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 . . . . . . . . . . . . . . . . . . . . . 18 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, an approximately 660 square mile 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 1994, electric, gas and steam operating revenues were 80.6 percent, 14.0 percent and 5.4 percent, respectively, of the Company's operating revenues.
INDUSTRY SEGMENTS
For information on operating revenues, expenses and income for the years ended December 31, 1994, 1993 and 1992, 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 1994 or 80.6 percent of total Company operating revenues. The percentages were 81.9 and 82.4, respectively, in the two preceding years. Electricity sales in the Company's service area in 1994, 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 2.0 percent from 1993, after increasing 3.3 percent in 1993 and decreasing 2.7 percent in 1992. After adjusting for variations, principally weather, electricity sales volume increased 1.5 percent in 1994, increased 1.0 percent in 1993 and decreased 0.3 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 occurred.
In 1994, 80.0 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, 66.7 percent was to commercial customers, 2.7 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 1990-1994 are shown below:
1990 1991 1992 1993 1994 Generated: Fossil-Fueled . . . . . 59.8% 51.4% 42.3% 35.5% 30.9% Nuclear (Indian Point 2) 13.3% 9.8% 20.4% 14.8% 18.4% Total Generated . . . 73.1% 61.2% 62.7% 50.3% 49.3% Firm Purchases: NYPA . . . . . . . . . 8.1% 8.9% 4.8% 6.0% 1.3% Hydro-Quebec . . . . . 3.3% 1.9% 2.9% 4.3% 4.8% IPPs . . . . . . . . . 0.9% 1.0% 8.9% 11.9% 12.9% Other Purchases . . . . . 14.6% 27.0% 20.7% 27.5% 31.7% 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 1994, including the Company's shares of generating capacity at Roseton and Bowline Point, totaled 11.3 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 1995. The Company anticipates covering the balance of its 1995 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 1994, the Company burned approximately 110,900 mdth of gas for the production of electricity and steam, including 18,500 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 1994 fuel oil requirements by about 17.8 million barrels. The Company expects to continue to have substantial amounts of gas available in 1995 for the production of electricity and steam.
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DISTILLATE OIL. The Company's estimated 1995 requirements for distillate oil for gas turbine fuel are about 170,000 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.
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.
Under the Energy Policy Act of 1992, the DOE is to collect a special annual assessment, for a period of 15 years, from utilities that have purchased enriched uranium from the DOE. The assessments are to be used to pay a portion of the costs to decontaminate and decommission DOE's gaseous diffusion facilities used to enrich uranium for commercial and defense purposes. The Company has paid assessments attributable to Indian Point Units 1 and 2 for 1993, 1994 and 1995. The 1995 assessment was approximately $2.6 million. Future amounts are subject to review and adjustment for inflation. The Company's liability at December 31, 1994 for future installments of this assessment is $30.7 million, of which $28.1 million is classified as non- current. The Company is recovering these costs through its electric fuel adjustment clause.
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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. A scheduled refueling and maintenance outage commenced on February 4, 1995, and is expected to conclude before the beginning of the summer. The last previous 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.
See "Liquidity and Capital Resources - Nuclear Fuel Disposal" in Item 7 and "Nuclear Decommissioning" in Note A to the financial statements in Item 8.
Under a 1985 Federal law, by January 1996 New York State is to provide for permanent disposal of low-level radioactive wastes (LLRW) generated at Indian Point 1 and 2. The Company is providing for on-site storage of LLRW as required until New York State establishes an interim storage or permanent disposal facility or adopts some other LLRW management method. There is no domestic licensed disposal facility currently accepting LLRW from New York State waste generators for permanent disposal.
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. In January 1995, a new State administration took office. It is not known what effect, if any, this change in administration will have on State regulatory policy.
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. For additional information about the Company's rates, see "Liquidity and Capital Resources - 1992 Electric Rate Settlement Agreement, 1994 Electric Rate Increase Filing and Gas and Steam Rate Increases" in Item 7.
In 1994, a controversy arose over the rates the Company charges to religious organizations. State law requires electric and gas utilities to charge religious organizations rates that do not exceed those charged to residential customers. Due mainly to the complexity of the Company's rates, a significant number of religious institutions, for the most part small store-front type
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accounts, had been served under generally higher commercial rates. In December 1994, the Company and the Attorney General executed a settlement under which the Company admitted no wrongdoing but agreed to provide refunds amounting to $5 to $6 million to affected religious organizations and transfer affected customers to the appropriate rates. In a related matter, a customer claiming to be a church has sued the Company in Federal court. The plaintiff claims that it has operated as a religious organization since 1983 and has been charged commercial rates for electric service. The plaintiff is seeking $500 million for the class members in this purported class action. The lawsuit is in its early stages.
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. In July 1994, the Administrative Law Judges issued a recommended decision. The judges generally accepted the parties' resolution of financial integrity issues, but rejected the agreement on the method of calculating the cost of common equity. Instead, the judges recommended their own method, which is more sensitive to changes in interest rates than the traditional PSC method. A PSC decision is expected in 1995.
For several years the PSC has required utilities to favor demand side resources in evaluating the cost-effectiveness of such resources by deeming their cost to be reduced by savings from avoiding adverse environmental impacts ("externalities"). Currently, the required reduction is 1.6 cents per kilowatt-hour. 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 a separate proceeding, the Company, together with other members of the New York Power Pool, entered into a settlement agreement under which the utilities would procure about 300-400 MW of renewable resources provided that these resources could be obtained at an acceptable price. The
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settlement agreement was recently "approved" by the PSC except that the PSC expanded the Company's obligations to purchase electric capacity. The Company is withdrawing from the settlement agreement because it believes that the PSC's substantial modification of the agreement constitutes rejection of the agreement.
In March 1993, the PSC instituted a proceeding to examine competitive opportunities in the energy marketplace. In July 1994, the PSC issued an order in this case establishing general guidelines for "flexible" rates. Under tariffs designed pursuant to these guidelines, utilities may negotiate discount rates with customers who have options for obtaining electric service from other sources such as through the installation of on-site generation. The loss of revenue due to the discount must be shared between ratepayers and shareholders. In August 1994, the PSC initiated a second phase of this proceeding to investigate the transition to a competitive market in electricity service. In December 1994, the PSC issued an order proposing guiding principles for this transition. The proposed principles, among other things, assert that vertically integrated electric utilities are "incompatible with effective wholesale or retail competition" and indicate that utilities "should have a reasonable opportunity to recover prudent and verifiable expenditures and commitments made pursuant to their legal obligations as long as they are cooperating in furthering all of these principles". In March 1995, the Company, other electric utilities and other parties to this proceeding filed comments on the proposed guidelines. The Company believes that the principles raise important issues which will require more extensive review than they have been afforded, particularly in the case of the Company's complex electric system. The PSC is expected to finalize its transition guidelines in 1995.
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. In December 1994, the PSC issued an order establishing regulatory policies and guidelines for gas utilities regarding the pricing and provision of bundled and unbundled sales and transportation services. Utilities were required to implement a number of these policies in a compliance filing and the balance no later than their general rate filings. The order also provided for the institution of a separate proceeding to examine the implementation of a performance-based gas purchase mechanism and the Commission's principle of affordability for core customers (i.e., those customers who could be disadvantaged in a competitive gas market).
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STATE ENERGY PLAN. In October 1994, the New York State Energy Planning Board, comprised of the PSC Chairman and the Commissioners of the New York State Energy Office and the Department of Environmental Conservation, released a final 1994 State Energy Plan which is designed to provide "an intelligent framework for evaluating the proper course for energy policy, environmental protection and economic development. . . 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." Under New York State law, any energy-related decisions of State agencies must be reasonably consistent with the findings and recommendations of the Plan.
COMPETITION
For information concerning competition in the electricity and gas business, see "Liquidity and Capital Resources - Electric Capacity Resources 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.
ENVIRONMENTAL MATTERS AND RELATED LEGAL PROCEEDINGS
GENERAL. During 1994, the Company's capital expenditures for environmental protection facilities and related studies were approximately $24 million. The Company estimates that such expenditures will amount to approximately $19 million in 1995 and $18 million in 1996. These amounts include capital expenditures in 1995 and 1996 required to comply with the consent decree discussed under "Environmental Matters - DEC Settlement" in Note F to the financial statements in Item 8.
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" in Item 7 and Notes A and F to the financial statements in Item 8.
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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 additional information about Superfund, see "Superfund" in Item 3
ITEM 3. LEGAL PROCEEDINGS
SUPERFUND
The following is a discussion of significant proceedings pending under Superfund or similar statutes involving sites for which the Company has been asserted to have a liability. The list is not exhaustive and additional proceedings may arise in the future. For a further discussion of claims and possible claims against the Company under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (Superfund) and the estimated liability accrued for certain Superfund claims, see "Environmental Matters and Related Legal Proceedings - Superfund" in Item 1, and "Environmental Matters - Superfund" in Note F to the financial statements in Item 8.
MAXEY FLATS NUCLEAR DISPOSAL SITE. The United States Environmental Protection Agency (EPA) advised the Company by letter, dated November 26, 1986, that it was a potentially responsible party (PRP) under Superfund for the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky. The site is owned by the State of Kentucky and was operated as a disposal facility for low level radioactive waste
- 31 - from 1963 through 1977 by the Nuclear Engineering Corporation(now known as U.S. Ecology Corporation). EPA's letter alleges that various radionuclides and organic chemicals have been released from the site into the environment. In September 1991, the EPA issued its Record of Decision ("ROD") for the site cleanup program. Phase one of the program requires, among other things, the removal, treatment and on-site disposal of the leachate that has accumulated in the site's waste burial trenches and the installation of an impervious cover over the waste burial trench area of the site, monitoring wells and erosion control and surface water drainage systems. Phase two requires a 100-year stabilization period, with periodic monitoring and maintenance of the cover, followed by installation of a permanent cap.
In March 1995, the EPA, de minimis PRPs, large private party PRPs, large federal agency PRPs and Kentucky entered into a settlement agreement with respect to the costs of the cleanup program. Subject to court approval, the settlement agreement is to be implemented pursuant to a consent decree. The Company has agreed to be responsible for approximately 1.9 percent of the costs allocable to the large private party PRPs. The large private party PRPs have agreed to implement phase one of the program and any corrective actions required, during the ten years following completion of phase one, to meet the performance standards established in the ROD, and to share the costs of those activities with the large Federal agency PRPs. Also, if during this ten-year period the EPA determines that horizontal flow barriers are required, the large party PRPs will be required to share the cost of such barriers. The large party private PRPs are not responsible for any costs after the ten year period expires. Kentucky will implement and fund the phase two program. The Company's share of the cleanup costs is estimated to be about $500,000. In addition, if horizontal flow barriers are required, depending on their extent, the Company would be obligated to pay an estimated $10,000 to $100,000.
EASTERN DIVERSIFIED METALS SITE. The EPA advised the Company by letter, dated March 5, 1987, that it is one of 118 PRPs under Superfund for the investigation and cleanup of the Eastern Diversified Metals Site in Hometown, Pennsylvania. Between 1966 and 1977, Diversified Industries used the site for a copper wire salvaging operation which involved the disposal of shredded wire insulation in a waste pile located on the site. The EPA alleges that various metals and organic chemicals have been released from the waste pile into the environment. A preliminary ranking list appended to the EPA's letter indicates that the Company is responsible for less than 0.03 percent of the waste insulation material at the site. An EPA-approved site study has been performed by the site owner and a PRP allegedly responsible for about 77 percent of the waste. The Company has accepted EPA's offer to settle the Company's liability for this site by paying $11,000.
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CURCIO SCRAP METAL SITE. The EPA advised the Company, in a letter received on August 11, 1987, that it had documented the release of hazardous substances into the environment at the site of Curcio Scrap Metal, Inc. in Saddle Brook, New Jersey, and that the EPA had information indicating that the Company sent hazardous substances (PCBs) to the site. The Company provided the EPA with records that indicated that the Company sold scrap electric transformers to a metal broker who in turn sold them to the owner of the site. A site study indicated that chemical contamination has occurred on a portion of the site. Elevated concentrations of PCBs and various organic compounds and metals have been detected in the soil and PCBs and organic compounds and metals have also been detected in the shallow groundwater beneath the site.
On September 30, 1991, the EPA issued a Unilateral Administrative Order which requires the Company and three other PRPs to commence a soil cleanup of this site pursuant to the EPA's Record of Decision, dated June 28, 1991. This soil cleanup has been completed. The EPA has not yet formulated a cleanup program for the groundwater under and around the Curcio site. The Company's estimate of the cost of the additional groundwater studies is $400,000. The EPA has only designated five PRPs for this site and, as a result, the Company will be expected to pay a major share of the cleanup costs.
METAL BANK OF AMERICA SITES. The EPA advised the Company by letter dated October 26, 1987 that it has reason to believe that the Company was a supplier of used transformers to Metal Bank of America Inc.'s recycling sites in Philadelphia during the late 1960s and thereafter. One of the sites has been placed on the EPA's national priority list under Superfund as a result of a leak in a storage tank containing PCBs. The EPA alleges that PCBs have been found in the ground water, soils and in the sediments of the adjoining Delaware River. The Company has provided the EPA with documents which indicate that the Company sold approximately 81 scrap transformers to a broker who, in turn, delivered them to the site. Under a steering committee participation agreement, the Company is responsible for 1.48% of the expense of the remedial investigation and feasibility study, which has been completed under an EPA administrative consent order. The Company's share of the cost of the study was about $80,000. The study identified various alternative site clean-up programs ranging in cost from $1.8 million to $90 million. The EPA has requested some additional study work, the results of which it will consider before selecting the clean up program.
NARROWSBURG SITE. In 1987, the New York State Attorney General notified the Company that he has evidence that the Company is a PRP under Superfund for hazardous substances that have been released at the Cortese landfill in Narrowsburg,
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Sullivan County, New York. The Cortese landfill is listed on the EPA's national priorities list. Company records indicate that drums containing non-nuclear waste were shipped from Indian Point to the Cortese landfill for disposal. The Attorney General has commenced an action under Superfund in the United States District Court for the Southern District of New York against the Cortese site owner and operator and SCA Services, an alleged transporter of hazardous substances to the site. On January 17, 1989, SCA Services commenced a third-party action for contribution against the Company and five other parties whose chemical waste was allegedly disposed of at the site. In 1990, SCA served a second amended third-party complaint in which it sued the Company and 27 other third-party defendants for contribution. The Company and SCA Services have reached a settlement of the third-party action under which the Company's sole responsibility will be to pay 6% of the first $25 million of remedial costs at the site. SCA Services has agreed to indemnify the Company for any other remedial costs that it has to pay. The EPA recently selected the clean up program for the site. The program is estimated to cost about $12 million to implement.
CARLSTADT SITE. On August 20, 1990, the Company was served with a third-party complaint in a Superfund cost contribution action for a former waste solvent and oil recycling facility located in Carlstadt, New Jersey. The complaint, which is pending before the United States District Court for the District of New Jersey, alleges that the Company shipped 120,000 gallons of waste oil to this site and that the Company is one of several hundred parties who are responsible under Superfund for the study and cleanup of the facility. The plaintiffs in the action, which include a group of former customers of the facility, have completed a $3 million remedial investigation and feasibility study for the site. Plaintiffs estimate that 7 to 15 million gallons of waste solvents and oil were recycled at the site and based on this estimate, the Company's share of the cleanup costs would be about one percent. The costs of the cleanup alternatives that were evaluated in the remedial investigation and feasibility study range from $48 million to $321 million. In 1990, the EPA selected an interim remedy, expected to cost about $13 million, to control release from the site while the EPA evaluates and develops a final cleanup remedy. The interim remedy calls for, among other things, the construction of a slurry wall around the site and an infiltration barrier over the site.
HELEN KRAMER LANDFILL SITE. In September 1991, Orange and Rockland Utilities, Inc. (O&R) was served with third-party complaints in consolidated Superfund cost recovery contribution actions for the Helen Kramer Landfill Site in Mantau, New Jersey.
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The complaints, which are pending before the United States District Court for the District of New Jersey, allege that, in 1974, Marvin Jonas, Inc. transported hazardous substances for O&R and disposed of those substances in the Helen Kramer Landfill. Preliminary investigation by O&R indicates that waste materials generated during the construction of the Bowline Point generating station were hauled and disposed of by Marvin Jonas, Inc. in 1974. The Company owns a two-thirds interest in Bowline Point. O&R, which operates Bowline Point, owns the remaining one-third interest. Bowline Point liabilities are shared by the Company and O&R in accordance with their respective ownership interests. The EPA has commenced cleanup of this site and the total site cleanup cost is estimated at $150 million. Assuming that all of the Bowline wastes alleged to have been disposed of at the site were so disposed of, they represent about 0.4% of the total volume of waste-in at the site. On this basis, the Company's share of the cleanup cost is estimated at $400,000.
GLOBAL LANDFILL SITE. The Company has been designated a PRP under Superfund and the New Jersey Spill Compensation and Control Act (Spill Act) for the study and cleanup of the Global Landfill Site in Old Bridge, New Jersey. This 65-acre municipal and industrial waste landfill is included on the Superfund National Priorities List and is being administered by the New Jersey Department of Environmental Protection and Energy (NJDEPE) pursuant to an agreement between the EPA and the State of New Jersey.
The Company provided EPA with records indicating that it had disposed of approximately ten cubic yards of waste asbestos at the site in February 1984. In August 1989, the NJDEPE served the Company with a Spill Act directive that required the Company and 40 other PRPs to fund a $1.5 million remedial investigation and feasibility study for the site. A PRP Group was formed and the Group entered into a settlement agreement and an administrative consent order with NJDEPE that, among other things, required the PRP Group's members to contribute $500,000 towards the cost of the study. The Company's share of the PRP Group's payment to the NJDEPE was $5,000.
In February 1991, the EPA and the NJDEPE proposed a $30 million interim remedy for the site. This remedy calls for the installation of gas and leachate collection and treatment systems at the landfill and the construction of an impervious cover over the landfill (Phase I). It also calls for further studies to determine the alternatives for addressing groundwater and wetlands contamination in the vicinity of the landfill (Phase II). In March 1991, the NJDEPE served the Company with a second Spill Act Directive that requires the Company and the other
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members of the PRP Group to pay for the implementation of the Phase I remedy for the site. The PRP Group negotiated a settlement of this directive with the NJDEPE and the Company's share of the cost is estimated at $150,000.
CHEMSOL SITE. By letter dated December 20, 1991, the EPA advised the Company that it had documented the release of hazardous substances at the Chemsol Site in Piscataway, New Jersey and that it had reason to believe that the Company sent waste materials to the site during the 1960 to 1965 period. In response to EPA's demand for records, including any relating to Cenco Instruments Corp., the Company submitted to EPA records of payments to Central Scientific Company, a Division of Cenco Instruments Corp. during the 1960-1965 period. The Company is unable at this time to determine either the purpose of the payments to Central Scientific Company or the connection of that company to the site. The EPA has not designated the Company as a PRP and has not yet selected a final cleanup program for the site. However, the EPA has selected an interim remedy, expected to cost about $8 million, for the site groundwater contamination and has ordered several designated PRPs to implement that remedy.
ECHO AVENUE SITE. In December 1987, the DEC classified the Company's former Echo Avenue Substation Site in New Rochelle, New York as an "Inactive Hazardous Waste Disposal Site." The basis for this classification was the presence of PCBs in the soil and in the buildings on the site. Although the Company has cleaned up the PCBs on the site, the DEC requires a thorough site survey before it will remove the site from the Inactive Hazardous Waste Disposal Site list. Under a consent order with the DEC a new site survey was done and remedial action taken. The cost to the Company of this additional work was $213,000. The Company intends to demolish its building on this site, and expects to incur approximately $1 million in additional clean up expenses.
In January 1992, the owners of Echo Bay Marina filed suit in Federal court alleging that PCBs were being discharged from the Echo Avenue site into Long Island Sound. Plaintiffs are seeking a declaration that the Company is in violation of the Clean Water Act, civil penalties of $25,000 per day for each violation, remediation costs, an injunction against further discharges, legal fees, and compensatory damages of $24 million. In December 1994, the court dismissed plaintiffs claims for property damage, including loss of business. Pretrial discovery on the remaining claims is continuing.
C&D RECYCLING SITE. On July 13, 1992, the Company received a letter from the EPA stating that it is a PRP with respect to the C&D Recycling site located in Foster Township, Luzerne County, Pennsylvania. In 1979, the Company retained C&D Recycling Company to recover copper and lead from a shipment of
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30,560 pounds of scrap electric cable. It appears that the bulk of the scrap cable sent to this site was generated by AT&T Nassau Metals, a subsidiary of AT&T. The total cleanup cost is estimated at $12.5 million. In March 1995, the EPA advised the Company, that based on the information currently available to it, the Company is responsible for 0.0297% of the scrap cable at this site. The EPA has offered to negotiate with the Company and other de minimis PRPs to settle their liability for this site.
PCB TREATMENT, INC., SITES. On September 30, 1994, the Company received a letter from the EPA indicating that it had been identified as a PRP for the PCB Treatment, Inc. ("PTI") Sites in Kansas City, Kansas and Kansas City, Missouri. The sites--a vacant, five-story building at 45 Ewing Street (K.C., Kansas) and a partially-occupied, seven-story building at 2100 Wyandotte Street (K.C., Missouri)-- were used by PTI from 1982 until 1987 for the storage, processing, and treatment of PCB- containing electric equipment, dielectric oils, and materials. According to the EPA, the buildings' floor slabs and ceilings and the soil areas outside the buildings' loading docks are contaminated with PCBs.
On October 21, 1994, the EPA held a PRP meeting for the sites and requested the PRPs to form a steering committee and to consider conducting a cleanup program for the sites under the auspices of the Toxic Substances Control Act, or failing that, performing a Superfund cleanup for the sites. At the meeting, the EPA provided the Company with waste manifests and other documents indicating that the Company was responsible for 141,090 pounds (about 0.7%) of the approximately 20.3 million pounds of PCB-containing equipment, oil, and materials that were shipped to the 2100 Wyandotte Street Site. The EPA has not yet completed compiling the waste manifests and shipment records for the 45 Ewing Street Site. The PRPs are attempting to organize for the purpose of developing and implementing acceptable cleanup programs for the sites. Efforts are also being made to elicit the participation of various federal agencies, which in the aggregate are responsible for about 5.7 million pounds of the PCB-containing equipment, oil, and materials that were shipped to the 2100 Wyandotte Street Site.
PELHAM MANOR SITE. Prior to 1968, the Company and its predecessor companies operated a manufactured gas plant (MGP) on a site located in Pelham Manor, Westchester County. Soil and groundwater tests by the current owners and lessees indicate the presence of hazardous substances which are associated with the MGP process. The Company has agreed to participate with the site owners and lessees in further site studies to develop and implement a cleanup plan that will be acceptable to the DEC.
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ASTORIA SITE. The Federal Resource Conservation and Recovery Act delegates to the states licensing authority for PCB storage. As a condition to renewal by the DEC of the Company's permit to store PCBs at the Company's Astoria generating station, the Company is required to conduct a site investigation and, where necessary, a remediation program. The site investigation commenced in April 1994 and will continue through 1995. The cost of the investigation is estimated at $2 million. The extent and cost of the remediation program will depend on the results of the investigation.
HUNTS POINT SITE. In September 1994, the City of New York notified the Company that it had discovered coal tar on the site of a former Company manufactured gas plant in the Hunts Point section of the Bronx. The Company had manufactured gas at that location prior to its sale of the site to the City in the 1960s. The Company has agreed to conduct a site study and to develop and implement a remediation program. However, the Company has not agreed to pay costs not associated with the Company's use of the site. The Company is unable at this time to estimate its exposure to liability with respect to this site.
TOXIC SUBSTANCES CONTROL ACT
In November 1994, BCF Oil Refining, Inc., a processor and re-refiner of used oil products and waste containing oil, brought suit in federal court against the Company and four transporters of waste oil products alleging that the defendants (primarily the Company) caused PCB contaminated waste to be shipped to BCF thereby contaminating its facilities. In addition to the remediation of BCF's facilities under the Federal Toxic Substances Control Act, the suit seeks compensatory damages of not less than $12.5 million from all the defendants and additional punitive damages of not less than $12.5 million from the Company. Pre-trial discovery began in January 1995 and should continue into 1996.
GRAMERCY PARK
On August 19, 1989, a Company steam main exploded in the Gramercy Park area of Manhattan, releasing debris containing asbestos into that area. The Company took responsibility for the asbestos cleanup and most of the cost of that cleanup was covered by the Company's insurance.
A Federal Grand Jury in the Southern District of New York issued an indictment in December 1993, which was superseded by an indictment issued in April 1994, charging the Company and two of its retired employees with criminal acts relating to the reporting of the release of asbestos from the steam main explosion. The April 1994 indictment contained eight counts.
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On October 31, 1994, the Company pled guilty to four counts of the eight count indictment. Sentencing is expected on March 31, 1995, at which time a fine of up to $500,000 on each of the four counts, and up to five years probation, could be imposed.
DEC PROCEEDING
For information about this proceeding, see "Environmental Matters - DEC Settlement" in Note F to the financial statements in Item 8 and "Results of Operation - Other Operations and Maintenance Expenses" in Item 7.
ASBESTOS LITIGATION
For a discussion of asbestos and suits against the Company involving asbestos, see "Environmental Matters and Related Legal Proceedings - Asbestos" in Item 1, and "Environmental Matters - Asbestos Claims" in Note F to the financial statements in Item 8. The following is a discussion of the significant suits involving asbestos in which the Company has been named a defendant. The listing is not exhaustive and additional suits may arise in the future.
MASS TORT CASES. Numerous suits have been brought in New York State and Federal courts against the Company and many other defendants for death and injuries allegedly caused by exposure to asbestos at various Company premises. Many of these suits have been disposed of without any payment by the Company, or for immaterial amounts. The amounts specified in the remaining suits, including the Moran v. Vacarro suit and the United States of America v. Con Edison suit discussed below, total billions of dollars, but the Company believes that these amounts are greatly exaggerated, as were the claims already disposed of.
MORAN, ET AL. V. VACARRO, ET AL. On May 9, 1988, the Company was served with a complaint in an action in the New York State Supreme Court, New York County, in which approximately 184 Company employees and their union alleged that the employees were exposed to dangerous levels of asbestos as a result of alleged intentional conduct of supervisory employees. Each of the employee plaintiffs seeks $1 million in punitive damages, unspecified additional compensatory damages, and to enjoin the Company from violating EPA regulations and exposing employees to asbestos without first taking certain safety measures. On May 16, 1988, the complaint was amended to add a claim by each employee plaintiff for $1 million in damages for mental distress. In November 1988, the complaint was amended to add four additional employee plaintiffs. On July 9, 1990, the complaint was amended to add the spouses of 131 plaintiffs as additional plaintiffs and to remove the union as a plaintiff. Each spouse
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seeks medical monitoring, $1 million for emotional distress and $1 million for punitive damages. On January 19, 1995, the court dismissed the claims of the employee plaintiffs, leaving employee spouses as the only plaintiffs.
UNITED STATES OF AMERICA V. CON EDISON. This suit was commenced on March 7, 1994 by the United States in the United States District Court for the Southern District of New York. The complaint alleges that the Company violated hazardous emissions provisions of the Federal Clean Air Act in connection with asbestos removal activities at the Company's Waterside generating station during 1989. The complaint seeks civil penalties of $25,000 per day per violation and injunctive relief. The Company has entered into a consent decree with the Federal government under which the Company will pay $100,000 to settle this action. The consent decree is subject to court approval.
RATE PROCEEDINGS
For information concerning proceedings relating to the Company's rates, see "Regulation and Rates" in Item 1.
NUCLEAR FUEL DISPOSAL
Reference is made to the information under the caption "Liquidity and Capital Resources - Nuclear Fuel Disposal" in Item 7 for information concerning a suit brought by the Company and a number of other utilities against the United States Department of Energy. The suit is entitled Northern States Power Co., et al. v. Department of Energy, et al.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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EXECUTIVE OFFICERS OF THE REGISTRANT
The names of the executive officers of the Company together with their ages and the positions and offices with the Company held by them as of March 1, 1995, the respective dates they became executive officers and their business experience during the past five years (or since they became executive officers, if earlier) are set forth below. Under the Company's By-laws, officers of the Company are elected to hold office until the next election of Trustees (directors) of the Company and until their respective successors are chosen and qualify, subject to removal at any time by the Company's Board of Trustees.
Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an and Date First Became an Executive Officer, Executive Officer If Longer
Eugene R. McGrath - 53 9/90 to present - Chairman of Chairman of the Board, the Board, President, Chief President, Chief Executive Executive Officer and Trustee Officer and Trustee; 2/89 to 8/90 - President, Chief 9/1/78 Operating Officer and Trustee 10/87 to 1/89 - Executive Vice President - Operations and Trustee 9/82 to 9/87 - Executive Vice President - Central Operations 3/81 to 8/82 - Senior Vice President - Power Generation 9/78 to 2/81 - Vice President - Power Generation
Raymond J. McCann - 60 2/89 to present - Executive Vice Executive Vice President President and Chief Financial and Chief Financial Officer, and Trustee Officer, and Trustee; 10/87 to 1/89 - Executive Vice 5/15/72 President, Finance and Law, and Trustee 8/80 to 9/87 - Executive Vice President - Division Operations 6/77 to 8/80 - Vice President - Manhattan Division 6/76 to 5/77 - Vice President - Accounting and Treasury 3/74 to 5/76 - Controller 5/72 to 3/74 - General Auditor
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Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer
J. Michael Evans - 49 9/91 to present - Executive Vice Executive Vice President President - Central Operations - Central Operations; 7/89 to 8/91 - Senior Vice 9/1/91 President and Chief Operating Officer - Kansas City Power and Light
Charles F. Soutar - 58 2/89 to present - Executive Vice Executive Vice President President - Customer Service - Customer Service; 3/85 to 1/89 - Executive Vice 9/1/77 President - Central Services 5/80 to 2/85 - Senior Vice President - Construction, Engineering and Environmental Affairs 9/77 to 4/80 - Vice President - Central Services
Stephen B. Bram - 52 12/94 to present - Senior Vice Senior Vice President; President 8/1/79 9/94 to 11/94 - Vice President 12/87 to 8/94 - Vice President - Nuclear Power 9/82 to 11/87 - Vice President - Fossil Power 7/80 to 8/82 - Vice President - Central Substation, Systems Operations and Technical Services 8/79 to 6/80 - Vice President - Central Substation and System Operations
Thomas J. Galvin - 56 2/93 to present - Senior Vice Senior Vice President President - Central Services - Central Services; 6/89 to 1/93 - Senior Vice 6/1/78 President - Administration 8/86 to 5/89 - Vice President - Employee Relations 3/83 to 7/86 - Vice President - Purchasing 6/78 to 2/83 - General Auditor
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Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer
Carl W. Greene - 59 9/94 to present - Senior Vice Senior Vice President President - Financial and - Financial and Regulatory Regulatory Matters Matters; 7/92 to 8/94 - Senior Vice 6/1/76 President - Accounting and Treasury 6/82 to 6/92 - Vice President and Controller 6/76 to 5/82 - Controller
Edward W. Livingston - 63 9/92 to present - Senior Vice Senior Vice President President 3/1/79 6/89 to 8/92 - Senior Vice President - Public Affairs 3/79 to 5/89 - Vice President - Government & Community Relations
Mary Jane McCartney - 46 10/93 to present - Senior Vice Senior Vice President President - Gas Operations - Gas Operations; 2/93 to 10/93 - Vice President 12/1/90 - Gas Supply 7/92 to 1/93 - Vice President - Gas Business Development 12/90 to 6/92 - Vice President - Queens 2/89 to 11/90 - Assistant Vice President - Environmental Affairs and Fuel Supply
Horace S. Webb - 54 9/92 to present - Senior Vice Senior Vice President President - Public Affairs - Public Affairs; 1/90 to 8/92 - Vice President 9/1/92 - Communications and Public Affairs, Hoechst Celanese Corp.
T. Bowring Woodbury, II - 57 6/89 to present - Senior Vice Senior Vice President President and General Counsel and General Counsel; 6/1/89
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Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer
Archie M. Bankston - 57 6/89 to present - Secretary and Secretary and Associate Associate General Counsel General Counsel; 1/74 to 5/89 - Secretary and 1/7/74 Assistant General Counsel
John F. Cioffi - 61 7/92 to present - Treasurer Treasurer; 6/87 to 6/92 - Assistant Vice 7/1/92 President
Lawrence F. Travaglia - 56 3/93 to present - General Auditor General Auditor; 10/80 to 2/93 - Assistant 3/1/93 Treasurer
Robert A. Bell - 61 6/81 to present - Vice President Vice President - Research & Development Research & Development; 6/1/81
Arthur J. Bennett - 59 3/93 to present - Vice President Vice President - Brooklyn Customer Service - Brooklyn Customer 6/91 to 2/93 - Vice President Service; - Transportation & Stores 3/1/83 3/83 to 6/91 - Vice President - Bronx Division
David G. Bosland - 58 6/91 to present - Vice President Vice President - Staten Island Customer Service - Staten Island 3/83 to 6/91 Vice President Customer Service; - Transportation & Stores 3/1/83
Kevin M. Burke - 44 3/93 to present - Vice President Vice President - Corporate Planning - Corporate Planning; 3/90 to 2/93 - Vice President 12/1/87 - Brooklyn Customer Service 12/87 to 2/90 - Vice President - Construction
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Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer
Richard P. Cowie - 48 3/94 to present - Vice President Vice President - Employee Relations - Employee Relations; 2/91 to 2/94 - Director - Central 3/1/94 Customer Service 9/90 to 1/91 - Assistant to the Executive Vice President - Customer Service 9/86 to 8/90 - Director - Credit & Collections
Robert F. Crane - 58 3/94 to present - Vice President Vice President - Fuel Supply - Fuel Supply; 10/93 to 2/94 - Vice President 12/1/82 - Gas Supply 2/93 to 10/93 - Vice President - Gas Business Development 4/91 to 1/93 - Vice President - Gas Supply 12/84 to 3/91 - Vice President - Manhattan Division 12/82 to 11/84 - Vice President - Queens Division
George J. Delaney - 59 12/78 to present - Vice President Vice President - Westchester Customer Service - Westchester 9/74 to 11/78 - Vice President Customer Service; - Bronx Division 5/28/74 5/74 to 8/74 - Vice President - Staten Island Division
Robert W. Donohue, Jr. - 52 2/94 to present - Vice President Vice President - Queens Customer Service - Queens Customer Service; 3/90 to 1/94 - Vice President 3/1/90 - Construction 12/84 to 2/90 - Assistant Vice President - Electrical Distribution
Charles J. Durkin, Jr. - 51 12/93 to present - Vice President Vice President - Fossil Power - Fossil Power; 1/88 to 12/93 - Vice President 9/1/82 - Engineering 9/82 to 12/87 - Vice President - System and Transmission Operations
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Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer
Jacob Feinstein - 51 4/91 to present - Vice President Vice President - System & Transmission - System & Transmission Operations Operations; 12/88 to 3/91 - Plant Manager 4/1/91
Joan S. Freilich - 53 9/94 to present - Vice President, Vice President, Controller Controller and Chief Accounting and Chief Accounting Officer Officer; 7/92 to 8/94 - Vice President 12/1/90 and Controller 12/90 to 6/92 - Vice President - Corporate Planning 12/89 to 11/90 - Assistant Vice President - Corporate Planning
David F. Gedris - 46 2/94 to present - Vice President Vice President - Maintenance and Construction - Maintenance and 7/92 to 1/94 - Assistant Vice Construction; President - Power Generation 2/1/94 Maintenance 3/90 to 6/92 - Assistant Vice President - Steam Operations 11/89 to 2/90 - Project Manager - Steam Operations
Garrett W. Groscup - 54 2/94 to present - Vice President Vice President - Energy Services - Energy Services; 4/91 to 1/94 - Vice President 12/1/82 - Manhattan Customer Service 1/88 to 3/91 - Vice President - System & Transmission Operations 12/82 to 12/87 - Vice President - Engineering
William A. Harkins - 49 2/89 to present - Vice President Vice President - Planning and Inter-Utility - Planning and Inter- Affairs Utility Affairs; 2/1/89
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Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer
Paul H. Kinkel - 50 12/93 to present - Vice President Vice President - Engineering - Engineering; 12/87 to 12/93 - Vice President 5/24/83 - Fossil Power 5/83 to 11/87 - Vice President - Construction
Laurence V. Kleinman - 52 9/86 to present - Vice President Vice President - Corporate Communications and - Corporate Communications Public Information and Public Information; 9/1/86
John A. Nutant - 59 2/94 to present - Vice President Vice President - Manhattan Customer Service - Manhattan 7/92 to 1/94 - Vice President Customer Service; - Queens Customer Service 5/27/80 9/86 - 6/92 - Vice President - Purchasing 7/80 to 8/86 - Vice President - Environmental Affairs 5/80 to 6/80 - Vice President
James P. O'Brien - 47 3/94 to present - Vice President Vice President - Information Resources - Information Resources; (formerly Systems and 3/1/94 Information Processing) 6/89 to 2/94 - Assistant Vice President - Employee Relations
Stephen E. Quinn - 48 9/94 to present - Vice President Vice President - Nuclear Power - Nuclear Power; 8/88 to 8/94 - General Manager 9/1/94 - Nuclear Power Generation
Edwin W. Scott - 56 6/89 to present - Vice President Vice President and Deputy and Deputy General Counsel General Counsel; 6/1/89
Minto L. Soares - 58 6/91 to present - Vice President Vice President - Bronx Customer Service - Bronx Customer Service; 11/88 to 5/91 - Plant Manager 6/1/91
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Business Experience Name, Age, Positions and During the Past Five Years Offices with the Company or Since Becoming an, and Date First Became an Executive Officer, Executive Officer If Longer
Alfred R. Wassler - 50 3/94 to present - Vice President Vice President - Purchasing, Transportation - Purchasing, Trans- and Stores portation and Stores; 7/92 to 2/94 - Vice President 8/15/80 - Purchasing 8/80 to 6/92 - Treasurer
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ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock ($2.50 par value) is the only class of common equity of the Company. The Common Stock is traded on the New York, Chicago and Pacific Stock Exchanges.
On January 24, 1995, the Board of Trustees of the Company declared a quarterly dividend of 51 cents per share of Common Stock payable on March 15, 1995 to holders of record on February 15, 1995.
ITEM 6.
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 $245.2 million at December 31, 1994 compared with $36.8 million at December 31, 1993 and $282.5 million at December 31, 1992. The Company's cash balances reflect, among other things, the timing and amounts of external financing.
In the first quarter of 1994, pursuant to its amended dividend reinvestment plan, the Company issued 478,016 shares of common stock for $14.7 million. 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 February 1994 the Company issued $150 million of 35-year debentures. In July 1994 the Company issued $150 million of five-year floating rate debentures; the interest rate is reset quarterly, based on the addition of 0.1875 percent to the three-month LIBOR (London Interbank Offered Rate). In December 1994 the Company issued $100 million of 35-year tax-exempt debt through the New York State Energy Research and Development Authority (NYSERDA). The balance of 1994 capital requirements was met from internally generated funds.
In April 1993 the Company issued $101 million of 35-year tax-exempt debt through NYSERDA. The Company issued 373,227 shares of common stock in December 1993 for $11.9 million pursuant to the Company's amended dividend reinvestment plan.
In June 1993 the Company issued $380 million of 30-year debentures of which approximately $80 million was used to meet 1993 capital requirements and the balance was used to retire higher-cost debt securities. 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.
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 issued 5,550,000 shares of common stock for $156.8 million.
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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.
In 1994, 1993 and 1992 the Company borrowed from banks for short periods. For 1995 the Company has arranged for bank credit lines amounting to $150 million. Borrowings thereunder would bear interest at prevailing market rates.
Customer accounts receivable, less allowance for uncollectible accounts, amounted to $440.5 million, $459.3 million and $424.3 million at December 31, 1994, 1993 and 1992, respectively. In terms of equivalent days of revenue outstanding, these amounts represented 27.1, 27.6 and 26.7 days, respectively.
Regulatory accounts receivable, amounting to $26.3 million, $97.1 million and $167.9 million at December 31, 1994, 1993 and 1992, respectively, include accruals under the three-year electric rate agreement effective April 1, 1992 for differences in electric sales revenues from forecast levels (the "ERAM" accrual), incentives and "lost revenues" related to the Company's Enlightened Energy program, incentives related to customer service activities and 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.
The following is a summary of the balances and activity in regulatory accounts receivable in 1994:
The balance in regulatory accounts receivable at December 31, 1994 will be billed to customers during 1995 and 1996. The incentives are discussed below under "1992 Electric Rate Settlement Agreement."
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Deferred charges for Enlightened Energy program costs amounted to $170.2 million, $140.1 million and $80.8 million at December 31, 1994, 1993 and 1992, respectively. These costs are being recovered in rates, as discussed below under "1992 Electric Rate Settlement Agreement."
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 1994 and 1993, and 2.4 percent in 1992.
Interest coverage on the SEC book basis was 4.58, 4.19 and 3.93 times for 1994, 1993 and 1992, respectively. The improvement in interest coverage in 1994 and 1993 was due to 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 and AA- by Standard & Poor's. In September 1994, following the filing by the New York State Public Service Commission's (PSC) staff of its recommendations with respect to the Company's 1994 electric rate filing, discussed below, Moody's placed its rating of the Company under review for possible downgrade and Standard & Poor's placed its rating of the Company on CreditWatch with negative implications.
Cash flows from operating activities for years 1992 through 1994 were as follows:
----------------------------------------------------------------- (Millions of Dollars) 1994 1993 1992 ---------------------------------------------------------------- Net cash flows from operating activities $1,250 $1,025 $ 962 Less: Dividends on common and preferred stock 505 490 475 ----------------------- Net after dividends $ 745 $ 535 $ 487 -----------------------------------------------------------------
Net cash flows in 1994 were favorably affected by incentive billings of $92.3 million, ERAM billings of $28.9 million, and labor productivity improvements resulting in costs estimated to be approximately $51 million less than reflected in rates. Net cash flows in 1993 were favorably affected by incentive billings of $47.5 million, ERAM billings of $104.8 million, and labor productivity improvements resulting in costs estimated to be approximately $29 million less than reflected in rates. Such amounts in 1995 are expected to be lower than in 1994. See the table on the preceding page for balances in regulatory accounts receivable at December 31, 1994 to be billed to customers in future periods.
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CAPITAL REQUIREMENTS. The following table compares the Company's capital requirements for the years 1992 through 1994 and estimated amounts for 1995 and 1996:
(a) See discussion below of electric rate agreements. (b) Assumes recovery as proposed by the Company of the portion of these costs not already in rates. See "1994 Electric Rate Increase Filing," below. (c) See Note A to the financial statements for discussion of nuclear decommissioning costs. (d) Does not include refundings in advance of maturity. For details of securities maturing after 1996, see Note B to the financial statements.
The Company expects to finance its capital requirements, including amounts for maturing securities, for 1995 and 1996 from internally generated funds and external financings of about $400 million, most, if not all, of which would be debt issues.
In 1995 and 1996 the Company may, from time to time, make short-term borrowings.
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ELECTRIC CAPACITY RESOURCES. Electric energy sales in the Company's service area increased, after adjustment for variations, principally weather, by 1.5 percent in 1994 and 1.0 percent in 1993. However, electric peak load growth in the Company's service area continues at approximately 50 megawatts (MW), or about one-half of one percent, per year. The low growth in peak load is largely a result of the Company's Enlightened Energy program, introduced in 1990, which helps our customers purchase and install energy-efficient equipment and encourages the efficient use of energy resources. This program has been modified for future years, based on the Company's experience to date, so as to obtain the same energy efficiency benefits at lower program costs.
In response to federal and state regulatory policies and requirements for utilities to contract with independent power producers (IPPs), the Company by December 1992 had entered into contracts for the supply of approximately 2,700 MW of capacity from facilities of IPPs scheduled to come into service in the 1990s. Plants with 1,670 MW of such capacity are in commercial operation, and the related charges are reflected in the Company's rates. Most of the balance of the IPP capacity (net of the terminations discussed below) is expected to be in operation in 1995. See "1994 Electric Rate Increase Filing," below.
Because of a decline in peak load growth rates and changing conditions in the marketplace, the need for long term power contracts is continuing to be re-evaluated. Excess generating capacity is projected for the Northeast and the market price of power has decreased significantly. Over the past two years, the Company has entered into agreements for the termination of several IPP contracts involving approximately 720 MW at a cost of $211 million (exclusive of interest) to be paid over a period of several years. The Company expects to recover these termination costs from its electric customers and most of these costs are already reflected in rates. See "1994 Electric Rate Increase Filing," below. The Company's electric customers are expected to realize a savings, net of the termination costs, of about $2 billion over the life of the contracts, based on current estimates of future market prices for power.
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On May 31, 1994 the Company gave notice of termination to the New York Power Authority (NYPA) with respect to a 20-year contract for the purchase of 780 MW from Hydro-Quebec. Initial deliveries were to begin in April 1999. The terms of the contract, which the Company had entered into in February 1990, had become uneconomic compared to power available in the electric marketplace. The Company is exploring with Hydro-Quebec an extension of its existing summer diversity contract, set to expire in 1998, for a period of up to five years. Under the current contract, the Company purchases 780 MW of capacity and associated energy from Hydro-Quebec during the summer months.
Based on current resource planning, the Company does not expect to add any long-term capacity resources to its system during the next twenty years.
COMPETITION. No federal or New York State law presently requires the Company to permit other sellers of electricity to use the Company's facilities to make sales to the Company's retail customers in New York City and Westchester County. However, in recent years, federal and New York State legislation have promoted the development of non-utility electric generating capacity and competition at the wholesale level for electric capacity and energy sales. A number of states, including New York, are now considering whether to require electric utilities to deliver electricity from other sellers directly to electricity consumers, referred to as "retail wheeling."
The most likely targets for retail wheeling are large industrial customers and, to a lesser extent, governmental customers. Almost all of the Company's customers are residential or commercial, with sales to industrial customers comprising less than 3 percent of the Company's 1994 electric sales. Most governmental customers in the Company's service area are, and for many years have been, served by the NYPA. If retail wheeling were permitted, the Company's large-usage commercial customers also might be targets. In any case, competition would be mitigated by the limited transmission capacity of the existing facilities for importing power and energy into the Company's service area. Nevertheless, in a competitive environment, the Company would be disadvantaged by the relatively high cost of its in-City generating facilities and the Company's substantial commitments under its IPP contracts. These contracts extend for various periods, up to 2034. The Company estimates that during the next five years under the IPP contracts relating to the 1,670 MW of capacity already in commercial operation, it will be obligated (assuming performance by the IPPs) to make annual capacity-related payments of approximately $180 million. In addition to these capacity payments, one of these contracts
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requires the Company (assuming performance by the IPP) to make payments for energy during the next five years which will be about $170 million per year higher priced than the Company's alternative sources of energy.
The Company's strategy for dealing with competition includes ongoing cost reduction, increased productivity, pursuit of growth opportunities and strengthening of customer relations by providing value-added services. Another major element of the strategy which the Company is promoting with government and regulators is a "level playing field" on which the Company could compete without unfair burdens of regulation or taxation. For example, taxes other than federal income taxes represent 21 cents of every dollar the Company bills customers, and one of the Company's largest operating expenses.
The PSC is conducting a generic "competitive opportunities" proceeding to investigate the potential impact of competition on the State's utilities, as well as the appropriate regulatory response to such competition. Among the issues being considered are the current vertically integrated structure of the industry, and the extent to which, in a competitive environment, rate regulation should continue to assure recovery of all costs prudently incurred. If the outcome of this proceeding were to adversely affect the eligibility of New York electric utilities to apply Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," significant write-downs of assets could be required.
In January 1995 a new State administration took office. It is not known what effect, if any, this change in administration will have on State regulatory policy.
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, by $251.2 million (5.0 percent) in April 1993 and by $55.2 million (1.1 percent) in April 1994. The increase in April 1993 included $138.4 million for recovery of accrued ERAM amounts. The increase in April 1994 reflects a return to customers of $6.0 million under ERAM procedures.
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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.
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 the 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 each of the first two rate years, the twelve months ended March 31, 1993 and 1994 (and for the first nine months of the third rate year, the nine months ended December 31, 1994), the Company's rate of return on electric common equity, excluding incentives and labor productivity, was below the thresholds for sharing with customers.
Incentive Provisions. The rate agreement provided that the Company could 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, or incur penalties for failing to achieve minimum objectives. For calendar years 1994, 1993 and 1992, the Company accrued benefits of $77.8 million (including $25.8 million related to prior years' achievements), $36.2 million and $28.8 million, respectively, before federal income tax, for the Enlightened Energy incentive. For calendar years 1994, 1993 and 1992, the Company earned $6.8 million, $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 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 1994, 1993 and 1992, the Company earned $31.8 million, $26.9 million
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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 are generally recovered over a five-year period. Unrecovered balances earn an approved rate of return. The incentive for Enlightened Energy is 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.
Electric Revenue Adjustment Mechanism. The settlement introduced a 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 in 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 1994 the Company set aside $63.7 million to be returned to customers for revenue overcollections under the ERAM. In 1993 the Company accrued $10.9 million of additional revenues under the ERAM compared with $130.1 million accrued under the ERAM in 1992.
1994 ELECTRIC RATE INCREASE FILING. In April 1994 the Company filed with the PSC for a $191.3 million electric rate increase to become effective April 1, 1995. On September 9, 1994 the PSC staff filed a recommendation for an electric rate reduction of $199 million, and on September 23, 1994 the Company revised its electric rate increase request to $223 million. On December 30, 1994 the PSC's Administrative Law Judges (ALJs) hearing the case issued a recommended decision which, if adopted by the PSC, would provide for a $23 million, one-year rate increase.
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On January 19, 1995 the Company, the PSC staff and other parties to the rate case announced that they had reached an agreement in principle resolving the issues in the case. On February 3, 1995 the Company and the PSC staff signed a detailed written agreement reflecting this resolution. The agreement has been submitted to the PSC for approval, and the PSC is expected to act on the agreement in March 1995.* If approved, the agreement would be effective for a three-year period beginning April 1, 1995 but could be extended. The principal features of the proposed new settlement agreement are as follows:
Limited Increases in Base Revenues. There will be no increase in base electric revenues for the first rate year of the agreement (the twelve months ending March 31, 1996). However, differences between actual and projected amounts for certain expense items during the first rate year will be reconciled and deferred for charging or crediting to customers. These items include pension and retiree health and life insurance expenses, costs incurred under IPP contracts, and certain demand side management and renewable energy expenses. Property tax differences will be similarly reconciled and charged or credited to customers, except that the Company will absorb (or retain) 14 percent of any property tax increase or decrease from the forecast amounts.
For each of the second and third rate years, rates will be changed to provide for projected increases or decreases in each year in pension and retiree health and life insurance costs, IPP contract costs, and demand side management and renewable energy costs. During the second and third rate years, differences between the projected and actual amounts of these items, and property taxes, will be reconciled and deferred for charging or crediting to customers as in the case of the first rate year, including the 86 percent/14 percent sharing between customers and the Company of property tax changes from the levels projected for the first rate year.
Unlike previous multi-year rate settlements, there will be no increases in rates to cover general escalation, wage and salary increases or carrying costs on increased utility plant investment. The rates effective April 1, 1995 will give customers the benefit of labor productivity achieved during the term of the 1992 electric rate settlement. Under the proposed settlement agreement, subject to the earnings sharing provisions discussed below, the Company will retain the benefit of further productivity gains achieved in excess of the productivity gain forecast for the first rate year.
_______________ * At its public session on March 29, 1995, the PSC indicated its general approval of the agreement, with some changes in detail. The specific terms of the PSC's order are not yet available.
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Return on Equity and Equity Ratio. The settlement is premised on a rate of return on common equity of 11.1 percent in the first rate year and assumes a 52 percent common equity ratio throughout the term of the agreement. Base rates in the second and third rate years will be adjusted for changes in the allowed return on equity. The allowed rate of return on equity is to be adjusted for each succeeding rate year by adding or subtracting one-half of the change in 30- year Treasury bond rates from a January/February 1995 base to or from 11.1 percent. The maximum change in the rate of return from the previous rate year is 100 basis points (one percent).
Costs for debt and preferred stock will not be updated from the levels projected for the first rate year.
Earnings Sharing. Following each rate year the Company's actual return on equity will be calculated, using actual capitalization ratios and debt and preferred stock costs, but excluding any earnings from the incentives discussed below. The Company will retain 100 percent of any earnings up to 50 basis points above the allowed rate of return for that rate year. The Company will retain 50 percent of earnings exceeding the allowed rate of return by more than 50 basis points but not more than 150 basis points and the balance will be deferred for customer benefit. The Company will retain 25 percent of earnings that exceed the allowed rate of return by more than 150 basis points; one third of the balance will be deferred for customer benefit and two-thirds will be applied to reduce rate base balances in a manner to be determined by the Company.
Contested Power Purchases and IPP Termination Costs. A major portion of the rate decrease which had been proposed by the PSC staff was based on proposed disallowances of costs associated with the Company's largest IPP contract, with Sithe Energies, Inc., and with a contract with NYPA relating to its Blenheim- Gilboa pumped-storage plant. The settlement agreement resolves the staff allegations by providing that "no future ratemaking disallowances based on grounds of imprudence [relating to the Sithe or Blenheim-Gilboa contracts]... will be permitted."
The settlement agreement also provides for full recovery by the Company of all IPP contract termination costs incurred to date, and permits the Company to petition the PSC to defer the costs of new IPP contract terminations or modifications, if any, during the term of the settlement agreement.
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Incentive Provisions. The settlement agreement, like the 1992 electric rate settlement, includes provisions which permit the Company to earn additional incentive amounts, not subject to the earnings sharing provisions, by attaining certain objectives for the Company's Enlightened Energy program, fuel costs, and customer service. There would also be penalties for failing to achieve minimum objectives, and there is a penalty-only incentive mechanism designed to encourage the Company to maintain its high level of service reliability.
The Company estimates that it could earn incentive amounts equivalent to a maximum of 22 basis points of additional equity rate of return (or a maximum penalty of 22 basis points) under the Enlightened Energy provision; a maximum incentive (or penalty) of 50 basis points under the fuel incentive; and a maximum incentive of 10 basis points (or a maximum penalty of 15 basis points) under the customer service incentive. Under the service reliability incentive mechanism, the maximum penalty will be the equivalent of 5 basis points of common equity return. In general, opportunities for earning incentives will be more limited under the new settlement agreement than under the 1992 electric rate settlement.
Partial Pass-Through Fuel Adjustment Clause. The fuel incentive is implemented through the PPFAC, which is continued with certain modifications from the 1992 electric rate settlement. Under the PPFAC, monthly targets are set for fuel and purchased power costs. The Company will collect, as an incentive, 30 percent of any savings in actual costs below the target amount, and must bear 30 percent of any excess of actual costs over the target. For each rate year of the settlement there will be a $35 million cap on the maximum incentive or penalty, with a "sub-cap" (within the $35 million cap) of $10 million for costs associated with generation from the Company's Indian Point 2 nuclear unit.
Modified ERAM. The settlement agreement continues, in modified form, the ERAM introduced in the 1992 electric rate settlement. Under the ERAM, the Company's electric revenues are adjusted, up or down, to offset variances of actual electric revenues from those forecast. Such variances typically result from factors, such as weather and the Enlightened Energy program, which alter consumption patterns. The new settlement agreement adds to the ERAM a revenue per customer (RPC) mechanism which excludes from adjustment those variances in the Company's electric revenues which result from changes in the number of customers in each electric service classification. A forecast amount of revenue per customer (the RPC Factor) is developed for each service classification by dividing the forecast amount of revenue expected from that service classification by the average number of customers expected in that classification during the first
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rate year. At the end of each rate year, the RPC Factor for each service classification is multiplied by the actual average number of customers in that classification for that rate year. The result is compared with the actual revenues from that service classification. The RPC Factor for the following rate year will be adjusted to return any surplus, or collect any deficiency, to or from customers in that classification during the following rate year. The RPC Factors will also be adjusted for the second and third rate years to reflect any increase or decrease in allowed base revenues (e.g. because of a change in allowed return on equity). Thus, the Company will retain additional revenues attributable to added customers, but will bear the revenue shortfall resulting from lost customers, while other variances from forecast revenues will be deferred for subsequent collection from, or return to, customers, and will not affect the Company's earnings.
The RPC mechanism will not apply to delivery service for NYPA.
Nuclear Decommissioning Expense and Other Depreciation. Revenues for each rate year include an annual allowance of $23.1 million for the cost of decommissioning the Company's nuclear units (including $1.8 million for the non-nuclear portions). This represents an increase over the $14.8 million decommissioning expense allowance (including $3.1 million for the non-nuclear portions) under the 1992 electric rate settlement.
The Company's request for additional depreciation allowances for retired generation facilities and acceleration of recovery of other production plant was deferred by the ALJs for consideration as part of the PSC's generic "competitive opportunities" proceeding, and is not reflected in this settlement.
Extension of Agreement. The proposed settlement stipulates that if the Company abstains from filing for a general electric rate increase to take effect at the end of the three-year period, the operation of the settlement agreement will be extended beyond March 31, 1998, the end of the third rate year. In such event the provisions for limited rate changes, adjustment of equity return, earnings sharing, incentives, and modified ERAM will continue in effect until changed by the PSC.
Restrictions on Further Changes. In general, the settlement will not permit further changes in the Company's base electric rates during the settlement period (April 1, 1995 - March 31, 1998), except as provided in the settlement. However, as in prior settlements, there are limited exceptions, for the protection of both the Company and the customers, including exceptions for certain tax and regulatory changes.
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As noted above, the settlement is subject to the approval of the PSC.* While the PSC may condition its approval on further changes, the Company is not obliged to accept the settlement with any such changes that are not agreeable to the Company.
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 settlements were 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 were to be shared equally with customers. For the first and second rate years, the twelve months ended September 30, 1993 and 1994, 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 and second rate years 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 and $3.6 million in 1994.
In October 1994 the PSC approved three-year rate agreements for gas and steam services. The agreements provide for gas and steam rate increases in the first rate year, the twelve months ending September 30, 1995, of $7.7 million (0.9 percent) and $9.9 million (3.0 percent), respectively, and a methodology for rate changes in the second and third rate years. For both services, the October 1994 increases reflect a 10.9 percent rate of return on common equity and a 52.0 percent common equity ratio. The agreements contain "excess earnings" provisions giving stockholders the benefit of 100 percent retention of any earnings between 10.9 percent and 11.65 percent, and 50 percent sharing with customers above 11.65 percent. The gas agreement contains incentive (or penalty) mechanisms (not subject to the "excess earnings" provisions), equivalent to approximately 85 basis points of return on common equity.
_______________ * See footnote on page 58.
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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. 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 Company has spent approximately $23 million to comply with the Phase I limitations. 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. New York and nine other member states of the Northeast Ozone Transport Commission have entered into a Memorandum of Understanding which calls for the states to adopt more stringent nitrogen oxide emissions limits for RACT Phases II and III, effective in 1999 and 2003, respectively. The Company estimates that the cost of compliance with these phases could approximate $180 million.
NUCLEAR FUEL DISPOSAL. The Company has a contract with the United States Department of Energy (DOE) which provides that, in return for payments being made by the Company to the DOE pursuant to the contract, the DOE, starting in 1998, will take title to the Company's spent nuclear fuel, transport it to a Federal repository and store it permanently. Notwithstanding the contract, the DOE has announced that it is not likely to have an operating permanent repository before 2010. The DOE has also taken the position that it is not obligated to begin accepting the spent fuel until it has an appropriate facility for such purpose. In June 1994 the Company and a number of other utilities petitioned the United States Court of Appeals for the District of Columbia for a declaratory judgment that the DOE is unconditionally obligated to begin accepting the spent fuel by 1998, an order directing the DOE to implement a program enabling it to begin acceptance of spent fuel by 1998, and, if warranted, appropriate relief for the financial burden to the utilities resulting from the DOE's delay. The Company estimates that it now has adequate on-site capacity until 2005 for interim storage of its spent fuel. If the DOE does not begin accepting spent fuel by 2005, absent regulatory or technological developments, the Company expects that it will require additional on-site or other spent fuel storage facilities. Such additional facilities would require regulatory approvals. In the event that the Company is unable to make appropriate arrangements for the storage of its spent fuel, the Company would be required to curtail the operation of its Indian Point 2 nuclear unit. See discussion of decommissioning in Note A to the financial statements.
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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 $2.98 in 1994, $2.66 in 1993 and $2.46 in 1992. The average number of common shares outstanding for 1994, 1993 and 1992 was 234.8 million, 234.0 million and 231.1 million, respectively.
Earnings for 1994, 1993 and 1992 reflect electric, gas and steam rate increases, incentives earned and labor productivity retained under the provisions of the 1992 electric rate agreement, discussed above. There were no incentives accrued in 1994 under the October 1994 gas rate agreement.
OPERATING REVENUES AND FUEL COSTS. Operating revenues in 1994 and 1993 increased from the prior year by $107.7 million and by $332.5 million, respectively. The principal increases and decreases in revenues were:
The decrease in fuel billings in 1994 reflects decreases in the unit costs of both purchased power and fuel used to produce electricity. The increase in fuel billings in 1993 reflects an increase in the unit cost of fuel used to produce electricity and steam and increased electric sales due to weather variations. Fuel costs in 1994 and 1993 were also affected by the greater availability in 1994 than 1993 of lower-cost nuclear generation from the Company's Indian Point 2 unit. The cost of gas per therm was 10.4 percent lower in 1994 than in 1993 but was 11.5 percent higher in 1993 than in 1992.
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Electricity sales volume in the Company's service territory increased 2.0 percent in 1994 and 3.3 percent in 1993. Gas sales volume to firm customers increased 3.9 percent in 1994 and 0.6 percent in 1993. Transportation of customer-owned gas decreased 12.1 percent in 1994 and 17.9 percent in 1993, 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 increased 4.4 percent in 1994 and was unchanged in 1993.
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 1.5 percent in 1994 and 1.0 percent in 1993. Similarly adjusted, gas sales volume to firm customers increased 1.6 percent in 1994 and 3.9 percent in 1993, and steam sales volume increased 0.6 percent in 1994 and decreased 0.1 percent in 1993. 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 decreased 1.5 percent in 1994 and increased 5.4 percent in 1993. The decrease in 1994 reflects lower production expenses principally due to the refueling and maintenance outage of the Indian Point 2 nuclear unit in 1993 but none in 1994. The decrease was offset by costs in connection with the settlement of an environmental proceeding (discussed below) and higher health insurance costs. For 1993 the increase reflects the cost of 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.
In November 1994 the Company settled a New York State Department of Environmental Conservation (DEC) civil administrative proceeding against the Company. Pursuant to the settlement, the Company has paid a $9 million penalty and contributed $5 million to an environmental projects fund. The penalty was charged to miscellaneous income deductions ($2 million in 1994 and $7 million in prior years). The payment to the environmental projects fund was charged to operations and maintenance expense in 1994. See Note F to the financial statements for additional information about the settlement.
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TAXES OTHER THAN FEDERAL INCOME TAX. At $1.1 billion, taxes other than federal income tax remain one of the Company's largest operating expenses. The principal components and variations in operating taxes were:
The reductions in property taxes in 1994 and 1993 reflect decreases in the share of total New York City property taxes borne by the Company. Under the terms of the current electric, gas and steam rate agreements the difference between property taxes included in rates and actual property taxes is being deferred for future collection from or return to customers. The increase in state and local taxes on revenues in 1993 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 $2.3 million in 1994 and $9.7 million in 1993. For 1994 the decrease reflects lower interest income accrued on ERAM revenue under the 1992 electric rate agreement. For 1993 the decrease reflects a lower level of temporary cash investments and lower interest rates. The decrease in both years also reflects the DEC settlement.
NET INTEREST CHARGES. Interest on long-term debt increased in 1994 and 1993 by $7.3 million in each year principally as a result of new debt issues offset to a large extent by the effect of debt refundings.
FEDERAL INCOME TAX. Federal income tax increased $73.6 million in 1994 and $44.5 million in 1993 reflecting the changes each year in income before tax and in tax deductions. For the rate treatment of the increase in the corporate income tax rate from 34 percent to 35 percent effective January 1, 1993, see Note G to the financial statements.
February 28, 1995
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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 70
Consolidated Balance Sheet at December 31, 1994 71-72 and 1993
Consolidated Income Statement for the years 73 December 31, 1994, 1993 and 1992
Consolidated Statement of Cash Flows for the 74 years ended December 31, 1994, 1993 and 1992
Consolidated Statement of Capitalization at 75-76 December 31, 1994 and 1993
Consolidated Statement of Retained Earnings 77 for the years ended December 31, 1994, 1993 and 1992
Notes to Consolidated Financial Statements 78-96
The following Schedule is filed as a "Financial Statement Schedule" pursuant to Item 14 of this report:
Schedule VIII - Valuation and Qualifying Accounts 97-99
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, 1994 and 1993 (Unaudited)
In the opinion of the Company these quarterly amounts include all adjustments, 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 68 present fairly, in all material respects, the financial position of Consolidated Edison Company of New York, Inc. and its subsidiaries at December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 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.
Price Waterhouse LLP
Price Waterhouse LLP 1177 Avenue of the Americas New York, N.Y. 10036
February 28, 1995
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The accompanying notes are an integral part of these financial statements.
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*Represents total authorized shares of cumulative preferred stock, $100 par value, including preferred stock subject to mandatory redemption.
The accompanying notes are an integral part of these financial statements.
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*This rate is reset quarterly. For the fourth quarter of 1994 it was 5.625%.
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The accompanying notes are an integral part of these financial statements.
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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 accounting 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 9.4 percent in 1994 and 9.5 percent in 1993 and 1992. 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 3.2 percent in 1994 and 3.1 percent in 1993 and 1992. Depreciation expense includes the amortization of certain deferred charges authorized by the PSC.
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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, 1994 and 1993 was:
----------------------------------------------------------------- (Thousands of Dollars) 1994 1993 ----------------------------------------------------------------- Bowline Point: Plant in service $196,065 $195,546 Construction work in progress 10,351 2,400 Roseton: Plant in service 141,487 139,798 Construction work in progress 4,283 1,204 -----------------------------------------------------------------
The Company's share of accumulated depreciation for the Roseton station at December 31, 1994 and 1993 was $61.6 million and $57.9 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.
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.
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Accumulated decommissioning provisions at December 31, 1994 and 1993, which include earnings on funds externally invested, are as follows:
----------------------------------------------------------------- Amounts Included in Accumulated Depreciation -------------------------- (Millions of Dollars) 1994 1993 ----------------------------------------------------------------- Nuclear $102.2 $ 86.0 Non-Nuclear 53.7 50.6 Total $155.9 $136.6 -----------------------------------------------------------------
The Company currently provides annual expense allowances of $11.7 million and $3.1 million, respectively, for decommissioning 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 at approximately $300 million in 1993 dollars. In 1994 a site-specific decommissioning study was prepared for both the Indian Point 2 and the retired Indian Point 1 nuclear units. Based on this study, the estimated decommissioning cost in 1993 dollars is approximately $657 million, of which $252 million is for extended on-site storage of spent nuclear fuel, and (using a 3.25 percent annual escalation factor) approximately $1,372 million in 2016, the assumed midpoint for decommissioning expenditures. Under the proposed 1995 electric rate settlement agreement, effective April 1995, the Company will revise the annual decommissioning expense allowance for the nuclear and non-nuclear portions of the plants to $21.3 million and $1.8 million, respectively, to fund the future estimated costs of decommissioning. The annual expense allowance assumes a 6 percent after-tax annual return on fund assets.
The Financial Accounting Standards Board is currently reviewing the utility industry's accounting treatment of nuclear decommissioning costs.
NUCLEAR FUEL. Nuclear fuel assemblies and components are amortized to operating expenses based on the quantity of heat produced for the generation of electricity. Fuel costs also include a provision for payments to the U.S. Department of Energy for the future off-site storage of the spent fuel, based on the kilowatt-hours of electricity generated. Nuclear fuel costs are recovered in revenues through base rates or through the fuel adjustment clause.
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LEASES. In accordance with Statement of Financial Accounting Standards (SFAS) No. 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.
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 1992 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 to the extent provided in rates.
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.
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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 1992 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.
REGULATORY ACCOUNTS RECEIVABLE. Regulatory accounts receivable, amounting to $26.3 million at December 31, 1994 include accruals under the three-year 1992 electric rate settlement agreement for incentives related to the Company's Enlightened Energy program ($70.1 million), for incentives related to customer service activities ($6.7 million), for the amounts to be billed under the PPFAC ($5.9 million) and for net electric sales revenues in accordance with the ERAM (a refund of $56.4 million). The revenues accrued in 1993 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, 1995. Revenues accrued in 1994 are anticipated to be collected over a twelve-month period beginning April 1, 1995. 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 $170.2 million at December 31, 1994 and $140.1 million at December 31, 1993. In accordance with the 1992 electric rate settlement agreement, the Company is generally recovering its Enlightened Energy program costs over a five-year period.
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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, 1994 and 1993, the trust fund amounted to $102.2 million and $83.1 million, respectively. Investments for 1994 are stated at market and for 1993 at cost which approximated 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 previously collected from customers are deducted from rate base and amortized or otherwise applied as a reduction in federal income tax expense in future years. Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties and applied as a reduction in future federal income tax expense.
The Company, beginning January 1, 1993, adopted SFAS 109, "Accounting for Income Taxes." SFAS 109 requires the Company to record a deferred income tax liability for substantially all temporary differences between book and tax bases of assets and liabilities at current tax rates, including differences for which deferred taxes have not previously been provided. For regulated enterprises, a regulatory asset is recognized for the latter if the criteria of SFAS 71 are met, that is, it is probable that future revenues will be allowed sufficient in amount to recover the costs for which deferred taxes have not previously been provided. The regulatory asset, stated at the revenue requirement level, amounts to $1,106.0 million and $1,150.6 million, at December 31, 1994 and 1993, respectively. These amounts which are included in accumulated deferred federal income tax (see Note G), are not reflected in rate base for rate-making purposes. In January 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 final policy statement is not expected to materially differ from the interim policy statement.
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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 1994, 1993 and 1992, amounting to $46.8 million, $48.0 million and $44.8 million, respectively, were charged to operating expenses. No research and development costs were capitalized in these years.
RECLASSIFICATION. Certain prior year amounts have been reclassified to conform with current year presentation.
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 1994, 1993 and 1992, 4,176 shares, 5,208 shares and 4,349 shares of Series B preference stock were converted into 54,288 shares, 67,704 shares and 56,537 shares of common stock, respectively.
At December 31, 1994, 690,326 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.
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Redemption prices of preferred stock other than Series I and Series J (in each case, plus accrued dividends) are 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 $105.76 per share, plus accrued dividends, if redeemed prior to May 1, 1995 (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 distributions in common stock or such junior stock.
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LONG-TERM DEBT. Total long-term debt maturing in the period 1995-1999 is as follows:
----------------------------------------------------------------- 1995 $ 10,889,000 1996 183,524,000 1997 106,256,000 1998 200,000,000 1999 225,000,000 -----------------------------------------------------------------
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.
Note C Lines of Credit ----------------------------------------------------------------- The Company has bank lines of credit for 1995 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.
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.
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In accordance with SFAS 87, "Employers' Accounting for Pensions," the Company uses the projected unit credit method for determining pension cost. Pension costs for 1994, 1993 and 1992 amounted to $38.7 million, $42.4 million and $56.8 million, respectively, of which $30.3 million for 1994, $33.6 million for 1993 and $44.8 million for 1992 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 PSC Policy). The PSC 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 actuarial 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 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 amounted to $33.3 million. Under an agreement with the PSC, the Company is amortizing 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 charged the equivalent of the first two years of the amortization ($4.4 million) to pension expense in 1993 and established a liability and offsetting regulatory asset for the $28.9 million allocable to future periods.
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* Being amortized over approximately 15 years. **See discussion above in this Note D.
To determine the present value of the projected benefit obligation in 1994, a discount rate of 8 percent was assumed. For 1993 and 1992, a discount rate of 7.5 percent was assumed. A weighted average rate of increase in future compensation levels of 5.8 percent and a long-term rate of return on plan assets of 8.5 percent were assumed for all 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.
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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 6,600 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 these programs.
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 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. 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 had accrued $6.9 million in interest on its unfunded liability of $28.5 million. In 1994, the Company funded both amounts in addition to $0.9 million accrued in 1994.
The retiree health and life insurance expense for 1994 and 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. Current electric, gas and steam rates reflect the increase in expense resulting from the adoption of SFAS 106.
The cost to the Company for retiree health benefits for 1994, 1993 and 1992 amounted to $67.1 million, $66.3 million and $46.1 million, respectively, of which $52.7 million for 1994, $52.5 million for 1993 and $36.4 million for 1992 was charged to operating expense. The cost of the retiree life insurance plan for 1994, 1993 and 1992 amounted to $21.6 million, $22.3 million and $8.6 million, respectively, of which $17.0 million for 1994, $17.7 million for 1993 and $6.8 million for 1992 was charged to operating expense.
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The components of postretirement benefit (health and life insurance) costs for years 1994 and 1993 were as follows:
*Being amortized over a period of 20 years.
To determine the accumulated postretirement benefit obligation in 1994 and 1993, a discount rate of 8 percent and 7.5 percent, respectively, was assumed. The assumed long-term rate of return on plan assets was 8.5 percent for these years. The health cost trend rate assumed for year 1994 was 9 percent, and then declining approximately one percent per year to 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 $91.8 million and the service cost and interest component of the net periodic postretirement benefit cost would increase by $9.3 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.
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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. The 1995 outage inspection has just begun. 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 replacement steam generators, which are stored at the site. If replacement of the steam generators is required, such replacement is presently estimated (in 1994 dollars) to require additional expenditures of approximately $102 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 policies 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, 1994, the highest amount which could be assessed for losses during the current policy year under all of the policies was $26.1 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 $3.1 million.
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ENVIRONMENTAL MATTERS. The normal course of the Company's operations necessarily involves activities and substances that expose the Company to potential liabilities under federal, state and local laws protecting the environment. Such liabilities can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Sources of such potential liabilities include (but are not limited to) the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (Superfund), a recent settlement with the New York State Department of Environmental Conservation (DEC), asbestos, and electric and magnetic fields (EMF).
Superfund. By its terms, Superfund imposes joint and several strict liability, regardless of fault, upon generators of hazardous substances for resulting removal and remedial costs and environmental damages. The Company has received process or notice concerning possible claims under Superfund or similar state statutes relating to a number of 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. Estimates of the investigative, removal, remedial and environmental damage costs (if any) the Company will be obligated to pay with respect to each of these sites range from extremely preliminary to highly refined. These estimates currently aggregate approximately $12 million and the Company has accrued a liability in this amount. However, it is possible that material additional costs in amounts not presently determinable may be incurred with respect to these and other sites.
DEC Settlement. In November 1994 the Company agreed to a consent order settling a civil administrative proceeding instituted by the DEC in 1992, alleging environmental violations by the Company. Under the consent order, in addition to required payments which have been made, the Company must also conduct an environmental compliance audit and an environmental management review, develop and implement "best management practices" plans for certain facilities and undertake a remediation program at certain sites. At December 31, 1994, the Company accrued a liability of $10.9 million for the expense of the site remediation program. Capital expenditures for environmental projects in the next five years to comply with the consent order are estimated at $64 million. There may be additional costs which could be material, but are not presently determinable.
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Asbestos Claims. Suits have been brought in New York State and federal courts against the Company and many other defendants, wherein several thousand 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. The amounts specified in all the remaining suits 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.
EMF. Electric and magnetic fields are found wherever electricity is used. Several scientific studies have raised concerns that EMF surrounding electric equipment and wires, including power lines, may present health risks. The Company is the defendant in several suits claiming property damage or personal injury allegedly resulting from EMF. In the event that a causal relationship between EMF and adverse health effects is established, or independently of any such causal determination, in the event of adverse developments in related legal or public policy doctrines, there could be a material adverse effect on the electric utility industry, including the Company.
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Note G Federal Income Tax ---------------------------------------------------------------- In the case of regulated utilities, SFAS 109 requires recognition in the balance sheet of the revenue requirements to meet the costs of future federal income taxes for temporary differences for which deferred taxes had not previously been provided. Accumulated deferred federal income taxes in excess of the statutory 35 percent tax rate for 1993 were reclassified to conform to the current year presentation. This reclassification had no effect on income. The net revenue requirements related to future federal income taxes at December 31, 1994 and 1993 are shown on the following table.
*Net revenue requirements will be offset by the amortization to federal income tax expense of accumulated deferred investment tax credits. Including the full effect therefrom, the net revenue requirements related to future federal income taxes at December 31, 1994 and 1993 are $914.5 million and $949.5 million, respectively.
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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 15, 1995. The proxy statement is to be filed pursuant to Regulation 14A not later than 120 days after December 31, 1994, 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, 1994 and
Consolidated Income Statement for the years ended December 31, 1994, 1993 and 1992
Consolidated Statement of Cash Flows for the years ended December 31, 1994, 1993 and 1992
Consolidated Statement of Capitalization at December 31, 1994 and 1993
Consolidated Statement of Retained Earnings for the years ended December 31, 1994, 1993 and 1992
Notes to Consolidated Financial Statements
2. List of Financial Statement Schedules
Valuation and Qualifying Accounts (Schedule VIII)
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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 (File No. 1-1217) 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 (File No. 1-1217) 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 (File No. 1-1217) 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 July 26, 1994. (Designated in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1994 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:
Securities Act Supplemental Registration Indenture Statement Exhibit
1. Fifteenth 2-13939 2-4 2. Twenty-ninth 2-24272 4-4 3. 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 *3. Third 12/1/94
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 *3. Third 12/1/94
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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 Floating Rate Series 1994 B 8-K 6/29/94 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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*10.5 The Con Edison Thrift Savings Plan for Management Employees and Tax Reduction Act Stock Ownership Plan, as amended and restated.
10.6 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 Company's Annual Report on Form 10-K for the year ended December 31, 1992 as Exhibit 10(i).)
10.7 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).)
10.8 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).)
10.9 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.)
10.10 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.)
10.11 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.)
10.12 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).)
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10.13 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.)
10.14 Amendment, dated August 24, 1994, 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, 1994 as Exhibit 10.1.)
10.15 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).)
10.16 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 (File No. 1-1217) as Exhibit 10(w).)
10.17 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).)
10.18 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).)
10.19 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).)
10.20 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).)
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10.21 Amendment, dated March 10, 1994, 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, 1993 as Exhibit 10.23.)
*10.22 Amendment, dated March 1, 1995, to Agreement, effective March 1, 1989, between Raymond J. McCann and the Company.
10.23 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).)
10.24 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).)
10.25 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).)
*10.26 The Consolidated Edison Retirement Plan for Management Employees, as amended and restated, effective as of January 1, 1994.
10.27 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).)
10.28 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).)
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10.29 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).)
10.30 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).)
10.31 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).)
10.32 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(hh).)
10.33 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).)
10.34 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).)
10.35 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.)
10.36 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.)
10.37 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.)
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10.38 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).)
10.39 Amendment No. 1, dated October 31, 1994, to the Consolidated Edison Retiree Health Program for Management Employees. (Designated in the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1994 as Exhibit 10.3.)
*12 Statement of computation of ratio of earnings to fixed charges for the years ended December 31, 1994, 1993, 1992, 1991 and 1990.
*23 Consent of Price Waterhouse dated March 28, 1995.
*24 Powers of Attorney of each of the persons signing this report by attorney-in-fact.
*27 Financial Data Schedule. (To the extent provided in Rule 402 of Regulation S-T, this exhibit shall not be deemed "filed", or otherwise subject to liabilities, or be deemed part of a registration statement.)
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
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(b) Reports on Form 8-K:
During the quarter ended December 31, 1994, the Company filed no Current Reports on Form 8-K.
The Company filed a Current Report on Form 8-K, dated February 13, 1995, reporting (under Item 5) the settlement agreement discussed under the caption "Liquidity and Capital Resources - 1994 Electric Rate Increase Filing" in Item 7 of this report.
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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, 1995 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, 1995 Eugene R. McGrath* Chairman of the Board, President, Chief Executive Officer and Trustee (Principal Executive Officer)
March 29, 1995 Raymond J. McCann* Executive Vice President & Chief Financial Officer and Trustee (Principal Financial Officer)
March 29, 1995 Joan S. Freilich* Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer) E. Virgil Conway* Trustee Gordon J. Davis* Trustee Ruth M. Davis* Trustee Ellen V. Futter* Trustee Arthur Hauspurg* Trustee Sally Hernandez-Pinero* Trustee Peter W. Likins* Trustee Frederick P. Rose* Trustee Donald K. Ross* Trustee Robert G. Schwartz* Trustee Richard A. Voell* Trustee Myles V. Whalen, Jr.* Trustee
March 29, 1995 *By Raymond J. McCann Attorney-in-Fact Raymond J. McCann