------------------------------------------------------------------- Per common share: Net income $2.66 $2.46 $2.32 $2.34 $2.49 Cash dividends $1.94 $1.90 $1.86 $1.82 $1.72 - ----------------------------------------------------------------------------------------------- Average common shares outstanding (millions) 234.0 231.1 228.3 228.2 228.1 =============================================================================================== *Includes $1,376.8 million of Regulatory Assets attributable to the adoption of SFAS 109 in 1993. A Deferred Tax Liability of equal amount was established in 1993. See Note A to the financial statements. - 48 - ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES SOURCES OF LIQUIDITY. Cash and temporary cash investments were $36.8 million at December 31, 1993 compared with $282.5 million at December 31, 1992 and $317.9 million at December 31, 1991. The balance at December 31, 1991 included $196.3 million held by Gramercy Assets Corporation (Gramercy Assets), the Company's wholly-owned investment subsidiary, which was liquidated in 1992. The Company's cash balances reflect the timing and amounts of external financings. In April 1993 the Company issued $101 million of 35-year tax-exempt debt through the New York State Energy Research and Development Authority (NYSERDA) for a portion of the Company's 1993 capital requirements. The balance of 1993 capital requirements was met from internally generated funds and a portion of the proceeds of the 1993 debenture issues discussed below, and through the issuance of 373,227 shares of common stock in December 1993 for $11.9 million pursuant to the Company's dividend reinvestment plan. The Company amended the plan in 1993 to permit, at the option of the Company, the sale of new shares or the purchase in the market of outstanding shares. In 1992 the Company issued $200 million of 35-year tax- exempt debt and $100 million of 35-year taxable debentures. In 1992 the Company also issued 5,550,000 shares of common stock for $156.8 million. In 1991 the Company issued $128 million of 35- year tax-exempt debt and $175 million of 35-year taxable debentures. Declining interest rates during 1992 and 1993 provided the Company an opportunity to reduce costs by redeeming outstanding securities in advance of maturity dates and replacing them with new securities bearing lower interest or dividend rates. The Company retired all or part of 16 series of securities totaling more than $1.7 billion, replacing them with 16 new series of debt and preferred stock. These refundings produced aggregate first- year savings in interest and preferred dividends of about $22 million, with continued savings in subsequent years. At various times during 1993 the Company issued $750 million of intermediate-term debentures to refund in advance of maturity $670 million of mortgage bonds and for 1993 capital requirements. Intermediate-term debentures were issued so as to match the maturities of the refunded issues. In June 1993 the Company made a tender offer to purchase any or all of its $200 million 9.70 percent Series 1990 A debentures and its $175 million 9-3/8 percent Series 1991 A debentures. Debenture holders tendered, and the Company purchased and cancelled, $172.6 million of the 9.70 percent debentures and $79.7 million of the 9-3/8 percent debentures for $295.6 million, including premiums, but excluding accrued interest. In June 1993 the Company issued $380 million of 30-year 7-1/2 percent debentures to fund these purchases and for 1993 capital requirements. - 49 - In September 1993 the Company made a tender offer to purchase any or all of the $256 million 9 percent Series 1985 A and the $49.145 million 9-1/4 percent Series 1987 B tax-exempt bonds issued through NYSERDA. Bondholders tendered, and the Company purchased and cancelled, $127,715,000 of the Series 1985 A bonds and $19,760,000 of the Series 1987 B bonds for $172.5 million, including premiums, but excluding accrued interest. In October 1993 the Company issued through NYSERDA $127,715,000 of 5-1/4 percent tax-exempt refunding bonds to refund a like amount of tendered 1985 A bonds, and $19,760,000 of 5-3/8 percent tax- exempt refunding bonds to refund a like amount of tendered 1987 B bonds. The Company paid the difference between the net proceeds of these issues and the price of the purchased bonds from internally generated funds. In November 1993 the Company retired the remaining $20 million of the 8-1/8 percent Series LL mortgage bonds through a combination of mandatory and optional sinking fund and redemption calls. In 1992 the Company refunded in advance of maturity $575 million of mortgage bonds with a like amount of intermediate-term debentures. In 1992 the Company issued 500,000 shares each of $100 par value sinking fund Cumulative Preferred Stock, 7.20 percent Series I and 6-1/8 percent Series J, primarily to refund the outstanding shares of 8.30 percent Series G and 8-1/8 percent Series H Cumulative Preferred Stock. The Company's cash requirements are subject to substantial fluctuations during the year due to seasonal variations in cash flow, and peak in January and July of each year when the semi- annual payments of New York City property taxes are due. At such times, in 1993, 1992 and 1991 the Company borrowed from banks for short periods. For 1994 the Company has arranged for bank credit lines amounting to $150 million. Borrowings thereunder would bear interest at prevailing market rates. The Company has obtained authorization from the Federal Energy Regulatory Commission to make short-term borrowings of up to $300 million from time to time through 1995. Customer accounts receivable, less allowance for uncollectible accounts, amounted to $459.3 million, $424.3 million and $390.0 million at December 31, 1993, 1992 and 1991, respectively. In terms of equivalent days of revenue outstanding, these amounts represented 27.6, 26.7 and 26.6 days, respectively. Regulatory accounts receivable, amounting to $97.1 million at December 31, 1993 and $167.9 million at December 31, 1992, include accruals under the three-year electric rate agreement effective April 1, 1992 for differences in electric sales revenues from the levels forecast pursuant to the rate agreement (the "ERAM" accrual), for incentives and "lost revenues" related to the Company's Enlightened Energy program, for incentives related to customer service activities and for savings achieved in fuel and purchased power costs below target levels. Regulatory accounts receivable are further described in Note A to the financial statements in this report. - 50 - The following is a summary of the balances and activity in regulatory accounts receivable in 1993: Balance Balance Dec. 31, 1993 1993 Dec. 31, (Millions of Dollars) 1992 Accruals Billings 1993 ERAM $ 130.1 $ 10.9 $ (104.8) $ 36.2 Incentives Enlightened Energy program 24.9 36.2 (18.7) 42.4 Customer service 4.5 6.5 (4.6) 6.4 Fuel and purchased power 7.1 26.9 (24.2) 9.8 Lost revenues relating to Enlightened Energy program 1.3 1.9 (.9) 2.3 Total $ 167.9 $ 82.4 $ (153.2) $ 97.1 The balance in regulatory accounts receivable at December 31, 1993 will be billed to customers during 1994 and 1995. The incentives are discussed below under "1992 Electric Rate Settlement Agreement." Deferred charges for Enlightened Energy program costs amounted to $140.1 million at December 31, 1993 and $80.8 million at December 31, 1992. Under the 1990 and 1992 electric rate agreements discussed below, the Company was allowed to offset a portion of such deferred charges (as well as incentives and "lost revenues") with deferred property tax savings and various other deferred credits due customers as of March 31, 1992. The balance at December 31, 1993 reflects the ongoing Enlightened Energy program costs and the effects of the rate recovery provisions discussed below under "1992 Electric Rate Settlement Agreement." In 1993 unamortized debt expense increased $89.9 million, principally reflecting premiums and expenses related to refundings in advance of maturity discussed above. These premiums and expenses will be amortized and recovered in rates, generally over the lives of the refunded issues. The Company's earnings include an allowance for funds used during construction which, as a percent of net income for common stock, was 1.7 percent in 1993, 2.4 percent in 1992 and 2.7 percent in 1991. Interest coverage on the SEC book basis was 4.19, 3.93 and 3.73 times for 1993, 1992 and 1991, respectively. The improvement in interest coverage in 1993 and 1992 was due to the debt refundings and increased earnings. The Company's interest coverage continues to be high compared with the electric utility industry generally. The Company's senior debt (first mortgage bonds) is rated Aa2 by Moody's Investors Service (Moody's), AA- by Standard & Poor's (S&P) and AA- by Duff and Phelps. Moody's and S&P revised their ratings in February 1994 from Aa1 and AA, respectively. A major factor was the Company's obligations under contracts with independent power producers (IPPs) (see "Electric Generating Capacity" below). - 51 - Cash flows from operating activities, before and after dividends, for years 1991 through 1993 were as follows: (Millions of Dollars) 1993 1992 1991 Net cash flows from operating activities $1,025 $962 $945 Less: Dividends on common and preferred stock 490 475 461 Net after dividends $ 535 $487 $484 Net cash flows in 1993 were favorably affected by ERAM billings of $104.8 million. ERAM billings in 1994 are expected to be substantially lower. CAPITAL REQUIREMENTS. The following table compares the Company's capital requirements for 1991 through 1993 and estimated amounts for 1994 and 1995: (Millions of Dollars) 1995 1994 1993 1992 1991 Construction expenditures $ 743 $ 770 $ 789 $ 795 $775 Enlightened Energy program costs less recoveries* 6 64 59 21 44 Power contract termination costs - net** (13) (36) 68 - - Nuclear decommissioning trust*** 12 12 19 7 7 Nuclear fuel 13 53 14 35 9 Sub-Total 761 863 949 858 835 Retirement of long- term debt and preferred stock**** 11 134 178 257 124 Total $ 772 $ 997 $1,127 $1,115 $959 * See discussion below of electric rate agreements. ** Assumes recovery of these costs as proposed by the Company. See 1992 Electric Rate Settlement Agreement-Rate Increases, below. (ALSO SEE REGULATION AND RATES - ELECTRIC, GAS AND STEAM RATES" in ITEM 1.) *** See Note A to the financial statements for discussion of nuclear decommissioning costs. ****Does not include refundings in advance of maturity in 1992 and 1993 discussed above. For details of securities maturing after 1995, see Note B to the financial statements. The Company expects to finance its capital requirements for 1994 and 1995 from internally generated funds and external financings of about $600 million, most of which would be debt issues in 1994. This includes a $150 million debt financing which was deferred from December 1993 to February 1994. In 1994 and 1995 the Company also expects, from time to time, to make short-term borrowings. - 52 - ELECTRIC GENERATING CAPACITY. Over the past two years, electric peak load growth in the Company's service area has declined to about one-half of one percent per year, attributable to the effects of the continuing recession in the Northeast and the success of the Company's Enlightened Energy program. This program was first introduced in 1990 to help our customers purchase and install energy-efficient equipment and to encourage the efficient use of energy resources. The PSC has approved the Company's program for 1994. The program for future years is being modified so as to obtain the same benefits at lower program costs based on the experience to date. In compliance with federal and state regulatory policies that encouraged the development of IPPs and required utilities to contract with IPPs meeting certain conditions, the Company entered into contracts for the supply of approximately 2,700 megawatts (MW) of capacity from IPP facilities scheduled to come into service in the 1990s. Included in this total are contracts for 645 MW of capacity from the Cogen Technologies plant in Linden, N.J. which began commercial operation in May 1992, and 740 MW of capacity from Sithe Energies' Independence Power Plant in Oswego, N.Y., which is expected to be in service in late 1994. Because of the decline in load growth rates and changing conditions in the marketplace, the need for the IPP contracts has been re-evaluated. More than enough generating capacity is projected for the Northeast and the market price of power has decreased significantly. The Company has entered into agreements for the termination of several IPP contracts involving approximately 440 MW for $121.7 million (exclusive of interest) to be paid over a period of several years. The Company's electric customers will save substantially more than this amount based on current estimates of future market prices for power. In 1993 the Company retired 384 MW of generating capacity in order to lower costs. The Company has given notice of termination to the New York Power Authority (NYPA) effective April 1, 1994 of a contract for the purchase of approximately 200 MW of power from NYPA's James A. Fitzpatrick nuclear facility, because the contract was uneconomic relative to power available in the electric marketplace. The Company is also examining the economics of other contracts it has with NYPA for the purchase of firm power. Based on current projections, the Company does not expect to add any capacity resources to its system during the next twenty years. COMPETITION. Recent regulatory changes affecting the gas industry now permit large retail customers to contract for gas directly with suppliers and interstate pipelines, paying the local gas utility a delivery charge for transporting the customer's gas from the pipeline delivery point to the customer's premises. In the electricity industry, the Energy Policy Act of 1992 permits unregulated non-utility generating companies to sell power and energy at wholesale in competition with regulated utilities, and to require utilities to provide access, for reasonable charges, to the utilities' electric transmission systems for purposes of making wholesale deliveries. However, neither the Act nor New York State regulations require utilities to deliver their competitors' power and energy directly to electricity consumers, referred to as "retail wheeling." Depending on the future course of developments in this area, the Company's market share and profit margins could become subject to competitive pressures in addition to traditional regulatory constraints. - 53 - The Company's strategy for dealing with these emerging competitive issues includes ongoing cost reduction, increasing productivity, seeking growth opportunities and strengthening customer relations by providing value-added services. Another major element of the strategy is seeking from government and regulators a "level playing field" on which the Company will compete without unfair burdens of regulation or taxation. 1990 ELECTRIC RATE SETTLEMENT AGREEMENT. In 1990 the Company entered into an agreement which continued the Company's base electric rates at their existing level from April 1, 1990 through March 31, 1992. The agreement directed the Company to refund to customers $43.3 million, plus interest, relating to property tax savings set aside in prior periods and to apply $37 million of excess earnings in the final year of a previous agreement, which had been set aside by an accounting provision, to offset a like amount of demand side management program costs deferred from prior periods. In the first rate year of the agreement, the twelve months ended March 31, 1991, $15 million of previously deferred costs for the Enlightened Energy program were amortized as a charge against income. During the second rate year, the twelve months ended March 31, 1992, the Company billed a surcharge of approximately one mill per kilowatt-hour to its electric customers, to recover approximately $40 million of the costs of the Enlightened Energy program. The agreement provided for sharing between customers and shareholders of any excess in earnings above an 11.75 percent return on equity (which computation was to assume a common equity ratio of 50 percent). For the two-year period ended March 31, 1992, the Company's average rate of return on electric common equity was below the 11.75 percent threshold. 1992 ELECTRIC RATE SETTLEMENT AGREEMENT. On April 1, 1992 the PSC approved an electric rate agreement covering the three-year period April 1, 1992 through March 31, 1995. The principal features of the agreement and subsequent developments are as follows: Rate Increases. Annual electric rates were increased by $250.5 million (5.0 percent) in April 1992 for the first rate year ending March 31, 1993 and were increased by $251.2 million (5.0 percent) in April 1993 for the second rate year ending March 31, 1994. The increase for the second rate year included $138.4 million for recovery of accrued ERAM amounts. On February 10, 1994, the Company submitted to the PSC its estimate of a $102.8 million (2.0 percent) increase in electric rates to become effective April 1, l994, the third year of the 1992 electric agreement.* The requested increase reflects primarily payments for capacity to be purchased from IPPs, the recovery of costs associated with the termination of IPP contracts, capital expenditures for infrastructure improvements and the recovery of Enlightened Energy program costs, offset in part by lower property taxes and a substantial decline in ERAM billings (see discussion of regulatory accounts receivable above, discussion of ERAM below, and Note A to the financial statements). Rate of Return and Equity Ratio. The agreement provides a rate of return on common equity of 11.50 percent for the first rate year and 11.60 percent for the second and third rate years, based on a common equity ratio of 52 percent. In order to settle disputed items, including alleged excess earnings in prior years, the Company's revenue allowance was reduced in each of the three years by $35 million. ______________ * In March 1994, the PSC approved a $55 million increase. See "Regulation and Rates - Electric, Gas and Steam Rates" in Item 1. - 54 - Earnings Sharing. Earnings above an 11.75 percent return on common equity in the first year, and above 11.85 percent in the second or third year will be shared with customers. One-half will be retained by the Company for shareholders. The other half will be applied first to make up any shortfall below the sharing threshold in the other rate years and the balance deferred to be applied for future benefit of customers. For purposes of this calculation, earnings levels will exclude incentive awards and labor productivity in excess of amounts reflected in rates. For the first rate year, the twelve months ended March 31, 1993, the Company's rate of return on electric common equity, excluding incentives, was below the 11.75 percent threshold for sharing with customers. Incentive Provisions. The rate agreement includes provisions which permit the Company to earn additional amounts (not subject to the earnings sharing provision) by attaining certain objectives for the Company's Enlightened Energy program, customer service and fuel costs. There are also penalties for failing to achieve minimum objectives. For calendar years 1993 and 1992, the Company earned $36.2 million and $28.8 million, respectively, before federal income tax, for the Enlightened Energy incentive. For calendar year 1994 the Company expects to earn a substantial Enlightened Energy incentive. For customer service performance, as measured against agreed-upon objective criteria, the Company can earn an incentive or penalty of up to 10 basis points for each rate year. For calendar years 1993 and 1992, the Company earned $6.5 million and $4.5 million, respectively, before federal income tax, for customer service performance. Partial Pass-Through Fuel Adjustment Clause. A partial pass- through fuel adjustment clause (PPFAC) was implemented with monthly targets for fuel and purchased power costs. The Company retains for stockholders 30 percent of any savings in actual costs below the target amount, but must bear 30 percent of any excess of actual costs over the target. For each rate year of the agreement there is a $30 million cap, before federal income tax, on the maximum incentives or penalties under the PPFAC, with a "sub-cap" (within the $30 million cap) of $10 million for generation from the Company's Indian Point 2 nuclear unit. For calendar years 1993 and 1992, the Company earned $26.9 million and $24.8 million, respectively, before federal income tax. These amounts are billed to customers on a monthly basis through the fuel adjustment clause. Enlightened Energy Program Costs and Incentive Recovery. The costs for the Enlightened Energy program for each rate year of the agreement will generally be recovered over a five-year period. Unrecovered balances will earn an approved rate of return. The incentive for Enlightened Energy will be recovered in the rate year following the calendar year in which it is earned. As part of the agreement, Enlightened Energy program costs, incentives and associated lost revenues deferred as of March 31, 1992 of approximately $98 million were set off against an equal amount of property tax reductions and other deferred credits that had been previously deferred for the future benefit of customers. Effective April 1, 1992, lost revenues associated with the Enlightened Energy program are reflected in the ERAM. - 55 - Electric Revenue Adjustment Mechanism. The settlement included a significant new rate-making concept known as the ERAM. The purpose of the ERAM is to eliminate the linkage between customers' energy consumption and Company profits. Under the ERAM the Company's rates are based on annual forecasts of electric sales and sales revenues with return to or recovery from customers of any overages or deficiencies from the forecast for the prior rate year. Implementation of the ERAM removes from Company earnings all variations in electric sales from forecasts, including the effects of year-to-year weather variations and the results of changes in economic conditions. In 1993 the Company accrued $10.9 million under the ERAM compared with $130.1 million under the ERAM in 1992. Other Changes. The agreement does not permit further changes in the Company's base electric rates during the settlement period. However, as in previous agreements, there are limited exceptions for the protection of both the Company and customers. GAS AND STEAM RATE INCREASES. In October 1991 the PSC granted the Company permission to increase its firm gas and steam base rates by $21.4 million (3.1 percent) and $17.6 million (5.0 percent), respectively. The increases were premised upon an allowed equity return of 11.3 percent and a common equity ratio of 50 percent of total capitalization. In October 1992 the PSC approved two-year gas and steam rate settlements which included annual increases for the first rate year in firm gas and steam rates of $12.3 million (1.9 percent) and $11.8 million (3.6 percent), respectively. In September 1993 the PSC granted the Company permission to increase its firm gas rates for the second rate year by $21.6 million (2.8 percent). In lieu of a steam rate increase of $2.1 million for the second rate year the PSC authorized the Company to retain certain tax refunds being held by the Company for return to steam customers. The gas and steam rate decisions are premised upon an allowed equity return of 11.6 percent and a common equity ratio of 52 percent of total capitalization. Earnings above an 11.95 percent return are to be shared equally with customers. For the first rate year, the twelve months ended September 30, 1993, the Company's rate of return on gas common equity was below the 11.95 percent threshold for sharing with customers. The Company's rate of return on steam common equity for the first rate year was above the sharing threshold, and as a result, the Company recorded a provision for refund to steam customers of $1.7 million in 1993. In November 1993 the Company filed for increases in gas and steam rates amounting to $19.1 million (2.3 percent) and $14.6 million (4.4 percent), respectively. The rate increases, which if approved would take effect October 1, 1994, are premised upon an 11.6 percent return on common equity and a common equity ratio of 52 percent. URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. Under the Energy Policy Act of 1992, the Department of Energy (DOE) is to collect a special annual assessment, for a period of 15 years, from utilities that have used nuclear fuel. According to the DOE, the 1993 assessment attributable to Indian Point nuclear units 1 and 2 is approximately $3.3 million, with similar amounts due annually thereafter. The annual amount,including the 1993 amount, is subject to review and future amounts are subject to adjustment for inflation. The Federal Energy Regulatory Commission has issued accounting guidelines requiring recognition of the liability and a corresponding deferred charge for the estimated total amount of the assessment. In 1993 the Company paid the first year assessment and recorded a liability of $46.1 million for future amounts, of which $39.5 million is classified as non-current. The Company is recovering these costs through its electric fuel adjustment clause. - 56 - GAS TAKE-OR-PAY SETTLEMENT. In September 1993 the PSC approved a settlement agreement for the recovery of deferred gas take-or-pay costs, which at December 31, 1993 amounted to $35.0 million, including interest. Commencing in October 1993, deferred costs associated with the electric and steam departments are being billed to customers over a two-year period and the costs associated with the gas department are being billed to customers over a four-year period. As settlement of the PSC's contention that the Company's stockholders should bear some share of these costs, the Company will not accrue additional interest on the unamortized deferred balances during the periods of recovery. CLEAN AIR ACT AMENDMENTS. The Clean Air Act amendments of 1990 impose limits on sulfur dioxide emissions from electric generating units. Because the Company uses very low sulfur fuel oil and natural gas as boiler fuels, the sulfur dioxide emission limits should not affect the Company's operations. However, the Company will incur increased capital and operating costs to meet the nitrogen oxide emissions limits set by the New York State Department of Environmental Conservation under the "Reasonably Available Control Technology" (RACT) provisions of the Clean Air Act. The cost of compliance with Phase I limitations which take effect in 1995 is estimated at $23 million including the cost of the installation of continuous emission monitors. The State may further reduce the nitrogen oxide emissions limits under Phase II of the RACT program which is expected to take effect in 1999. The Phase II limitations could require the installation of flue gas controls at generating units which could cost approximately $400 million. NEW FINANCIAL ACCOUNTING STANDARDS. In 1993 the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" and SFAS 109, "Accounting for Income Taxes." See Notes A, E and G to the financial statements. SUPERFUND AND ASBESTOS CLAIMS AND OTHER CONTINGENCIES. Reference is made to Note F to the financial statements for information concerning potential liabilities of the Company arising from the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("Superfund"), from claims relating to alleged exposure to asbestos, and from certain other contingencies to which the Company is subject. IMPACT OF INFLATION. In an inflationary period the purchasing power of the dollar declines. The historical cost amounts reported in traditional financial statements represent dollars of varying purchasing power because such financial statements combine dollars spent at various times in the past with dollars spent currently. Although the rate of inflation has eased greatly from its peak levels, the Company is still affected by the decline in the purchasing power of the dollar caused by even modest inflation. The Company cannot readily increase its prices to keep pace with inflation. The regulatory process introduces a time lag during which increased operating expenses are typically not fully recovered. Moreover, regulation permits the Company to recover through depreciation only the historical cost of its plant assets even though in an inflationary economy the cost to replace the assets upon their retirement will substantially exceed historical cost. Thus, the Company experiences losses on its property equivalent to the effect of inflation. These losses are, however, partially offset by the fact that repayment of the Company's long-term debt is made in dollars of lesser value than the dollars originally borrowed. - 57 - RESULTS OF OPERATIONS Earnings per share were $2.66 in 1993, $2.46 in 1992 and $2.32 in 1991. The average number of common shares outstanding for 1993, 1992 and 1991 was 234.0 million, 231.1 million and 228.3 million, respectively. Earnings for 1993 and 1992 reflect electric, gas and steam rate increases and incentives earned under the provisions of the 1992 electric rate settlement agreement. For year 1992, earnings were offset, in part, by lower investment income principally as a result of the liquidation of Gramercy Assets and generally lower interest rates. OPERATING REVENUES AND FUEL COSTS. Operating revenues in 1993 and 1992 increased from the prior year by $332.5 million and by $59.8 million, respectively. The principal increases and decreases in revenue were: (Millions of Dollars) Increase (Decrease) 1993 over 1992 1992 over 1991 Electric, gas and steam rate changes $ 238.2 $ 209.3 Fuel billings 113.4 (225.7) Sales volume changes Electric-Con Edison direct customers and delivery service for NYPA and municipal agencies 62.6 (77.4) Gas 11.2 80.2 Steam (1.6) 18.9 Weather normalization-Gas 7.9 (25.7) ERAM (119.2) 130.1 Sales to other electric utilities .9 (1.9) Other 19.1 (48.0) Total $ 332.5 $ 59.8 Electric rates were increased by $250.5 million in April 1992 and by $251.2 million in April 1993. Gas rates were increased by $21.6 million and $12.3 million in October 1993 and in October 1992, respectively, and steam rates were increased by $11.8 million in October 1992. The increase in fuel billings in 1993 reflects an increase in the unit cost of fuel used to produce electricity and increased electric sales due to weather variations. The decrease in fuel billings in 1992 reflects a decrease in the unit cost of fuel used to produce electricity and steam and reduced sales due to weather variations. Fuel costs in 1993 and 1992 were also affected by the availability of lower-cost nuclear generation from the Company's Indian Point 2 unit. The cost of gas per therm was 11.5 percent higher in 1993 than in 1992. Electricity sales volume in the Company's service territory increased 3.3 percent in 1993 and decreased 2.7 percent in 1992. Gas sales volume to firm customers increased 0.6 percent in 1993 and 12.0 percent in 1992. Transportation of customer-owned gas decreased 17.9 percent in 1993 and 2.9 percent in 1992, primarily due to a reduction in the volume of gas transported for NYPA's use as boiler fuel at its Poletti unit. Steam sales volume was unchanged in 1993 and increased 3.0 percent in 1992. - 58 - The Company's electricity, gas and steam sales vary seasonally in response to weather. Electric peak load occurs in the summer, while gas and steam sales peak in the winter. After adjusting for variations, principally weather, in each period, electricity sales volume increased 1.0 percent in 1993 and decreased 0.3 percent in 1992. Similarly adjusted, gas sales volume to firm customers increased 3.9 percent in 1993 and 1.8 percent in 1992, and steam sales volume decreased 0.1 percent in 1993 and 1.2 percent in 1992. Weather-adjusted sales represent the Company's estimate of the sales that would have been made if historical average weather conditions had prevailed. OTHER OPERATIONS AND MAINTENANCE EXPENSES. Other operations and maintenance expenses increased 5.4 percent and 4.3 percent in 1993 and 1992, respectively. For 1993 the increase reflects higher production expenses due to the 1993 refueling and maintenance outage of the Indian Point 2 nuclear unit, higher electric and gas distribution expenses, the amortization of previously deferred costs associated with the Company's Enlightened Energy program, in accordance with the electric rate agreements, and higher labor costs. The increase in 1992 reflects the amortization of previously deferred costs associated with the Company's Enlightened Energy program, increased electric and gas distribution expenses and higher labor costs. These were offset in part by lower production expenses because there was a refueling and maintenance outage of the Indian Point 2 nuclear unit in the 1991 period but none in 1992. TAXES OTHER THAN FEDERAL INCOME TAX. At $1.2 billion, taxes other than federal income tax remain the Company's largest operating expense after fuel and purchased power. The principal components and variations in operating taxes were: (Millions of Dollars) Increase (Decrease) 1993 1993 1992 Amount Over 1992 Over 1991 Property taxes $ 576.2 $(68.3) $(65.3) State and local taxes on revenues 468.8 26.9 30.7 Payroll taxes 58.0 1.8 2.7 Other taxes 56.3 (.7) 3.6 Total $1,159.3* $(40.3) $(28.3) *Including sales taxes on customers' bills, total taxes other than federal income taxes billed to customers in 1993 were $1,451.5 million. New York City property taxes for the fiscal year 1993- 1994 will be approximately $76 million less than for the fiscal year ended June 30, 1993. The reduction in property taxes reflects a decrease in the share of total New York City property taxes borne by the Company. Under the terms of the electric rate agreement the difference between property taxes included in electric rates and actual electric property taxes is being deferred for future credit to customers. Gas and steam rates which are currently in effect reflect this reduced level of property taxes. The increase in state and local taxes on revenues in 1993 and 1992 was due principally to increased revenues. The Company bills its customers for all revenue taxes and remits the amounts collected to the municipalities and the state. OTHER INCOME. Other income decreased $9.7 million in 1993 and $28.3 million in 1992. For 1993 the decrease reflects a lower level of temporary cash investments and lower interest rates and for 1992 the decrease reflects the liquidation of Gramercy Assets and lower interest rates. - 59 - INTEREST CHARGES. Interest on long-term debt increased $7.3 million in 1993 and $3.1 million in 1992 principally as a result of the issuance of new debt offset to a large extent by the effect of debt refundings. FEDERAL INCOME TAX. Federal income tax increased $44.5 million in 1993 and $29.4 million in 1992 reflecting the changes each year in income before tax and in tax deductions. The effect of the increase in the corporate income tax rate from 34 percent to 35 percent effective January 1, 1993 has been deferred in accordance with the rate agreements in effect for all services. For gas and steam, rates effective October 1, 1993 reflect the 35 percent corporate income tax rate. See Note G to the financial statements. February 22, 1994 - 60 - ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA A. Financial Statements Page Index to Financial Statements Number Report of Independent Accountants 62 Consolidated Balance Sheet at December 31, 1993 63-64 and 1992 Consolidated Income Statement for the years 65 December 31, 1993, 1992 and 1991 Consolidated Statement of Cash Flows for the 66 years ended December 31, 1993, 1992 and 1991 Consolidated Statement of Capitalization at 67-69 December 31, 1993 and 1992 Consolidated Statement of Retained Earnings 70 for the years ended December 31, 1993, 1992 and 1991 Notes to Consolidated Financial Statements 71-87 The following Schedules are filed as "Financial Statement Schedules" pursuant to Item 14 of this report: Schedule V - Property, Plant and Equipment (Utility Plant) 88-93 Schedule VI - Accumulated Depreciation - Utility Plant 94-96 Schedule VIII - Valuation and Qualifying Accounts 97-99 Schedule X - Supplementary Income Statement Information 100 All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. Separate financial statements of subsidiaries, not consolidated, have been omitted because, if considered in the aggregate, they would not constitute a significant subsidiary. - 61 - B. Supplementary Financial Information Selected Quarterly Financial Data for the years ended December 31, 1993 and 1992 (Unaudited)
First Second Third Fourth 1993 (Millions of Dollars) Quarter Quarter Quarter Quarter - ----------------------------------------------------------------------------------------------- Operating revenues $1,586.1 $1,396.0 $1,799.7 $1,483.6 Operating income 222.3 134.5 400.1 194.2 Net income 153.9 62.5 324.8 117.3 Net income for common stock 145.0 53.6 315.9 108.4 Earnings per common share $ .62 $ .23 $1.35 $ .46 - ----------------------------------------------------------------------------------------------- In the opinion of the Company these quarterly amounts include all djustments, consisting only of normal recurring accruals, necessary for a fair presentation.
First Second Third Fourth 1992 (Millions of Dollars) Quarter Quarter Quarter Quarter - ----------------------------------------------------------------------------------------------- Operating revenues $1,456.1 $1,280.1 $1,717.9 $1,478.8 Operating income 186.0 145.8 377.4 171.2 Net income 116.5 77.5 309.5 100.6 Net income for common stock 107.3 68.5 300.1 91.8 Earnings per common share $ .47 $ .30 $1.30 $ .39 =============================================================================================== - 62 - Report of Independent Accountants To the Board of Trustees and Stockholders of Consolidated Edison Company of New York, Inc. In our opinion, the consolidated financial statements listed under Item 8.A in the index appearing on page 60 present fairly, in all material respects, the financial position of Consolidated Edison Company of New York, Inc. and its subsidiaries at December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A, E and G to the consolidated financial statements, the Company changed its method of accounting for income taxes and postretirement benefits other than pensions in 1993. Price Waterhouse Price Waterhouse 1177 Avenue of the Americas New York, N.Y. 10036 February 22, 1994 - 63 - CONSOLIDATED BALANCE SHEET Consolidated Edison Company of New York, Inc. ====================================================================================== ASSETS - --------------------------------------------------------------------------------------
At December 31 (Thousands of Dollars) 1993 1992 - -------------------------------------------------------------------------------------- Utility plant, at original cost (Notes A and B) Electric $10,530,193 $10,183,064 Gas 1,341,704 1,250,312 Steam 403,411 371,758 General 1,015,947 882,083 - -------------------------------------------------------------------------------------- Total 13,291,255 12,687,217 Less: Accumulated depreciation 3,594,784 3,460,958 - -------------------------------------------------------------------------------------- Net 9,696,471 9,226,259 Construction work in progress 389,244 426,667 Nuclear fuel assemblies and components, less accumulated amortization 70,441 76,732 - -------------------------------------------------------------------------------------- Net utility plant 10,156,156 9,729,658 ====================================================================================== Current assets Cash and temporary cash investments (Note A) 36,756 282,454 Accounts receivable -- customers, less allowance for uncollectible accounts of $21,600 and $19,600 459,261 424,349 Other receivables 84,955 55,876 Regulatory accounts receivable (Note A) 97,117 167,931 Fuel, at average cost 53,755 87,485 Gas in storage, at average cost 49,091 45,570 Materials and supplies, at average cost 245,785 276,130 Prepayments 56,274 51,829 Other current assets 11,486 12,774 - -------------------------------------------------------------------------------------- Total current assets 1,094,480 1,404,398 ====================================================================================== Investments and nonutility property Investments (Note A) 92,108 70,033 Nonutility property 1,791 1,237 - -------------------------------------------------------------------------------------- Total investments and nonutility property 93,899 71,270 ====================================================================================== Deferred charges Recoverable fuel costs (Note A) 17,649 21,522 Enlightened Energy program costs (Note A) 140,057 80,760 Unamortized debt expense 144,928 55,072 Power contract termination costs 121,740 - Other deferred charges 337,826 233,439 - -------------------------------------------------------------------------------------- Total deferred charges 762,200 390,793 ====================================================================================== Regulatory asset - future federal income taxes (Notes A and G) 1,376,759 - ====================================================================================== Total $13,483,494 $11,596,119 ====================================================================================== - 64 -
====================================================================================== Capitalization and Liabilities - -------------------------------------------------------------------------------------- At December 31 (Thousands of Dollars) 1993 1992 - -------------------------------------------------------------------------------------- Capitalization (see Consolidated Statement of Capitalization) Common shareholders' equity $ 5,068,530 $ 4,886,879 Preferred stock subject to mandatory redemption (Note B) 100,000 100,000 Other preferred stock 540,728 541,249 Long-term debt 3,643,891 3,493,553 - -------------------------------------------------------------------------------------- Total capitalization 9,353,149 9,021,681 ====================================================================================== Noncurrent liabilities Obligations under capital leases 50,355 52,906 Other noncurrent liabilities 125,369 90,129 - -------------------------------------------------------------------------------------- Total noncurrent liabilities 175,724 143,035 ====================================================================================== Current liabilities Long-term debt due within one year (Note B) 133,639 162,897 Accounts payable 399,543 376,536 Customer deposits 157,380 153,840 Accrued income taxes 28,410 37,499 Other accrued taxes 30,896 40,838 Accrued interest 82,002 86,559 Accrued wages 81,174 80,320 Other current liabilities 172,876 90,636 - -------------------------------------------------------------------------------------- Total current liabilities 1,085,920 1,029,125 ====================================================================================== Deferred credits Accumulated deferred federal income tax (Note A) 1,083,720 964,290 Accumulated deferred investment tax credits (Note A) 201,144 213,404 Other deferred credits 207,078 224,584 - -------------------------------------------------------------------------------------- Total deferred credits 1,491,942 1,402,278 ====================================================================================== Deferred tax liability - future federal income taxes (Notes A and G) 1,376,759 - ====================================================================================== Contingencies (Note F) ====================================================================================== Total $13,483,494 $11,596,119 ====================================================================================== The accompanying notes are an integral part of these financial statements. /TABLE - 65 - CONSOLIDATED INCOME STATEMENT Consolidated Edison Company of New York, Inc. ============================================================================================ Year Ended December 31 (Thousands of Dollars) 1993 1992 1991 - --------------------------------------------------------------------------------------------
Operating revenues (Note A) Electric $5,131,665 $4,892,054 $4,896,818 Gas 808,389 728,343 678,332 Steam 325,340 312,507 297,908 - -------------------------------------------------------------------------------------------- Total operating revenues 6,265,394 5,932,904 5,873,058 ============================================================================================ Operating expenses Fuel and purchased power 1,417,829 1,317,072 1,440,575 Gas purchased for resale 289,708 245,175 223,354 Other operations 1,106,966 1,062,552 1,005,137 Maintenance 570,794 528,994 520,901 Depreciation and amortization (Note A) 403,730 380,861 359,826 Taxes, other than federal income tax 1,159,283 1,199,573 1,227,878 Federal income tax (Note G) 366,020 318,320 282,310 - -------------------------------------------------------------------------------------------- Total operating expenses 5,314,330 5,052,547 5,059,981 ============================================================================================ Operating income 951,064 880,357 813,077 - -------------------------------------------------------------------------------------------- Other income (deductions) Investment income (Note A) 4,934 12,063 48,215 Allowance for equity funds used during construction (Note A) 7,222 9,313 10,286 Other income less miscellaneous deductions (7,565) (3,899) (6,181) Federal income tax (Note G) 1,010 (2,150) (8,740) - -------------------------------------------------------------------------------------------- Total other income 5,601 15,327 43,580 ============================================================================================ Income before interest charges 956,665 895,684 856,657 - -------------------------------------------------------------------------------------------- Interest on long-term debt 281,756 274,442 271,361 Other interest 19,721 21,688 22,522 Allowance for borrowed funds used during construction (Note A) (3,334) (4,534) (4,136) - -------------------------------------------------------------------------------------------- Net interest charges 298,143 291,596 289,747 ============================================================================================ Net income 658,522 604,088 566,910 Preferred stock dividend requirements 35,617 36,428 36,850 - -------------------------------------------------------------------------------------------- Net income for common stock $ 622,905 $ 567,660 $ 530,060 ============================================================================================ Earnings per common share based on average number of shares outstanding during each year (233,981,369; 231,129,040; and 228,282,570) $2.66 $2.46 $2.32 ============================================================================================ The accompanying notes are an integral part of these financial statements. - 66 -
CONSOLIDATED STATEMENT OF CASH FLOWS Consolidated Edison Company of New York, Inc. ============================================================================================ Year Ended December 31 (Thousands of Dollars) 1993 1992 1991 - -------------------------------------------------------------------------------------------- Operating activities Net income $ 658,522 $ 604,088 $ 566,910 Principal non-cash charges (credits) to income Depreciation and amortization 403,730 380,861 359,826 Deferred recoverable fuel costs 3,873 (510) 29,866 Federal income tax deferred 94,210 67,870 81,150 Common equity component of allowance for funds used during construction (6,795) (8,710) (9,688) Other non-cash charges (24,451) 49,596 8,114 Changes in assets and liabilities Accounts receivable -- customers, less allowance for uncollectibles (34,912) (34,367) 5,291 Regulatory accounts receivable 70,814 (127,497) (34,855) Materials and supplies, including fuel and gas in storage 60,554 (6,570) 40,630 Prepayments, other receivables and other current assets (32,236) 16,088 (31,307) Enlightened Energy program costs (59,297) (20,841) (44,036) Power contract termination costs (68,380) - - Accounts payable 23,007 31,689 (8,758) Other -- net (63,374) 10,326 (17,731) - -------------------------------------------------------------------------------------------- Net cash flows from operating activities 1,025,265 962,023 945,412 ============================================================================================ Investing activities including construction Construction expenditures (789,068) (794,681) (774,817) Nuclear fuel expenditures (14,092) (35,220) (9,127) Contributions to nuclear decommissioning trust (19,247) (6,973) (6,973) Common equity component of allowance for funds used during construction 6,795 8,710 9,688 Investments other than temporary cash investments - 137,152 90,095 - -------------------------------------------------------------------------------------------- Net cash flows from investing activities including construction (815,612) (691,012) (691,134) ============================================================================================ Financing activities including dividends Issuance of common stock 11,881 156,788 - Issuance of preferred stock - 100,000 - Issuance of long-term debt 1,378,475 875,000 303,150 Retirement of long-term debt and preferred stock (177,897) (256,718) (123,848) Advance refunding of long-term debt and preferred stock (1,069,732) (664,000) - Issuance and refunding costs (108,562) (41,996) (7,607) Common stock dividends (453,902) (439,150) (424,614) Preferred stock dividends (35,614) (36,343) (36,832) - -------------------------------------------------------------------------------------------- Net cash flows from financing activities including dividends (455,351) (306,419) (289,751) ============================================================================================ Net decrease in cash and temporary cash investments (245,698) (35,408) (35,473) Cash and temporary cash investments at January 1 282,454 317,862 353,335 Cash and temporary cash investments at December 31 $ 36,756 $282,454 $317,862 Supplemental disclosure of cash flow information Cash paid during the period for: Interest $ 265,475 $261,619 $259,739 Income taxes 280,122 250,753 220,567 ============================================================================================ The accompanying notes are an integral part of these financial statements. - 67 - CONSOLIDATED STATEMENT OF CAPITALIZATION Consolidated Edison Company of New York, Inc. ==========================================================================================
At December 31 (Thousands of Dollars) 1993 1992 - ------------------------------------------------------------------------------------------ Shares outstanding ---------------------------- Dec. 31, 1993 Dec. 31, 1992 Common shareholders' equity (Note B) Common stock, $2.50 par value, authorized 340,000,000 shares 234,372,931 233,932,000 $1,448,845 $1,436,444 Retained earnings 3,658,886 3,489,880 Capital stock expense (39,201) (39,445) - ------------------------------------------------------------------------------------------ Total common shareholders' equity 5,068,530 4,886,879 ========================================================================================== Preferred stock (Note B) Subject to mandatory redemption Cumulative Preferred, $100 par value, 7.20% Series I 500,000 500,000 50,000 50,000 6-1/8% Series J 500,000 500,000 50,000 50,000 - ------------------------------------------------------------------------------------------ Total subject to mandatory redemption 100,000 100,000 - ------------------------------------------------------------------------------------------ Other preferred stock $5 Cumulative Preferred, without par value, authorized 1,915,319 shares 1,915,319 1,915,319 175,000 175,000 Cumulative Preferred, $100 par value, authorized 6,000,000 shares* 5-3/4% Series A 600,000 600,000 60,000 60,000 5-1/4% Series B 750,000 750,000 75,000 75,000 4.65% Series C 600,000 600,000 60,000 60,000 4.65% Series D 750,000 750,000 75,000 75,000 5-3/4% Series E 500,000 500,000 50,000 50,000 6.20% Series F 400,000 400,000 40,000 40,000 Cumulative Preference, $100 par value, authorized 2,250,000 shares 6% Convertible Series B 57,278 62,486 5,728 6,249 - ------------------------------------------------------------------------------------------ Total other preferred stock 540,728 541,249 - ------------------------------------------------------------------------------------------ Total preferred stock 640,728 641,249 ========================================================================================== *Represents total authorized shares of cumulative preferred stock, $100 par value, including preferred stock subject to mandatory redemption. - 68 -
============================================================================================= At December 31 (Thousands of Dollars) 1993 1992 - --------------------------------------------------------------------------------------------- Long-term debt (Note B) Maturity Interest Rate Series - --------------------------------------------------------------------------------------------- First and Refunding Mortgage Bonds (open-end mortgage):1993 4.40 % Y - 75,000 1993 4-5/8 AA - 75,000 1994 4.60 BB 125,000 125,000 1996 5 CC 100,000 100,000 1996 5.90 DD 75,000 75,000 1996 8-1/8 LL - 20,000 1997 6-1/4 EE - 80,000 1998 6.85 FF - 60,000 1999 7.90 GG - 80,000 2001 7.90 JJ - 150,000 2002 7.90 KK - 150,000 2003 7-3/4 MM - 150,000 - --------------------------------------------------------------------------------------------- Total mortgage bonds 300,000 1,140,000 - --------------------------------------------------------------------------------------------- Debentures: 1997 5.30 % 1993E 100,000 - 1998 6-1/4 1993A 100,000 - 1998 5.70 1993F 100,000 - 1999 6-1/2 1992D 75,000 75,000 2000 7-3/8 1992A 150,000 150,000 2000 7.60 1992C 125,000 125,000 2001 6-1/2 1993B 150,000 - 2002 6-5/8 1993C 150,000 - 2003 6-3/8 1993D 150,000 - 2004 7-5/8 1992B 150,000 150,000 2005 7-3/8 1992E 75,000 75,000 2023 7-1/2 1993G 380,000 - 2025 9.70 1990A 27,414 200,000 2026 9-3/8 1991A 95,329 175,000 2027 8.05 1992F 100,000 100,000 - --------------------------------------------------------------------------------------------- Total debentures 1,927,743 1,050,000 - --------------------------------------------------------------------------------------------- Tax-exempt debt -- notes issued to New York State Energy Research and Development Authority for Facilities Revenue Bonds: 2020 9 % 1985A 128,285 256,000 2020 5-1/4 1993B 127,715 - 2021 7-1/2 1986A 150,000 150,000 2022 7-1/8 1987A 100,855 100,855 2022 9-1/4 1987B 29,385 49,145 2022 5-3/8 1993C 19,760 - 2024 7-3/4 1989A 150,000 150,000 2024 7-3/8 1989B 100,000 100,000 2024 7-1/4 1989C 150,000 150,000 2025 7-1/2 1990A 150,000 150,000 2026 7-1/2 1991A 128,150 128,150 2027 6-3/4 1992A 100,000 100,000 2027 6-3/8 1992B 100,000 100,000 2028 6 1993A 101,000 - - --------------------------------------------------------------------------------------------- Total tax-exempt debt 1,535,150 1,434,150 - --------------------------------------------------------------------------------------------- - 69 - ============================================================================================== At December 31 (Thousands of Dollars) 1993 1992 - ---------------------------------------------------------------------------------------------- Other long-term debt: Liens on purchased gas turbines 31,419 39,315 Other long-term debt 10,476 11,467 Unamortized debt discount (27,258) (18,482) - ---------------------------------------------------------------------------------------------- Total 3,777,530 3,656,450 Less: Long-term debt due within one year 133,639 162,897 - ---------------------------------------------------------------------------------------------- Total long-term debt 3,643,891 3,493,553 ============================================================================================== Total capitalization $9,353,149 $9,021,681 ============================================================================================== The accompanying notes are an integral part of these financial statements. - 70 - CONSOLIDATED STATEMENT OF RETAINED EARNINGS Consolidated Edison Company of New York, Inc. ======================================================================================
Year Ended December 31 (Thousands of Dollars) 1993 1992 1991 - -------------------------------------------------------------------------------------- Balance, January 1 $3,489,880 $3,361,305 $3,255,851 Net income for the year 658,522 604,088 566,910 - -------------------------------------------------------------------------------------- Total 4,148,402 3,965,393 3,822,761 ====================================================================================== Dividends declared on capital stock Cumulative Preferred at required annual rates 35,259 35,957 36,419 Cumulative Preference, 6% Convertible Series B 355 386 413 Common, $1.94, $1.90 and $1.86 per share 453,902 439,150 424,614 - -------------------------------------------------------------------------------------- Total dividends declared 489,516 475,493 461,446 Redemption of Cumulative Preferred Stock, 8-1/8% Series H - 20 10 - -------------------------------------------------------------------------------------- Total deductions 489,516 475,513 461,456 - -------------------------------------------------------------------------------------- Balance, December 31 $3,658,886 $3,489,880 $3,361,305 - -------------------------------------------------------------------------------------- The accompanying notes are an integral part of these financial statements.- 71 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS =============================================================== NOTE A SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - --------------------------------------------------------------- REGULATION. The Company is subject to regulation by the New York Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC). The Company's accounting policies conform to generally accepted accounting principles, as applied in the case of regulated public utilities, and to the account- ing requirements and rate-making practices of these regulatory authorities. PRINCIPLES OF CONSOLIDATION. The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Intercompany transactions have been eliminated. UTILITY PLANT AND DEPRECIATION. The capitalized cost of additions to utility plant includes indirect costs such as engineering, supervision, payroll taxes, pensions, other benefits and an allowance for funds used during construction (AFDC). The original cost of property, together with removal cost, less salvage, is charged to accumulated depreciation as property is retired. The cost of repairs and maintenance is charged to expense, and the cost of betterments is capitalized. Rates used for AFDC include the cost of borrowed funds used for construction purposes and a reasonable rate on the Company's own funds when so used, determined in accordance with PSC and FERC regulations. The AFDC rate was 9.5 percent in 1993 and 1992 and 10.1 percent in 1991. The rate was compounded semiannually, and the amounts applicable to borrowed funds were treated as a reduction of interest charges. The annual charge for depreciation is computed on the straight-line method for financial statement purposes, using rates based on average lives and net salvage factors, with the exception of the Indian Point 2 nuclear unit, the Company's share of the Roseton generating station and certain leaseholds, which are depreciated on a remaining life amortization method. Depreciation rates averaged approximately 3.1 percent in 1993, 1992 and 1991. Depreciation expense includes the amortization of certain deferred charges authorized by the PSC. The Company is a joint owner of two 1,200-megawatt electric generating stations: (1) Bowline Point, operated by Orange and Rockland Utilities, Inc. with Con Edison owning a two-thirds interest and (2) Roseton, operated by Central Hudson Gas & Electric Corp. with Con Edison owning a 40 percent interest. Central Hudson has the option to acquire the Company's interest in the Roseton station in 2004. Con Edison's share of the investment in these stations at original cost and as included in its balance sheet at December 31, 1993 and December 31, 1992 was: - --------------------------------------------------------------- (Thousands of Dollars) 1993 1992 - --------------------------------------------------------------- Bowline Point: Plant in service $195,546 $193,466 Construction work in progress 2,400 2,050 Roseton: Plant in service 139,798 141,330 Construction work in progress 1,204 439 - --------------------------------------------------------------- The Company's share of accumulated depreciation for the Roseton station at December 31, 1993 and 1992 was $57.9 million and $56.0 million, respectively. A separate depreciation account is not maintained for the Company's share of the Bowline Point station. The Company's share of operating expenses for these stations is included in its income statement. - 72 - NUCLEAR DECOMMISSIONING. Depreciation charges include a provision for decommissioning both the Indian Point 2 and the retired Indian Point 1 nuclear units. Decommissioning costs are being accrued ratably over the Indian Point 2 license period which extends to the year 2013. The Company has been accruing for the costs of decommissioning within the internal depreciation reserve since 1975. In 1989 the PSC permitted the Company to establish an external trust fund for the costs of decommissioning the nuclear portions of the plants pursuant to NRC regulations. Accordingly, beginning in 1989 the Company made contributions to such a trust. The external trust fund is discussed below under "Investments" in this Note A. Accumulated decommissioning provisions at December 31, 1993 and 1992, which include earnings on funds externally invested, are as follows: - ------------------------------------------------------------ Amounts Included in Accumulated Depreciation (Millions of Dollars) 1993 1992 - ------------------------------------------------------------ Nuclear $ 86.0 $ 70.0 Non-Nuclear 50.6 47.5 Total $136.6 $117.5 - ------------------------------------------------------------ The Company currently provides annual expense allowances of $11.7 million and $3.1 million, respectively, for decommis- sioning the nuclear and non-nuclear portions of the plants. These amounts, which are recovered from customers through billings, were approved by the PSC in the 1992 electric rate settlement agreement, and were designed to fund decommissioning costs which had been estimated, consistent with NRC minimum funding standards in 1992, at approximately $300 million in 1993 dollars and (using a five percent annual escalation factor) approximately $950 million in 2016, the midpoint of a six-year decommissioning period assumed to follow expiration of the license. In 1993 the NRC, using a substantially revised scenario for waste disposal, published new funding standards which would more than double these estimated decommissioning costs. The Company is preparing a site-specific decommissioning study for its plants which it intends to file with the PSC in its next electric rate proceeding, currently planned for 1994. The Company expects that this study will also produce estimated decommissioning costs substantially higher than its previous estimates. In the rate proceeding, the Company will seek an increase in the amounts of the decommissioning expense allowances consistent with the new study and NRC requirements. NUCLEAR FUEL. Nuclear fuel assemblies and components are amortized to operating expenses based on the quantity of heat produced for the generation of electricity. A provision for the future storage of the spent fuel is charged to operating expenses based on the kilowatt-hours of electricity generated. Nuclear fuel costs are recovered in revenues through base rates or through the fuel adjustment clause. LEASES. In accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation," those leases that meet the criteria for capitalization are capitalized for accounting purposes. For rate-making purposes, all leases have been treated as operating leases. - 73 - REVENUES. Revenues for electric and steam service are recognized on a monthly billing cycle basis. Pursuant to the three-year electric rate settlement agreement, effective April 1, 1992, actual electric net revenues (operating revenues less fuel and purchased power costs and revenue taxes) are adjusted by accrual to target levels established under the agreement in accordance with the electric revenue adjustment mechanism (ERAM). Revenues are also increased (or decreased) each month to reflect incentives (or penalties) earned for the Enlightened Energy program and for customer service activities. The settlement agreement provides that the net regulatory asset (or liability), including interest thereon, thus accrued in each rate year is to be reflected in customers' bills in the following rate year. In accordance with a PSC rate order the Company began phasing in recognition of unbilled gas revenues over a 4-1/4 year period effective October 1989. Pursuant to the gas rate decision in October 1991, this recognition of unbilled gas revenues was modified so as to be fully phased in by September 30, 1994. Revenues from the fuel adjustment clause are not recorded until billed. RECOVERABLE FUEL COSTS. Fuel and purchased power costs that are above the levels included in base rates are recoverable under electric, gas and steam fuel adjustment clauses. If costs fall below these levels, the difference is credited to customers. For electric and steam, such costs are deferred until the period in which they are billed or credited to customers (40 days for electric, 30 days for steam). For gas, the excess or deficiency is accumulated for refund or surcharge to customers on an annual basis. Effective April 1992, a partial pass-through electric fuel adjustment clause (PPFAC) was implemented with monthly targets for fuel and purchased power costs. The Company retains for stockholders 30 percent of any savings in actual costs below the target amount, but must bear 30 percent of any excess of actual costs over the target. For each rate year of the electric rate agreement there is a $30 million cap on the maximum increase or decrease in fuel billings, with a limit (within the $30 million) of $10 million for costs associated with generation at the Company's Indian Point 2 nuclear unit. Subject to these limits, 30 percent of any variance below target amounts is added to regulatory accounts receivable and 30 percent of any variance above target amounts is deducted from regulatory accounts receivable. The PSC has allowed the Company to recover in rates certain deferred recoverable fuel costs that were affected by shortening the billing lag period or changing the cost of fuel in base rates. If there were any further such revisions, the Company believes that deferred recoverable fuel costs affected thereby would be recovered. - 74 - REGULATORY ACCOUNTS RECEIVABLE. Regulatory accounts receivable, amounting to $97.1 million at December 31, 1993 include accruals under the three-year electric rate settlement agreement for net electric sales revenues in accordance with the ERAM ($36.2 million), for incentives and lost revenues related to the Company's Enlightened Energy program ($44.7 million), for incentives related to customer service activities ($6.4 million) and for the amounts to be billed under the PPFAC ($9.8 million). The revenues accrued in 1992 under the ERAM and for incentives related to the Enlightened Energy program and customer service activities are being collected from customers over the twelve-month period ending March 31, 1994. Revenues accrued in 1993 are anticipated to be collected over a twelve- month period beginning April 1, 1994. The revenues accrued under the PPFAC are billed to customers on a monthly basis through the electric fuel adjustment clause. ENLIGHTENED ENERGY COSTS. In accordance with PSC directives, the Company defers the costs for its Enlightened Energy program for future recovery from ratepayers. Such deferrals amounted to $140.1 million at December 31, 1993 and $80.8 million at December 31, 1992. Pursuant to the 1990 electric rate settlement agreement, the Company recovered approximately $40 million through the fuel adjustment clause over the twelve- month period ended March 31, 1992. In accordance with the 1992 electric rate settlement agreement, the Company is generally recovering its Enlightened Energy program costs over a five- year period. TEMPORARY CASH INVESTMENTS. Temporary cash investments are short-term, highly liquid investments which generally have maturities of three months or less. They are stated at cost which approximates market. The Company considers temporary cash investments to be cash equivalents. INVESTMENTS. Investments consist primarily of an external nuclear decommissioning trust fund. At December 31, 1993 and 1992, the trust fund amounted to $83.1 million and $59.5 million, respectively. Investments are stated at cost which approximates market. Earnings on the trust fund are not recognized in income but are included in the accumulated depreciation reserve. See "Nuclear Decommissioning" in this Note A. FEDERAL INCOME TAX. The Company provides for deferred federal income taxes with respect to certain benefits realized from depreciation deductions utilized for tax purposes, deferred fuel accounting, unbilled revenues (electricity, gas and steam) included in taxable income, deferrals arising from the rate settlement agreements, and certain other specific items, when approved by the PSC. For rate-making purposes, accumulated deferred federal income taxes are deducted from rate base and amortized or otherwise applied as a reduction (or increase) in federal income tax expense in future years. Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties. The balance at December 31, 1993 for each of the above is reported as a "deferred credit" in the financial statements. - 75 - In February 1992 the Financial Accounting Standards Board issued SFAS 109, "Accounting for Income Taxes," which the Company adopted effective January 1, 1993. It requires the Company to record deferred income taxes for substantially all temporary differences between the book and tax bases of assets and liabilities, including those differences for which deferred taxes have not previously been provided. It also requires the Company to adjust deferred income tax balances to reflect changes in current income tax rates. As a result of the adoption of SFAS 109, the Company has recorded an increase in accumulated deferred income tax liabilities and a corresponding increase in regulatory assets. The $1,376.8 million of regulatory assets represents the future revenue recoverable from customers for increases in taxes as these taxes become payable (see Note G). On January 15, 1993, the PSC issued an Interim Policy Statement proposing accounting procedures consistent with SFAS 109 and providing assurances that these future increases in taxes will be recoverable in rates. The Company and its subsidiaries file a consolidated federal income tax return. Income taxes are allocated to each company based on its taxable income. RESEARCH AND DEVELOPMENT COSTS. Research and development costs relating to specific construction projects are capitalized. All other such costs are charged to operating expenses as incurred. Research and development costs in 1993, 1992 and 1991, amounting to $48.0 million, $44.8 million and $36.3 million, respectively, were charged to operating expenses. No research and development costs were capitalized in these years. - 76 - Note B Capitalization - -------------------------------------------------------------- COMMON STOCK AND PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION. Each share of Series B preference stock is convertible into 13 shares of common stock at a conversion price of $7.69 per share. During 1993, 1992 and 1991, 5,208 shares, 4,349 shares and 7,177 shares of Series B preference stock were converted into 67,704 shares, 56,537 shares and 93,301 shares of common stock, respectively. At December 31, 1993, 744,614 shares of unissued common stock were reserved for conversion of preference stock. The preference stock is subordinate to the $5 Cumulative Preferred Stock and Cumulative Preferred Stock with respect to dividends and liquidation rights. Redemption prices of preferred stock other than Series I and Series J at December 31, 1993 (in each case, plus accrued dividends) were as follows: - -------------------------------------------------------------- $5 Cumulative Preferred Stock $105.00 - -------------------------------------------------------------- Cumulative Preferred Stock: Series A 102.00 Series B 102.00 Series C 101.00 Series D 101.00 Series E 101.00 Series F 102.50 - -------------------------------------------------------------- Cumulative Preference Stock: 6% Convertible Series B 100.00 - -------------------------------------------------------------- PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION. The Company is required to redeem 25,000 of the Series I shares on May 1 of each year in the five-year period commencing with the year 2002 and to redeem the remaining Series I shares on May 1, 2007. The Company is required to redeem the Series J shares on August 1, 2002. In each case, the redemption price is $100 per share plus accrued and unpaid dividends to the redemption date. In addition, the Company may redeem Series I shares at a redemption price of $106.48 per share, plus accrued dividends, if redeemed prior to May 1, 1994 (and thereafter at prices declining annually to $100 per share, plus accrued dividends, after April 30, 2002); provided, however, that prior to May 1, 1997, the Company may not redeem any Series I shares with borrowed funds or proceeds from certain securities issuances having a cost to the Company of less than 7.20 percent per annum. Neither Series I nor Series J shares may be called for redemption while dividends are in arrears on outstanding shares of $5 Cumulative Preferred Stock or Cumulative Preferred Stock. Nevertheless, the mandatory redemption obligation of the Company with respect to such shares is cumulative and if the redemption requirement is in arrears the Company may not purchase or redeem or pay any dividends on the common stock or any other stock ranking junior as to dividends or assets to the Cumulative Preferred Stock, except for payments or distribu- tions in common stock or such junior stock. - 77 - LONG-TERM DEBT. Total long-term debt maturing in the period 1994-1998 is as follows: - -------------------------------------------------------------- 1994 $133,639,000 1995 $ 10,889,000 1996 $183,524,000 1997 $106,256,000 1998 $200,000,000 - -------------------------------------------------------------- Substantially all properties and franchises of the Company, other than expressly excepted property, are subject to the liens securing the Company's First and Refunding Mortgage Bonds and the mortgage bonds of acquired companies. - 78 - =============================================================== Note C Lines of Credit - ---------------------------------------------------------------- The Company has bank lines of credit for 1994 amounting to $150 million. The credit lines require average compensating balances of 2.5 percent of the credit lines, with interest on any borrowings to be at prevailing market rates. There are no legal restrictions applicable to the Company's cash balances resulting from its obligation to maintain compensating balances. =============================================================== - 79 - Note D Pension Plans - --------------------------------------------------------------- The pension plans for management and bargaining unit employees cover substantially all employees of the Company and are designed to comply with the Employee Retirement Income Security Act of 1974 (ERISA). Contributions are made solely by the Company based on an actuarial valuation, and are not less than the minimum amount required by ERISA. The Company's policy is to fund the actuarially computed net pension cost as such cost accrues. Benefits for management and bargaining unit employees are generally based on a final five-year average pay formula. In accordance with SFAS 87, "Employers' Accounting for Pensions," the Company uses the projected unit credit method for determining pension cost. Pension costs for 1993, 1992 and 1991 amounted to $42.4 million, $56.8 million and $65.9 million, respectively, of which $33.6 million for 1993, $44.8 million for 1992 and $52.0 million for 1991 was charged to operating expense. In accordance with SFAS 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," as modified by SFAS 71, the Company in 1993 recorded an additional $4.4 million of pension cost, of which $3.5 million was charged to operating expense, in connection with the special retirement program discussed below. Effective January 1, 1993, the Company adopted the PSC's "Statement of Policy and Order Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other Than Pensions" ("the Policy"). The Policy requires certain departures from the Company's previous accounting under SFAS 87, including actuarial recognition of investment gains and losses over five years (previously four years), removal of the 10 percent gain/loss corridor, and adoption of a 10-year period for amortization of recognized gains and losses. (Previously, amounts in excess of corridor limits were amortized over the remaining average service life of active employees.) These changes have reduced pension cost in 1993 due to more rapid amortization of outstanding actuarial gains. The Company offered a special retirement program in 1993 providing enhanced pension benefits for those employees who met certain eligibility requirements and retired within specific time limits. The incentives offered by the Company fall within the category of special termination benefits as described in SFAS 88. The increase in pension obligations as a result of this program amounts to $33.3 million. Under an agreement with the PSC, the Company will amortize this liability over a 15- year period, with rate recovery anticipated for the costs allocable to years three through fifteen. In accordance with SFAS 71, the Company has charged the equivalent of the first two years of the amortization ($4.4 million) to pension expense in 1993 and has established a liability and offsetting regula- tory asset for the $28.9 million allocable to future periods. - 80 - The components of net periodic pension cost for 1993, 1992 and 1991 were as follows: - ------------------------------------------------------------------- (Millions of Dollars) 1993 1992 1991 - ------------------------------------------------------------------- Service cost -- benefits earned during the period $ 96.0 $ 89.7 $ 83.4 Interest cost on projected benefit obligation 259.9 243.2 218.8 Actual return on plan assets (500.0) (258.4) (598.7) Unrecognized investment gain (loss) deferred 201.5 (19.3) 355.5 Net amortization (15.0) 1.6 6.9 Net periodic pension cost 42.4 56.8 65.9 Special retirement program cost 33.3 - - Regulatory asset (28.9) - - Net special retirement program cost 4.4 - - Total pension cost $ 46.8 $ 56.8 $ 65.9 - ------------------------------------------------------------------- To determine the present value of the projected benefit obligation in 1993, 1992 and 1991, a discount rate of 7.5 percent and an average rate of increase in future compensation levels of approximately 6.5 percent were assumed. The assumed long-term rate of return on plan assets was 8.5 percent for these years. The pension plan assets consist primarily of corporate common stock and bonds, group annuity contracts and debt of the United States government and its agencies. The funded status of the pension plans as of December 31, 1993, 1992 and 1991 was as follows: - -------------------------------------------------------------------- (Millions of Dollars) 1993 1992 1991 - -------------------------------------------------------------------- Actuarial present value of benefit obligations: Vested $2,731.9 $2,421.0 $2,245.0 Nonvested 212.6 206.0 193.0 Accumulated to date 2,944.5 2,627.0 2,438.0 Effect of projected future compensation levels 841.5 809.0 745.0 Total projected obligation 3,786.0 3,436.0 3,183.0 Plan assets at fair value 4,154.3 3,745.0 3,551.0 Plan assets less projected benefit obligation 368.3 309.0 368.0 Unrecognized net gain (522.9) (447.0) (446.0) Unrecognized prior service cost* 102.5 112.0 49.0 Unrecognized net transition liability at January 1, 1987* 23.2 26.0 29.0 Accrued pension cost $ (28.9)** $ 0 $ 0 - --------------------------------------------------------------------- *Being amortized over approximately 15 years. **See discussion above in this Note D. - 81 - Note E Postretirement Benefits Other Than Pensions (OPEB) - --------------------------------------------------------------- The Company has a contributory comprehensive hospital, medical and prescription drug program for all retirees, their dependents and surviving spouses. The Company also provides life insurance benefits for approximately 7,000 retired employees. All of the Company's employees become eligible for these benefits upon retirement except that the amount of life insurance is limited and is available only to management employees and to those bargaining unit employees who participated in the optional program prior to retirement. The Company has reserved the right to amend or terminate the program. The Company adopted the provisions of SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," effective January 1, 1993. It contains specific rules for determining the cost of postretirement health and life insurance benefits. These rules require accrual of the obligation for previously unrecognized retiree benefit cost over a shorter period than previous methods. The retiree health and life insurance expense for 1993 was determined in accordance with the PSC policy (see Note D) which requires the Company to defer the difference between the rate allowance for OPEB expense and the OPEB expense determined in accordance with SFAS 106, amortize the transition obligation over 20 years, and recognize all gains and losses over a 10- year period in determining the SFAS 106 expense. Electric, gas and steam rates in 1993 reflect the increase in expense resulting from the adoption of SFAS 106. Rate allowances that are not funded to an external trust accrue interest at the pre- tax rate of return. As of December 31, 1993, the Company has accrued $6.9 million in interest on its unfunded liability. The Company's policy is to fund in external trusts the actuarially determined annual costs for retiree health and life insurance subject to statutory maximum (and minimum) limits. The cost to the Company for retiree health benefits for 1993, 1992 and 1991 amounted to $66.3 million, $46.1 million and $33.5 million, respectively, of which $52.5 million for 1993, $36.4 million for 1992 and $26.5 million for 1991 was charged to operating expense. The cost of the retiree life insurance plan to the Company for 1993, 1992 and 1991 amounted to $22.3 million, $8.6 million and $7.7 million, respectively, of which $17.7 million for 1993, $6.8 million for 1992 and $6.1 million for 1991 was charged to operating expense. The components of postretirement benefit (health and life insurance) costs for year 1993 were as follows: - ----------------------------------------------------------------- (Millions of Dollars) - ----------------------------------------------------------------- Service cost -- benefits earned during the period $ 10.3 Interest cost on accumulated postretirement benefit obligations 53.0 Actual return on plan assets (8.5) Unrecognized investment gain deferred 2.9 Amortization of transition obligation over 20 years 30.9 Net periodic postretirement benefit cost $ 88.6 - ----------------------------------------------------------------- - 82 - The discount rate used in determining the accumulated postretirement benefit obligation was 7.5 percent, and the expected long-term rate of return on plan assets was 8.5 percent. The health cost trend rate assumed for year 1993 was 12 percent, for year 1994, 9 percent, and then declining one percent per year to 4.5 percent for year 1999 and thereafter. If the assumed health care cost trend rate were to be increased by one percentage point each year, the accumulated postretirement benefit obligation would increase by approximately $89.1 million and the service cost and interest component of the net periodic postretirement benefit cost would increase by $8.7 million. Postretirement plan assets consist of corporate common stock and bonds, group annuity contracts, debt of the United States government and its agencies and short-term securities. The following table sets forth the program's estimated funded status at December 31, 1993: - ----------------------------------------------------------------- (Millions of Dollars) - ----------------------------------------------------------------- Accumulated postretirement benefit obligation: Retirees $ 413.2 Employees eligible to retire 144.2 Employees not eligible to retire 221.5 Total projected obligation 778.9 Plan assets at fair value 130.8 Plan assets less accumulated postretirement benefit obligation (648.1) Unrecognized net loss 33.4 Unrecognized net transition liability at January 1, 1993* 586.2 Accrued postretirement benefit cost $ (28.5) - ----------------------------------------------------------------- *Being amortized over a period of 20 years at $30.9 million per year. The accrued unfunded liability for retiree health benefits was $28.5 million at December 31, 1993 and $41.8 million at December 31, 1992. - 83 - NOTE F - Contingencies - ----------------------------------------------------------- INDIAN POINT. Nuclear generating units similar in design to the Company's Indian Point 2 unit have experienced problems of varying severity in their steam generators, which in a number of instances have required steam generator replacement. Inspections of the Indian Point 2 steam generators since 1976 have revealed various problems, some of which appear to have been arrested, but the remaining service life of the steam generators is uncertain and may be shorter than the unit's life. The projected service life of the steam generators is reassessed periodically in the light of the inspections made during scheduled outages of the unit. Based on data from the latest completed inspection (1993) and other sources, the Company estimates that steam generator replacement will not be required before 1997, and possibly not until some years later. To avoid procurement delays in the event replacement is necessary, the Company purchased, and has stored at the site, replacement steam generators. If replacement of the steam generators is required, such replacement is presently estimated (in 1993 dollars) to require additional expenditures of approximately $135 million (exclusive of replacement power costs) and an outage of approximately six months. However, securing necessary permits and approvals or other factors could require a substantially longer outage if steam generator replacement is required on short notice. NUCLEAR INSURANCE. The insurance polices covering the Company's nuclear facilities for property damage, excess property damage, and outage costs permit assessments under certain conditions to cover insurers' losses. As of December 31, 1993, the highest amount which could be assessed for losses during the current policy year under all of the policies was $25.6 million. While assessments may also be made for losses in certain prior years, the Company is not aware of any losses in such years which it believes are likely to result in an assessment. Under certain circumstances, in the event of nuclear incidents at facilities covered by the federal government's third-party liability indemnification program, the Company could be assessed up to $79.3 million per incident of which not more than $10 million may be assessed in any one year. The per-incident limit is to be adjusted for inflation not later than 1998 and not less than once every five years thereafter. The Company participates in an insurance program covering liabilities for injuries to certain workers in the nuclear power industry. In the event of such injuries, the Company is subject to assessment up to an estimated maximum of approximately $3.2 million. - 84 - SUPERFUND CLAIMS. The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (Superfund) by its terms imposes joint and several strict liability, regardless of fault, upon generators of hazardous substances for resulting removal and remedial costs and environmental damages. Complex technical and factual determinations must be made prior to the ultimate disposition of these claims. Accordingly, estimates of the total removal, remedial and environmental damage costs for these sites may not be accurate. Moreover, the Company at appropriate times seeks recovery of its share of these costs under any applicable insurance coverage and through inclusion of such costs in allowable costs for rate-making purposes. The Company has received process or notice concerning possible claims under Superfund or similar state statutes relating to 14 sites at which it is alleged that hazardous substances generated by the Company (and, in most instances, a large number of other potentially responsible parties) were deposited. At the five sites for which the Company has estimates, the removal, remedial and environmental damage costs it will be obligated to pay are estimated at approximately $11 million. The Company has accrued a liability in this amount. It is possible that substantial additional costs may be incurred with respect to the 14 sites and other sites. The Company evaluates its potential Superfund liability on an ongoing basis. Based on the information and relevant circumstances known to the Company at this time, it is the opinion of the Company that the amounts it will be obligated to pay for the 14 sites will not have a material adverse effect on the Company's financial position. DEC PROCEEDING. In June 1992 the Staff of the New York State Department of Environmental Conservation (DEC) instituted a civil administrative proceeding against the Company before the DEC, alleging environmental violations. The complaint seeks approximately $20 million in civil penalties, and injunctive measures which could require substantial capital expenditures. The Company does not believe that this proceeding will materially interfere with its operations or materially adversely affect the Company's financial position. ASBESTOS CLAIMS. Suits were brought in New York State and federal courts against the Company and many other defendants, wherein several hundred plaintiffs sought large amounts of compensatory and punitive damages for deaths and injuries allegedly caused by exposure to asbestos at various premises of the Company. Many of these suits have been disposed of without any payment by the Company, or for immaterial amounts. Additional settlements, also for immaterial amounts, are pending. The amounts specified in all the remaining suits, including those for which settlements are pending, total billions of dollars but the Company believes that these amounts are greatly exaggerated, as were the claims already disposed of. Based on the information and relevant circumstances known to the Company at this time, it is the opinion of the Company that these suits will not have a material adverse effect on the Company's financial position. - 85 - =========================================================================================== NOTE G Federal Income Tax - -------------------------------------------------------------------------------------------
Year Ended December 31 (Thousands of Dollars) 1993 1992 1991 - ------------------------------------------------------------------------------------------- Charged to: Operations $ 366,020 $318,320 $282,310 Other income (1,010) 2,150 8,740 - ------------------------------------------------------------------------------------------- Total federal income tax 365,010 320,470 291,050 =========================================================================================== Reconciliation of reported net income with taxable income Federal income tax -- current 270,800 252,600 209,900 Federal income tax -- deferred 106,470 81,670 94,950 Investment tax credits deferred (12,260) (13,800) (13,800) - ------------------------------------------------------------------------------------------- Total federal income tax 365,010 320,470 291,050 Net income 658,522 604,088 566,910 - ------------------------------------------------------------------------------------------- Income before federal income tax 1,023,532 924,558 857,960 - ------------------------------------------------------------------------------------------- Effective federal income tax rate 35.7% 34.7% 33.9% =========================================================================================== Adjustments decreasing (increasing) taxable income: Tax depreciation in excess of book depreciation: Amounts subject to normalization 224,833 203,030 191,810 Other (88,819) (86,999) (75,880) Deferred recoverable fuel costs (3,873) 510 (29,866) Unbilled revenue (16,076) (3,349) 26,112 Regulatory accounts receivable (70,814) 127,497 34,855 Enlightened Energy program costs 59,297 20,841 44,036 Property tax settlements (66,060) 14,277 (40,273) Boiler fuel sales tax settlement 52,748 (65,401) - Pension and other postretirement benefits (978) (38,394) - Advance refunding of long-term debt 86,346 17,375 - Power contract termination costs 68,380 - - Other -- net (3,859) (8,625) 88,115 - ------------------------------------------------------------------------------------------- Total 241,125 180,762 238,909 - ------------------------------------------------------------------------------------------- Taxable income 782,407 743,796 619,051 =========================================================================================== Federal income tax -- current Amount computed at statutory rates (35%, 34% and 34%)* 273,842 252,891 210,477 Tax credits (3,042) (291) (577) - ------------------------------------------------------------------------------------------- Total 270,800 252,600 209,900 - ------------------------------------------------------------------------------------------- Charged to: Operations 271,140 250,160 202,860 Other income (340) 2,440 7,040 - ------------------------------------------------------------------------------------------- Total 270,800 252,600 209,900 =========================================================================================== *Under rate agreements, the effect of increases in the statutory rate from 34% to 35% effective January 1, 1993 was deferred until such effect could next be reflected in rates. The deferrals applicable to gas and steam operations began to be amortized over a twelve- month period beginning October 1, l993 when new rates became effective. For electric operations, deferrals for the year 1993 and the first three months of 1994 will be amortized over a twelve-month period beginning April 1, 1994 when new electric rates become effective. - 86 - =========================================================================================== NOTE G Federal Income Tax, continued - ------------------------------------------------------------------------------------------- Year Ended December 31 (Thousands of Dollars) 1993 1992 1991 - ------------------------------------------------------------------------------------------- Federal income tax -- deferred Provisions for deferred federal income taxes consist of the following tax effects of timing differences between tax and book income: Tax depreciation in excess of book depreciation 76,193 66,220 62,473 Deferred recoverable fuel costs (1,356) 174 (10,154) Unbilled revenue (5,626) (1,139) 8,878 Regulatory accounts receivable (24,785) 43,349 11,851 Enlightened Energy program costs 20,754 7,086 14,972 Property tax settlements (23,121) 4,854 (13,693) Boiler fuel sales tax settlement 18,462 (22,236) - Pension and other postretirement benefits 3,850 (13,054) - Advance refunding of long-term debt 30,221 5,908 - Power contract termination costs 23,933 - - Other -- net (12,055) (9,492) 20,623 - ------------------------------------------------------------------------------------------- Total 106,470 81,670 94,950 - ------------------------------------------------------------------------------------------- Charged to: Operations 107,140 81,960 93,250 Other income (670) (290) 1,700 - ------------------------------------------------------------------------------------------- Total $ 106,470 $ 81,670 $ 94,950 =========================================================================================== Under SFAS 109, temporary differences gave rise to deferred tax assets of $136,139 and deferred tax liabilities of $1,512,898 at December 31, 1993. These amounts are summarized as follows: Property related differences $1,505,768 Allowance for funds used during construction 5,790 Unamortized investment tax credits (108,311) Reserve for injuries and damages (26,977) Other -- net 489 - ------------------------------------------------------------------------------------------- Net deferred tax liability $1,376,759 ============================================================================================ - 87 - =========================================================================================================================== NOTE H Financial Information by Business Segments (Thousands of Dollars) - --------------------------------------------------------------------------------------------------------------------------- Electric Steam ------------------------------------ ---------------------------------------
1993 1992 1991 1993 1992 1991 - --------------------------------------------------------------------------------------------------------------------------- Operating revenues* $5,145,010 $4,905,523 $4,909,803 $ 326,888 $ 314,075 $ 299,724 - --------------------------------------------------------------------------------------------------------------------------- Operating expenses Fuel and purchased power 1,259,194 1,170,171 1,282,872 158,635 146,901 157,703 Other operations and maintenance* 1,403,022 1,328,900 1,276,491 78,787 75,210 72,315 Depreciation and amortization 350,590 331,610 314,526 9,909 9,259 8,561 Taxes, other than federal income 994,174 1,037,461 1,069,483 46,090 46,741 46,586 Federal income tax 322,076 281,960 251,847 4,966 6,069 1,621 - --------------------------------------------------------------------------------------------------------------------------- Total operating expenses* 4,329,056 4,150,102 4,195,219 298,387 284,180 286,786 - --------------------------------------------------------------------------------------------------------------------------- Operating income 815,954 755,421 714,584 28,501 29,895 12,938 - --------------------------------------------------------------------------------------------------------------------------- Construction expenditures 626,494 641,076 634,562 36,612 32,008 26,539 - --------------------------------------------------------------------------------------------------------------------------- Net utility plant** 8,592,187 8,285,993 7,933,027 337,713 303,198 273,678 Fuel 53,681 87,410 79,714 74 75 87 Other identifiable assets 2,170,016 743,795 607,542 56,732 15,929 8,813 - --------------------------------------------------------------------------------------------------------------------------- *Intersegment rentals included in segments' income but eliminated for total company Operating revenues $13,345 $13,469 $12,985 $ 1,548 $ 1,568 $ 1,816 Operating expenses 2,726 2,559 2,924 14,139 14,250 13,702 =========================================================================================================================== Gas Total Company ------------------------------------ --------------------------------------- 1993 1992 1991 1993 1992 1991 - --------------------------------------------------------------------------------------------------------------------------- Operating revenues* $ 810,377 $ 730,132 $ 680,175 $ 6,265,394 $ 5,932,904 $ 5,873,058 - --------------------------------------------------------------------------------------------------------------------------- Operating expenses Fuel and purchased power - - - 1,417,829 1,317,072 1,440,575 Gas purchased for resale 289,708 245,175 223,354 289,708 245,175 223,354 Other operations and maintenance* 212,832 204,262 193,876 1,677,760 1,591,546 1,526,038 Depreciation and amortization 43,231 39,992 36,739 403,730 380,861 359,826 Taxes, other than federal income 119,019 115,371 111,809 1,159,283 1,199,573 1,227,878 Federal income tax 38,978 30,291 28,842 366,020 318,320 282,310 - --------------------------------------------------------------------------------------------------------------------------- Total operating expenses* 703,768 635,091 594,620 5,314,330 5,052,547 5,059,981 - --------------------------------------------------------------------------------------------------------------------------- Operating income 106,609 95,041 85,555 951,064 880,357 813,077 - --------------------------------------------------------------------------------------------------------------------------- Construction expenditures 125,962 121,597 113,716 789,068 794,681 774,817 - --------------------------------------------------------------------------------------------------------------------------- Net utility plant** 1,226,256 1,140,467 1,056,289 10,156,156 9,729,658 9,262,994 Fuel and gas in storage 49,091 45,570 43,160 102,846 133,055 122,961 Other identifiable assets 193,724 86,829 84,238 2,420,472 846,553 700,593 Other corporate assets 804,020 886,853 1,021,394 - --------------------------------------------------------------------------------------------------------------------------- Total assets $13,483,494 $11,596,119 $11,107,942 - --------------------------------------------------------------------------------------------------------------------------- *Intersegment rentals included in segments' income but eliminated for total company Operating revenues $ 1,988 $ 1,789 $ 1,843 $ 16,881 $16,826 $16,644 Operating expenses 16 17 18 16,881 16,826 16,644 =========================================================================================================================== **General Utility Plant was allocated to Electric and Gas on the basis of the departmental use of such plant. Pursuant to PSC requirements the Steam department is charged an interdepartmental rent for General Plant used in Steam operations which is credited to the Electric and Gas departments. /TABLE - 88 - SCHEDULE V CONSOLIDATED EDISON COMPANY OF NEW YORK, INC. PROPERTY, PLANT AND EQUIPMENT (UTILITY PLANT) (D) YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
COLUMN F COLUMN A BALANCE AT END OF PERIOD Common (Electric- Classification Electric Gas Gas) Steam Total Plant in service: Land and land rights......... $ 96,484 $ 665 $ 29,049 $ 758 $ 126,956 Structures and improvements.. 764,009 8,378 353,005 12,702 1,138,094 Production plant equipment... 2,325,769 - - 103,620 2,429,389 Storage plant equipment...... - 30,446 - - 30,446 Transmission lines and equipment.................. 1,564,717 - - - 1,564,717 Distribution lines, mains and equipment.............. 5,743,165 1,300,976 - 286,331 7,330,472 General equipment............ - - 633,893 - 633,893 10,494,144 1,340,465 1,015,947 403,411 13,253,967 Construction work in progress.. 261,412 29,422 90,440 7,970 389,244 Plant held for future use: Land and land rights......... 19,359 - - - 19,359 Structures and improvements.. 15,944 - - - 15,944 Transmission lines and equipment.................. 746 - - - 746 36,049 - - - 36,049 Gas stored underground - Non current.................. - 1,239 - - 1,239 Utility Plant (A).......... $10,791,605 $1,371,126 $1,106,387 $ 411,381 $13,680,499 Nuclear fuel assemblies (B).... $ 459,465(E)$ - $ - $ - $ 459,465 Less accumulated provision for amortization of Nuclear fuel assemblies (C)........ 389,024(E) - - - 389,024 Net Nuclear Fuel........ $ 70,441 $ - $ - $ - $ 70,441 (A) Neither the total additions nor the total deductions of utility plant, net nuclear fuel, and gas stored underground - non current during the year ended December 31, 1993 amounted to more than 10% of the property, plant and equipment account (including nuclear fuel) and the information required by columns b, c, d and e is therefore omitted. The additions (Col. (c)) to utility plant aggregated $789,068 (including $8,708 allowance for funds used during construction). Retirements (Col. (d)) amounted to $219,894. Other charges (Col. (e)) amounted to $(2,559) consisting of the following: Amortization of Capitalized Leases $ (2,563) Transfer from Non-Utility Property 4 $ (2,559) - 89 - (B) The additions (Col. (c)) to nuclear fuel aggregated $14,092 (including $1,848 allowance for funds used during construction) in uranium and fabrication costs relating to Indian Point 2 - Regions 14 and 15. (C) The additions (Col. (c)) to the accumulated provision for amortization of nuclear fuel assemblies amounted to $20,384. (D) For information as to the Company's methods and rates used in computing the annual provision for depreciation, see Note A to the Financial Statements included herein. (E) Included in the $459,465 and the $389,024 is $328,667 for spent nuclear fuel removed from the reactor and stored at the Indian Point site. - 90 - SCHEDULE V CONSOLIDATED EDISON COMPANY OF NEW YORK, INC. PROPERTY, PLANT AND EQUIPMENT (UTILITY PLANT) (D) YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
COLUMN F COLUMN A BALANCE AT END OF PERIOD Common (Electric- Classification Electric Gas Gas) Steam Total Plant in service: Land and land rights......... $ 96,788 $ 665 $ 29,019 $ 666 $ 127,138 Structures and improvements.. 743,262 8,450 287,448 12,482 1,051,642 Production plant equipment... 2,317,613 - - 99,587 2,417,200 Storage plant equipment...... - 29,645 - - 29,645 Transmission lines and equipment.................. 1,532,927 - - - 1,532,927 Distribution lines, mains and equipment.............. 5,458,281 1,210,313 - 259,023 6,927,617 General equipment............ - - 565,616 - 565,616 10,148,871 1,249,073 882,083 371,758 12,651,785 Construction work in progress.. 263,431 25,705 129,991 7,540 426,667 Plant held for future use: Land and land rights......... 18,808 - - - 18,808 Structures and improvements.. 14,514 - - - 14,514 Transmission lines and equipment.................. 871 - - - 871 34,193 - - - 34,193 Gas stored underground - Non current.................. - 1,239 - - 1,239 Utility Plant (A).......... $10,446,495 $1,276,017 $1,012,074 $ 379,298 $13,113,884 Nuclear fuel assemblies (B).... $ 445,373(E)$ - $ - $ - $ 445,373 Less accumulated provision for amortization of Nuclear fuel assemblies (C)........ 368,641(E) - - - 368,641 Net Nuclear Fuel........ $ 76,732 $ - $ - $ - $ 76,732 (A) Neither the total additions nor the total deductions of utility plant, net nuclear fuel, and gas stored underground - non current during the year ended December 31, 1992 amounted to more than 10% of the property, plant and equipment account (including nuclear fuel) and the information required by columns b, c, d and e is therefore omitted. The additions (Col. (c)) to utility plant aggregated $794,681 (including $11,903 allowance for funds used during construction). Retirements (Col. (d)) amounted to $123,832. Other charges (Col. (e)) amounted to $(3,193) consisting of the following: Amortization of Capitalized Leases $ (2,576) Amortization of Weaver Unsuccessful Exploration Costs (667) Transfer from Non-Utility Property 50 $ (3,193) - 91 - (B) The additions (Col. (c)) to nuclear fuel aggregated $35,220 (including $1,944 allowance for funds used during construction) in uranium and fabrication costs relating to Indian Point 2 - Regions 14 and 15. (C) The additions (Col. (c)) to the accumulated provision for amortization of nuclear fuel assemblies amounted to $32,972. (D) For information as to the Company's methods and rates used in computing the annual provision for depreciation, see Note A to the Financial Statements included herein. (E) Included in the $445,373 and the $368,641 is $280,985 for spent nuclear fuel removed from the reactor and stored at the Indian Point site. /TABLE - 92 - SCHEDULE V CONSOLIDATED EDISON COMPANY OF NEW YORK, INC. PROPERTY, PLANT AND EQUIPMENT (UTILITY PLANT) (D) YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
COLUMN F COLUMN A BALANCE AT END OF PERIOD Common (Electric- Classification Electric Gas Gas) Steam Total Plant in service: Land and land rights......... $ 90,722 $ 665 $ 28,645 $ 694 $ 120,726 Structures and improvements.. 712,062 8,359 282,088 12,434 1,014,943 Production plant equipment... 2,230,217 624 - 98,064 2,328,905 Storage plant equipment...... - 29,672 - - 29,672 Transmission lines and equipment.................. 1,487,363 - - - 1,487,363 Distribution lines, mains and equipment.............. 5,195,136 1,120,574 - 234,029 6,549,739 General equipment............ - - 524,175 - 524,175 9,715,500 1,159,894 834,908 345,221 12,055,523 Construction work in progress.. 270,974 28,044 47,626 9,917 356,561 Plant held for future use: Land and land rights......... 17,627 - - - 17,627 Structures and improvements.. 14,407 - - - 14,407 Transmission lines and equipment.................. 871 - - - 871 32,905 - - - 32,905 Gas stored underground - Non current.................. - 1,239 - - 1,239 Utility Plant (A).......... $10,019,379 $1,189,177 $ 882,534 $ 355,138 $12,446,228 Nuclear fuel assemblies (B).... $ 410,152(E)$ - $ - $ - $ 410,152 Less accumulated provision for amortization of Nuclear fuel assemblies (C)........ 335,668(E) - - - 335,668 Net Nuclear Fuel........ $ 74,484 $ - $ - $ - $ 74,484 (A) Neither the total additions nor the total deductions of utility plant, net nuclear fuel, and gas stored underground - non current during the year ended December 31, 1991 amounted to more than 10% of the property, plant and equipment account (including nuclear fuel) and the information required by columns b, c, d and e is therefore omitted. The additions (Col. (c)) to utility plant aggregated $774,817 (including $11,327 allowance for funds used during construction). Retirements (Col. (d)) amounted to $164,625. Other charges (Col. (e)) amounted to $(2,721) consisting of the following: Amortization of Capitalized Leases $ (2,597) Amortization of Weaver Unsuccessful Exploration Costs (90) Transfer from Non-Utility Property (34) $ (2,721) - 93 - (B) The additions (Col. (c)) to nuclear fuel aggregated $9,127 (including $3,095 allowance for funds used during construction) in uranium and fabrication costs relating to Indian Point 2 - Regions 10, 11, 12 and 13. (C) The additions (Col. (c)) to the accumulated provision for amortization of nuclear fuel assemblies amounted to $17,845. (D) For information as to the Company's methods and rates used in computing the annual provision for depreciation, see Note A to the Financial Statements included herein. (E) Included in the $410,152 and the $335,668 is $280,985 for spent nuclear fuel removed from the reactor and stored at the Indian Point site. /TABLE - 94 - SCHEDULE VI CONSOLIDATED EDISON COMPANY OF NEW YORK, INC. ACCUMULATED DEPRECIATION - UTILITY PLANT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F Other Charges Add (Deduct) Additions Balance at Charged to Removal Balance Beginning Costs and Cost Less At End Description of Period Expenses Retirements Salvage Other of Period Accumulated Depreciation Utility Plant: Electric................ $2,881,521 $297,747 $173,330 $(41,930) $ 4,324(B) $2,968,332 Electric Plant Held for Future Use 7,838 - 76 76 - 7,838 Gas..................... 269,117 32,702 9,147 (3,137) - 289,535 Steam................... 76,100 9,909 4,529 (7,812) - 73,668 Common.................. 226,382 61,935 32,812 (98) 4 255,411 TOTAL $3,460,958 $402,293(A) $219,894 $(52,901) $ 4,328 $3,594,784 (A) Excludes $1,437 representing the amortization of regulatory study costs. (B) Represents the estimated net earnings applicable to the External Trust Fund for Nuclear Decommissioning Costs. /TABLE - 95 - SCHEDULE VI CONSOLIDATED EDISON COMPANY OF NEW YORK, INC. ACCUMULATED DEPRECIATION - UTILITY PLANT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F Other Charges Add (Deduct) Additions Balance at Charged to Removal Balance Beginning Costs and Cost Less At End Description of Period Expenses Retirements Salvage Other of Period Accumulated Depreciation Utility Plant: Electric................ $2,718,236 $284,710 $ 80,533 $(43,564) $ 2,672(C) $2,881,521 Electric Plant Held for Future Use 8,361 - 523 - - 7,838 Gas..................... 248,767 30,309(A) 7,285 (2,674) - 269,117 Steam................... 81,461 9,258 7,848 (6,771) - 76,100 Common.................. 200,893 54,777 27,643 (1,645) - 226,382 TOTAL $3,257,718 $379,054(B) $123,832 $(54,654) $ 2,672 $3,460,958 (A)Excludes $668 representing the amortization of unsuccessful exploration costs which was credited to Gas Plant in Service. (B)Excludes $1,437 representing the amortization of regulatory study costs. (C)Represents the estimated net earnings applicable to the External Trust Fund for Nuclear Decommissioning Costs. /TABLE - 96 - SCHEDULE VI CONSOLIDATED EDISON COMPANY OF NEW YORK, INC. ACCUMULATED DEPRECIATION - UTILITY PLANT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F Other Charges Add (Deduct) Additions Balance at Charged to Removal Balance Beginning Costs and Cost Less At End Description of Period Expenses Retirements Salvage Other of Period Accumulated Depreciation Utility Plant: Electric................ $2,607,405 $270,991 $119,212 $(39,642) $(1,306)(D) $2,718,236 Electric Plant Held for Future Use 8,430 - - (69) - 8,361 Gas..................... 230,162 28,287(A) 7,347 (2,329) (6) 248,767 Steam................... 79,521 8,561 3,317 (3,304) - 81,461 Common.................. 181,285 49,184 34,749 89 5,084 (C) 200,893 TOTAL $3,106,803 $357,023(B) $164,625 $(45,255) $ 3,772 $3,257,718 (A)Excludes $90 representing the amortization of unsuccessful exploration costs which was credited to Gas Plant in Service. (B)Excludes: (1) $1,276 representing the amortization of the Company's Cornwall investment. (2) $1,437 representing the amortization of regulatory study costs. (C)Represents depreciation on property transferred from electric utility plant to common utility plant in May 1991. (D)Represents the estimated net earnings applicable to the External Trust Fund for Nuclear Decommissioning Costs. /TABLE