Annual Report (Form 10-K), fiscal year 1993

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.
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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%
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For information about the Company's generating facilities, see "Electric Facilities - Generating Facilities" in Item 2.



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.
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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.
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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.
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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.
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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




ITEM 6. SELECTED FINANCIAL DATA
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ITEM 7.

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.
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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.
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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).
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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.
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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.
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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.
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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.
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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
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ITEM 8.


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.
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B. Supplementary Financial Information
Selected Quarterly Financial Data for the years ended December 31, 1993 and 1992 (Unaudited)
In the opinion of the Company these quarterly amounts include all djustments, consisting only of normal recurring accruals, necessary for a fair presentation.
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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
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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.
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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.
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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.
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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.
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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.
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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.
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=============================================================== 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. ===============================================================
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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.
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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.
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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 - -----------------------------------------------------------------
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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.
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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.
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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.
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ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
NONE.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Part III is incorporated by reference from the Company's definitive proxy statement for its Annual Meeting of Stockholders to be held on May 16, 1994. The proxy statement is to be filed pursuant to Regulation 14A not later than 120 days after December 31, 1993, the close of the fiscal year covered by this report.
In accordance with General Instruction G(3) to Form 10-K other information regarding the Company's Executive Officers may be found in Part I of this report under the caption "Executive Officers of the Registrant."
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PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1. List of Financial Statements
Consolidated Balance Sheet at December 31, 1993 and
Consolidated Income Statement for the years ended December 31, 1993, 1992 and 1991
Consolidated Statement of Cash Flows for the years ended December 31, 1993, 1992 and 1991
Consolidated Statement of Capitalization at December 31, 1993 and 1992
Consolidated Statement of Retained Earnings for the years ended December 31, 1993, 1992 and 1991
Notes to Consolidated Financial Statements
2. List of Financial Statement Schedules
Property, Plant & Equipment (Utility Plant) (Schedule V)
Accumulated Depreciation - Utility Plant (Schedule VI)
Valuation and Qualifying Accounts (Schedule VIII)
Supplementary Income Statement Information (Schedule X)
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3. List of Exhibits
3(i).1 Restated Certificate of Incorporation filed with the Department of State of the State of New York on December 31, 1984. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1989 as Exhibit 3(a).)
3(i).2 Certificate of Amendment of Restated Certificate of Incorporation filed with the Department of State of the State of New York on May 16, 1988. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1989 as Exhibit 3(b).)
3(i).3 Certificate of Amendment of Restated Certificate of Incorporation filed with the Department of State of the State of New York on June 2, 1989. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1989 as Exhibit 3(c).)
3(i).4 Certificate of Amendment of Restated Certificate of Incorporation filed with the Department of State of the State of New York on April 28, 1992. (Designated in the Company's Current Report on Form 8-K, dated April 24, 1992, as Exhibit 4(d).)
3(i).5 Certificate of Amendment of Restated Certificate of Incorporation filed with the Department of State of the State of New York on August 21, 1992. (Designated in the Company's Current Report on Form 8-K, dated August 20, 1992, as Exhibit 4(e).)
3(ii) By-laws of the Company, effective as of May 31, 1993. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1993 as Exhibit 3.2.)
4.1 Indenture, dated as of April 1, 1946, between the Company and the National City Bank of New York (now Citibank, N.A.), as Trustee. (Designated in Registration Statement No. 2-6932 as Exhibit 7-48.)
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4.2 The following Supplemental Indentures between the Company and the National City Bank of New York (now Citibank, N.A.), as Trustee, which are designated as follows:
Designation Securities Act Securities Exchange Act Supplemental Registration File No. 1-1217 Indenture Statement Exhibit Form Date
(1) Fifteenth 2-13939 2-4 (2) Twenty-eighth 10-K 12/31/90 (3) Twenty-ninth 2-24272 4-4 (4) Thirtieth 2-25736 4-4
4.3 Instrument of Resignation, Appointment and Acceptance, dated as of October 31, 1979, among the Company, Citibank, N.A., and Chemical Bank, Supplemental to Mortgage Trust Indenture, dated as of April 1, 1946. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991 as Exhibit 4(c).)
4.4 Participation Agreement, dated as of August 15, 1985, between New York State Energy Research and Development Authority ("NYSERDA") and the Company. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1990 as Exhibit 4(a)(1).)
4.5 The following Supplemental Participation Agreements supplementing the Participation Agreement, dated as of August 15, 1985, between NYSERDA and the Company, which are designated as follows:
Supplemental Securities Exchange Act Participation Agreement File No. 1-1217 Number Date Form Date Exhibit
(1) First 11/15/86 10-Q 6/30/90 4(a)(2) (2) Second 4/15/87 10-Q 6/30/90 4(a)(3) (3) Third 9/15/87 10-Q 6/30/90 4(a)(4) (4) Fourth 1/1/89 10-Q 6/30/90 4(a)(5) (5) Fifth 7/1/89 10-Q 6/30/90 4(a)(6) (6) Sixth 11/1/89 10-Q 6/30/90 4(a)(7) (7) Seventh 7/1/90 10-Q 6/30/90 4(a)(8) (8) Eighth 1/1/91 10-K 12/31/90 4(e)(8) (9) Ninth 1/15/92 10-K 12/31/91 4(e)(9)
4.6 Participation Agreement, dated as of December 1, 1992, between NYSERDA and the Company. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 4(f).)
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4.7 The following Supplemental Participation Agreements supplementing the Participation Agreement, dated as of December 1, 1992, between NYSERDA and the Company, which are designated as follows:
Supplemental Securities Exchange Act Participation Agreement File No. 1-1217 Number Date Form Date Exhibit (1) First 3/15/93 10-Q 6/30/93 4.1 (2) Second 10/1/93 10-Q 9/30/93 4.3
4.8 Indenture of Trust, dated as of August 15, 1985, between NYSERDA and Morgan Guaranty Trust Company of New York, as Trustee ("Morgan Guaranty"). (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1990 as Exhibit 4(b)(1).)
4.9 The following Supplemental Indentures of Trust supplementing the Indenture of Trust, dated as of August 15, 1985, between NYSERDA and Morgan Guaranty.
Supplemental Securities Exchange Act Indenture of Trust File No. 1-1217 Number Date Form Date Exhibit
(1) First 11/15/86 10-Q 6/30/90 4(b)(2) (2) Second 4/15/87 10-Q 6/30/90 4(b)(3) (3) Third 9/15/87 10-Q 6/30/90 4(b)(4) (4) Fourth 1/1/89 10-Q 6/30/90 4(b)(5) (5) Fifth 7/1/89 10-Q 6/30/90 4(b)(6) (6) Sixth 11/1/89 10-Q 6/30/90 4(b)(7) (7) Seventh 7/1/90 10-Q 6/30/90 4(b)(8) (8) Eighth 1/1/91 10-K 12/31/90 4(g)(8) (9) Ninth 1/15/92 10-K 12/31/91 4(g)(9)
4.10 Indenture of Trust, dated as of December 1, 1992, between NYSERDA and Morgan Guaranty Trust Company of New York, as Trustee ("Morgan Guaranty"). (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 4(i).)
4.11 The following Supplemental Indentures of Trust supplementing the Indenture of Trust, dated as of December 1, 1992, between NYSERDA and Morgan Guaranty.
Supplemental Securities Exchange Act Indenture of Trust File No. 1-1217 Number Date Form Date Exhibit
(1) First 3/15/93 10-Q 6/30/93 4.2 (2) Second 10/1/93 10-Q 9/30/93 4.4
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4.12 Indenture, dated as of December 1, 1990, between the Company and The Chase Manhattan Bank (National Association), as Trustee. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1990 as Exhibit 4(h).)
4.13 The following Forms of the Company's Debentures:
Securities Exchange Act File No. 1-1217 Debenture Form Date Exhibit
9.70%, Series 1990 A 8-K 11/29/90 4 9 3/8%, Series 1991 A 8-K 6/20/91 4 7 3/8%, Series 1992 A 8-K 2/5/92 4(a) 7 5/8%, Series 1992 B 8-K 2/5/92 4(b) 7.60%, Series 1992 C 8-K 2/25/92 4 6 1/2%, Series 1992 D 8-K 8/26/92 4(a) 7 3/8%, Series 1992 E 8-K 8/26/92 4(b) 8.05%, Series 1992 F 8-K 12/15/92 4 6 1/4%, Series 1993 A 8-K 1/13/93 4 6 1/2%, Series 1993 B 8-K 2/4/93 4(a) 6 5/8%, Series 1993 C 8-K 2/4/93 4(b) 6 3/8%, Series 1993 D 8-K 4/7/93 4 5.30%, Series 1993 E 8-K 5/19/93 4(a) 5.70%, Series 1993 F 8-K 5/19/93 4(b) 7 1/2%, Series 1993 G 8-K 6/7/93 4 7 1/8% Series 1994 A 8-K 2/8/94 4
10.1 Agreement dated as of October 31, 1968 among Central Hudson Gas & Electric Corporation, the Company and Niagara Mohawk Power Corporation. (Designated in Registration Statement No. 2-31884 as Exhibit 7.)
10.2 Amendment dated November 23, 1976 to Agreement dated as of October 31, 1968 among Central Hudson Gas & Electric Corporation, the Company and Niagara Mohawk Power Corporation and Additional Agreement dated as of November 23, 1976 between Central Hudson and the Company. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991 as Exhibit 10(b).)
10.3 General Agreement between Orange and Rockland Utilities, Inc. and the Company dated October 10, 1969. (Designated in Registration Statement No. 2-35734 as Exhibit 7-1.)
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10.4 Letters, dated November 18, 1970 and November 23, 1970, between Orange and Rockland Utilities, Inc. and the Company pursuant to Article 14(a) of the aforesaid General Agreement. (Designated in Registration Statement No. 2-38807 as Exhibit 5-3.)
10.5 The Con Edison Thrift Savings Plan for Management Employees and Tax Reduction Act Stock Ownership Plan, as amended. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1989 as Exhibit 10(m).)
10.6 Amendment No. 13, dated August 30, 1990, to the Con Edison Thrift Savings Plan for Management Employees and Tax Reduction Act Stock Ownership Plan. Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1990 as Exhibit 19(b).)
10.7 Amendment No. 14, dated April 2, 1991, to the Con Edison Thrift Savings Plan for Management Employees and Tax Reduction Stock Ownership Plan. (Designated in the Company's Quarterly Report on Form 10-Q for the Quarter ended March 31, 1991 as Exhibit 19(c).)
10.8 Amendment No. 15, dated April 6, 1992, to the Con Edison Thrift Plan for Management Employees and Tax Reduction Act Stock Ownership Plan. (Designated in the Company's Quarterly Report on Form 10-Q for the Quarter ended March 31, 1992 as Exhibit 19(a).)
10.9 Deferred Compensation Plan for the benefit of Trustees of the Company, dated February 27, 1979, and amendments thereto, dated September 19, 1979 (effective February 27, 1979), February 26, 1980, and November 24, 1992 (effective January 1, 1993). (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(i).)
10.10 Employment contract, dated August 24, 1982, between the Company and Arthur Hauspurg, as amended. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991 as Exhibit 10(i).)
10.11 Agreement, dated January 24, 1991, between the Company and Arthur Hauspurg. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1990 as Exhibit 10(l).)
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10.12 Employment Contract, dated May 22, 1990, between the Company and Eugene R. McGrath. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1990 as Exhibit 10.)
10.13 Amendment, dated August 27, 1991, to Employment Contract dated May 22, 1990, between the Company and Eugene R. McGrath. (Designated in the Company's Quarterly Report on Form 10-Q for the Quarter ended September 30, 1991 as Exhibit 19.)
10.14 Amendment, dated August 25, 1992, to Employment Contract, dated May 22, 1990, between the Company and Eugene R. McGrath. (Designated in the Company's Quarterly Report on Form 10-Q for the Quarter ended September 30, 1992 as Exhibit 19.)
10.15 Amendment, dated February 18, 1993, to Employment Contract dated May 22, 1990, between the Company and Eugene R. McGrath. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(o).)
10.16 Amendment, dated August 24, 1993, to Employment Contract dated May 22, 1990, between the Company and Eugene R. McGrath. (Designated in the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1993 as Exhibit 10.1.)
10.17 Agreement, effective March 1, 1989, between Raymond J. McCann and the Company as to salary and deferred compensation. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(p).)
10.18 Amendment, dated February 27, 1990, to Agreement, effective March 1, 1989, between Raymond J. McCann and the Company. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1989 as Exhibit 10(w).)
10.19 Amendment, dated November 27, 1990, to Agreement, effective March 1, 1989, between Raymond J. McCann and the Company. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1990 as Exhibit 10(r).)
10.20 Amendment, dated March 11, 1992, to Agreement, effective March 1, 1989, between Raymond J. McCann and the Company. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as Exhibit 10(p).) - 109 -
10.21 Amendment, dated February 18, 1993, to Agreement, effective March 1, 1989, between Raymond J. McCann and the Company. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(t).)
10.22 Amendment, dated March 10, 1993, to Agreement, effective March 1, 1989, between Raymond J. McCann and the Company. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(u).)
*10.23 Amendment, dated March 10, 1994, to Agreement, effective March 1, 1989, between Raymond J. McCann and the Company.
10.24 The Consolidated Edison Company of New York, Inc. Executive Incentive Plan adopted by the Company's Board of Trustees on March 23, 1982 as amended through March 30, 1989. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as Exhibit 10(q).)
10.25 Amendment and Restatement, dated August 26, 1991 and effective as of April 30, 1991, of The Consolidated Edison Company of New York, Inc. Executive Incentive Plan. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991 as Exhibit 10(r).)
10.26 Amendment and Restatement, dated January 29, 1992 and effective as of December 1, 1991, of The Consolidated Edison Company of New York, Inc. Executive Incentive Plan. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991 as Exhibit 10(s).)
10.27 Conformed copy of The Consolidated Edison Retirement Plan for Management Employees, effective January 1, 1983, as amended through August 16, 1990. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991 as Exhibit 10(t).)
10.28 Amendment No. 15, dated April 1, 1992, to the Consolidated Edison Retirement Plan for Management Employees. (Designated in the Company's Quarterly Report on Form 10-Q for the Quarter ended March 31, 1992, as Exhibit 19(b).)
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10.29 Amendment No. 16, dated December 18, 1992, to the Consolidated Edison Retirement Plan for Management Employees. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(aa).)
10.30 Amendment No. 17, dated March 1, 1993, to the Consolidated Edison Retirement Plan for Management Employees. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(bb).)
10.31 Con Edison Supplemental Retirement Income Plan, adopted July 22, 1987, effective January 1, 1987. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(cc).)
10.32 Copy of memorandum and resolutions adopted by the Company's Board of Trustees on August 23, 1983 authorizing additional compensation for certain officers of the Company and permitting the deferral by the officers of certain compensation. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(dd).)
10.33 Consolidated Edison Company of New York, Inc. Retirement Plan for Trustees, effective as of July 1, 1988. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(ee).)
10.34 Amendment No. 1, dated September 28, 1990, to the Consolidated Edison Company of New York, Inc. Retirement Plan for Trustees. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1990 as Exhibit 19(c).)
10.35 Planning and Supply Agreement, dated March 10, 1989, between the Company and the Power Authority of the State of New York. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(gg).)
10.36 Delivery Service Agreement, dated March 10, 1989, between the Company and the Power Authority of the State of New York. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(gg).)
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10.37 Supplemental Medical Plan for the Benefit of the Company's officers. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as Exhibit 10(aa).)
10.38 The Con Edison Discount Stock Purchase Plan. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as Exhibit 10(bb).)
10.39 Employment Agreement, dated June 25, 1991, between the Company and J. Michael Evans. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1991 as Exhibit 19.)
10.40 Amendment, dated March 29, 1993, to Employment Agreement, dated June 25, 1991, between the Company and J. Michael Evans. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1993 as Exhibit 10.)
10.41 Amendment, dated November 8, 1993, to Employment Agreement, dated June 25, 1991, between the Company and J. Michael Evans. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 as Exhibit 10.2.)
10.42 The Consolidated Edison Retiree Health Program for Management Employees, effective as of January 1, 1993. (Designated in the Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(ll).)
*12 Statement of computation of ratio of earnings to fixed charges for the years ended December 31, 1993, 1992, 1991, 1990 and 1989.
*23 Consent of Price Waterhouse dated March 29, 1994.
*24 Powers of Attorney of each of the persons signing this report by attorney-in-fact.
Exhibits listed above which have been filed with the Securities and Exchange Commission pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, and which were designated as noted above, are hereby incorporated by reference and made a part of this report with the same effect as if filed with the report.
____________________ * Filed herewith - 112 -
(b) Reports on Form 8-K:
During the quarter ended December 31, 1993, the Company filed a Current Report on Form 8-K, dated December 16, 1993, reporting (under Item 5) the indictment against the Company discussed under the caption "Gramercy Park" in Item 3 of this report.
The Company also filed a Current Report on Form 8-K, dated February 8, 1994, reporting (under Item 5) the sale of $150 million aggregate principal amount of the Company's 7 1/8% Debentures, Series 1994 A, due February 15, 2029.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.
Date: March 29, 1994 By Raymond J. McCann Raymond J. McCann Executive Vice President & Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Signature Title
March 29, 1994 Eugene R. McGrath* Chairman of the Board, President, Chief Executive Officer and Trustee (Principal Executive Officer)
March 29, 1994 Raymond J. McCann* Executive Vice President & Chief Financial Officer and Trustee (Principal Financial Officer)
March 29, 1994 Carl W. Greene* Senior Vice President - Accounting and Treasury (Principal Accounting Officer)
Gordon J. Davis* Trustee Arthur Hauspurg* Trustee Frederick P. Rose* Trustee Robert G. Schwartz* Trustee Richard A. Voell* Trustee Myles V. Whalen, Jr.* Trustee
March 29, 1994 *By Raymond J. McCann Attorney-in-Fact Raymond J. McCann