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

Item 1. Business
(a) General development of business
New York State Electric & Gas Corporation (Company) was organized under the laws of the State of New York in 1852.
The following general developments have occurred in the business of the Company since January 1, 1993:
Rates and regulatory matters
Rate Matters
In September 1993, the Company reached a three-year electric and natural gas rate settlement agreement (Agreement) with the Public Service Commission of the State of New York (PSC). The new electric and natural gas rates became effective September 4, 1993.
The allowed return on equity is 10.8% in year one, 11.4% in year two, and 11.4% (subject to an indexing mechanism) in year three. Shareholders will be allowed to keep 100% of any earnings in excess of the allowed return in year one. Shareholders and customers will share, on a 50%/50% basis, any earnings in excess of the allowed return in years two and three.
The Agreement also includes a modified revenue decoupling mechanism (RDM) for electric sales. Rates are based on sales forecasts. Since actual sales may differ significantly from forecasted sales because of conservation efforts, unusual weather, or changing economic conditions, the revenue collected may be more or less than forecast. Subject to the caps described below, the modified RDM will let the Company adjust for most of the differences between forecasted and actual sales. For example, if revenues exceed the forecast for a given year, the excess would be passed back to customers in a future year. If revenues are below the forecast, customers would receive a surcharge in a future year. The Company will share excesses or shortfalls from most large commercial and industrial sales revenues on a 70%/30% (customer/stockholder) basis.
Customer savings for production and transmission operating costs of $21 million will be imputed over three years, $7 million each year, whether or not they are realized.
Incentives for customer service, production cost, and demand-side management (DSM) could increase the allowed return to 12.3% or decrease it to 9.95% in year one, increase it to 13.05% or decrease it to 10.4% in year two, and increase it to 13.25% or decrease it to 10.2% in year three.
The electric and natural gas rate increases discussed below represent eleven months for year one and twelve months for years two and three.
The estimated total electric price increases below include base rate increases allowed by the Agreement plus estimates of fuel and purchased power increases which will be collected through the Fuel Adjustment Clause (FAC). Actual fuel and purchased power costs could vary from estimates causing the estimated FAC and total electric price increases below to change.
Base Rate Estimated FAC Total Electric (Dollar Amounts in Millions)
Year 1 $60.5 4.4% $39.1 3.0% $99.6 7.4% Year 2 $70.3 4.8% $39.2 2.8% $109.5 7.6% Year 3 $57.4 3.6% $30.4 2.0% $87.8 5.6%
The natural gas base rate increases allowed by the Agreement are $7.5 million, or 2.9%, $8.2 million, or 3.0%, and $7.2 million, or 2.5%, in years one, two, and three, respectively. They do not include changes in natural gas costs, which will be collected through the Gas Adjustment Clause. Natural gas costs can be expected to rise and fall with overall natural gas market conditions. Such fluctuations will affect the total natural gas price increases.
The Agreement also provides for the stated electric and natural gas base rate increases to be adjusted up or down in the second and third years, as well as the year after the Agreement period (year four). These adjustments will depend on several factors, such as electric sales and incentive mechanisms. The Agreement provides that no cap would apply to any downward revision to base rates for electric and natural gas service. The electric base rate increases could be increased by up to 1.5% in years two and three and 1.6% in year four (the caps). The natural gas base rate increases could also be increased by up to 1% in year two and 1.2% in year three. The Agreement does not specify a cap for natural gas base rates for year four.
Flexible, Negotiable Rate Tariffs
A major challenge to the Company's Electric Business Unit is to retain and grow its industrial base. The competitive energy supply options currently available to the Company's industrial customers include self-generation, shifting production to plants in other locations, or relocation. During 1993, the Company received PSC approval for a flexible, negotiable rate tariff for some of its high-use industrial customers. Discounts negotiated in agreements under this tariff are not expected to have a material effect on the Company's 1994 earnings. Two agreements have been negotiated which eliminated threats of self-generation and relocation.
The PSC currently has a generic proceeding to study the broad subject of flexible, competitive rates, and will establish guidelines for the Company and other New York State utilities during 1994.
In November 1993, the Company filed with the PSC an additional flexible, negotiable rate tariff to address opportunities for new load. The proposed tariff is for large additions to load (at least 500 kilowatts [kw]) for new or
existing industrial and some commercial customers. The tariff will assist the Company in attracting new customers whose location or expansion decisions are influenced by electricity costs. Smaller customers will be assisted by a concurrent proposal to increase the Company's existing economic development incentives by one cent per kilowatt-hour. The Company has proposed and will continue to propose revisions or additional tariffs to respond to the opportunities or risks that develop in a changing electric utility industry.
Federal Energy Regulatory Commission (FERC) Order 636
A major challenge to the Company's Gas Business Unit is FERC Order 636, which became effective in November 1993, and requires interstate natural gas pipeline companies to offer customers unbundled or separate services equivalent to their former sales service. With the unbundling of services, primary responsibility for reliable natural gas supply will shift from interstate pipeline companies to local distribution companies, such as the Company. This should result in increased direct access to low cost natural gas supplies by local distribution companies and end users. One goal of FERC Order 636 is to provide equitable access to interstate pipeline capacity. FERC Order 636 will substantially restructure the interstate natural gas market and intensify competition within the natural gas industry. FERC Order 636 will allow the Company, subject to PSC approval, to restructure rates and provide multiple service options to its customers.
In July 1993, certain interstate pipelines serving the Company began implementing restructured services in compliance with FERC Order 636. The remaining pipelines implemented restructured services by November 1993. As a result of these restructuring changes, pipelines have incurred and will continue to incur transition costs. These transition costs include those associated with restructuring existing natural gas supply contracts, the unrecovered natural gas cost that would otherwise have been billable to pipeline customers under previously existing rules, costs of assets needed to implement the order, and stranded investment costs. FERC Order 636 allows pipelines to recover all prudently incurred costs from their customers. The Company's liability for transition costs will be based on the pipelines' filings with FERC to recover transition costs. Only a few of those filings have been made. The Company recorded an estimated liability for transition costs of approximately $29 million. The Company also recorded a deferred asset for that amount since it is currently recovering transition costs from its customers through its gas adjustment clause and believes that such costs will continue to be recoverable from its customers.
Diversification
Diversification will play an important role in the Company's future. While the strength of the Company's core electric and natural gas businesses remains its focus, and while the Company will not compromise its financial integrity, it is actively evaluating a number of corporate development opportunities for investment to help augment future earnings and dividend growth. In April 1992, the PSC issued an order allowing the Company to
invest up to 5% of its consolidated capitalization (approximately $175 million at December 31, 1993) in one or more subsidiaries that may engage or invest in energy-related or environmental services businesses and provide related services. In May 1993, NGE Enterprises, Inc. (NGE), a wholly-owned subsidiary of the Company, formed a computer software company, EnerSoft Corporation (EnerSoft), to produce and market software applications for natural gas utilities in the post-FERC Order 636 environment. This represents NGE's initial diversified investment.
In October 1993, EnerSoft began a strategic alliance with the New York Mercantile Exchange to develop an information superhighway that will provide the natural gas industry with a single system for monitoring and trading natural gas and pipeline capacity in the North American market. NGE invested approximately $9 million in EnerSoft through February 1994.
The Company and NGE plan to develop two natural gas storage projects. One of the projects, which will be regulated by the PSC, is expected to cost approximately $14 million and will be used to supplement the Company's natural gas supply. Construction of this project is scheduled to begin in 1994 and it is expected to be operating for the 1995-96 heating season. The other project, which will be regulated by the FERC, is an equal partnership between NGE and ANR Storage, Inc., and is expected to cost approximately $44 million in total. The entire capacity of this project will be marketed to local distribution companies and non-utility generator (NUG)s, as well as marketers, producers, and end users of natural gas. Construction of this project is scheduled to begin in 1995 and it is expected to be operating for the 1996-1997 heating season.
Restructuring
In the fourth quarter of 1993, the Company recorded a $26 million restructuring charge. The corporate restructuring will reorganize the way the Company delivers services to its electric and natural gas customers beginning in March 1994. The restructuring reduced 1993 earnings available for common stock by approximately $17.2 million or 25 cents per share. Included in this amount are $13.2 million for a voluntary early retirement program, $3.2 million for an involuntary severance program, and $.8 million for the elimination and closing of electric and natural gas operations facilities statewide. During 1994, the restructuring resulted in a work force reduction throughout the organization of approximately 600, the elimination of customer walk-in services at 28 satellite locations, and the closing of up to 10 electric and natural gas operations facilities statewide. The work force reduction was accomplished through a voluntary early retirement program (See Note 7 to the Consolidated Financial Statements on page 60) and an involuntary severance program. 384 employees accepted the early retirement program.
(b) Financial information about industry segments
See Note 11 to the Consolidated Financial Statements on page 72.
(c) Narrative description of business (i) Principal business
The Company's principal business is generating, purchasing, transmitting, and distributing electricity and purchasing, transporting, and distributing natural gas. The service territory, 99% of which is located outside the corporate limits of cities, is in the central, eastern, and western parts of the State of New York. The service territory has an area of approximately 19,500 square miles, and a population of 2,400,000. The larger cities in which the Company serves both electricity and natural gas are Binghamton, Elmira, Auburn, Geneva, Ithaca, and Lockport. The Company serves approximately 790,000 electric retail customers and 226,000 natural gas retail customers. Its service territory reflects a diversified economy, including high- tech firms, light industry, agriculture, colleges and universities, and recreational facilities. No customer accounts for 5% or more of either electric or natural gas revenues. For the years 1993, 1992, and 1991, 85%, 86%, and 88%, respectively, of operating revenue was derived from electric service and 15%, 14%, and 12%, respectively, was derived from natural gas service.
The 1993-1994 winter peak load of 2,618,000 kw, was set on January 19, 1994. This is 21,000 kw more than the previous all time peak of 2,597,000 kw set during the 1989-1990 winter on December 21, 1989. Power supply capability to meet peak loads is currently 3,194,430 kw. This is composed of 2,656,700 kw of generating capacity (90% coal-fired, 7% nuclear, and 3% hydroelectric) and 848,730 kw of purchases offset by 311,000 kw of firm sales. The purchases are composed of 362,280 kw from NUGs and 486,450 kw from the New York Power Authority (NYPA). Most purchases from NYPA are hydroelectric power.
In June 1989, New York City, the Counties of Westchester, Nassau, and Suffolk, and their respective municipal distribution agencies, commenced Article 78 proceedings in the Supreme Court of the State of New York (New York County) (Court) against NYPA to set aside NYPA's contracts expiring in the year 2007 with the Company and two other utilities for the post January 1, 1990 allocation of NYPA hydroelectric power. The Company has intervened in these proceedings to protect its contractual entitlement. In November 1990, the Court issued a decision granting various motions and dismissing the Article 78 proceedings. On December 29, 1992, the Appellate Division, First Department unanimously affirmed the decision. On October 12, 1993, the Court of Appeals of the State of New York rejected a motion for leave to appeal to that court.
The Company has on line and under contract 362 megawatts (mw) of NUG power. In addition, another 240 mw of NUG power is under construction. The Company is required to make payments under these contracts only for the power it receives. During 1993, 1992, and 1991, the Company purchased approximately $138 million, $71 million, and $30 million, respectively, of NUG power. The Company estimates that it will purchase approximately $255 million, $291 million, and $335 million of NUG power for the years 1994, 1995, and 1996, respectively.
Increases in NUG power purchase costs are expected to be a significant contributor to price increases over the next three years.
As part of the Company's effort to meet competition and minimize future price increases associated with uneconomical power purchases from NUGs, it negotiated the termination of two cogeneration projects. This effort, along with the termination of NUG contracts due to developers' failures to meet contract obligations, will save customers nearly $1 billion over the terms of the contracts. The Company has also recently negotiated amendments with two NUGs whereby the Company may direct the NUGs to reduce their output or shut down for limited periods each year. During these periods, lower-cost generation will replace the NUG energy and result in additional customer savings. The Company is negotiating with other NUGs for similar amendments.
As part of the Company's effort to reduce costs, one of two generating units at each of its Goudey and Greenidge Generating Stations will be placed on long-term cold standby. These actions are being taken because the abundance of power in the Northeast has driven down wholesale prices. These units will continue to be utilized to provide electrical system support.
The Company has implemented a number of demand-side management (DSM) programs. As a result of its three-year rate settlement agreement (See Item 1(a)-Rates and regulatory matters - - Rate Matters), incentives earned for conducting efficient DSM programs were reduced from 15% to 5% of the net resource savings achieved by these DSM programs. For 1994, the Company expects to earn approximately $3 million in incentives as a result of these DSM programs.
In 1993, the Company's customers saved approximately 282 million kilowatt-hours (kwh) on an annualized basis through the Company's DSM programs. The implementation of these programs cost $48 million in 1993 and will cost approximately $16 million in 1994 with estimated customer savings of 113 million kwh on an annualized basis. The Company has approximately $73 million and $44 million of deferred DSM program costs on the Consolidated Balance Sheets at December 31, 1993, and 1992, respectively. The two-year (1993-1994) DSM plan, which has received PSC approval, has been modified to improve cost-effectiveness and reduce rate impacts.
On January 19, 1994, the Company experienced its 1993-1994 maximum peak daily sendout for natural gas of 431,756 dekatherms. This is 69,175 dekatherms greater than the 1991-1992 peak of 362,581 dekatherms set on January 16, 1992.
The following table provides information on the Company's estimated sources and uses of funds for 1994-1996. This forecast is subject to periodic review and revision, and actual construction costs may vary because of revised load estimates, imposition of additional regulatory requirements, and the availability and cost of capital.
1994 1995 1996 Total ---- ---- ---- ----- Sources of funds (Millions)
Internal funds $254 $265 $269 $788 Long-term financing Debt and stock proceeds 413 141 80 634 Debt proceeds held in trust 34 8 - 42 ---- ---- ---- ----- Net financing proceeds 447 149 80 676 Increase (decrease) in short-term debt (50) - - (50) Decrease (increase) in temporary cash investments 89 (69) (52) (32) ---- ---- ---- ------ Total $740 $345 $297 $1,382 ==== ==== ==== ====== Uses of funds
Construction Cash expenditures $202 $193 $193 $588 AFDC 8 7 7 22 ---- ---- ---- ------ Total construction 210 200 200 610 Retirement of securities and sinking fund obligations 501 108 63 672 Working capital and deferrals 29 37 34 100 ---- ---- ---- ------ Total $740 $345 $297 $1,382 ==== ==== ==== ======
As shown in the preceding table, internal sources of funds represent 129% of construction expenditures for 1994-1996.
Capital expenditures for 1994-1996 have been significantly reduced from previously forecasted levels. This represents one of many actions the Company is taking to address competition (See Item 1(c)(x)-Competitive conditions). Capital expenditures for 1994-1996 will be primarily for extension of service, necessary improvements at existing facilities, and compliance with the Clean Air Act Amendments of 1990 (See Item 1(c)(xii)- Environmental matters). The Company forecasts that its current reserve margin, coupled with more efficient use of energy and generation from NUGs, will eliminate the need for additional generating capacity until after the year 2005.
(ii) New product or segment (See Item 1(a)-Diversification.)
(iii) Sources and availability of raw materials
Electric
In 1993, approximately 90% of the Company's generation was coal-fired steam electric, 8% nuclear and 2% hydroelectric power. About 37% of the Company's steam electric generation in 1993 was supplied from its one-half share of the output from the Homer City Generating Station, which is owned in common with Pennsylvania Electric Company. An additional 34% was supplied from the Company's Kintigh Generating Station, and the remaining 29% was supplied from its other generating stations which are located in New York State.
Coal
Coal for the New York generating stations is obtained primarily from Pennsylvania and West Virginia. Of the 3.2 million tons of coal purchased for the New York generating stations in 1993, approximately 46% was purchased under contract and the balance on the open market. Coal purchased under contract is expected to be approximately 53% of the estimated 3.1 million tons to be purchased in 1994.
The annual coal requirement for the Homer City Generating Station is approximately four million tons, the majority of which is obtained under long-term contracts. During 1993, approximately 52% of Homer City Generating Station coal was obtained under these contracts. The Company anticipates obtaining approximately 79% of the 1994 requirements under these contracts. The balance will be purchased under short-term contracts and, when necessary, on the open market.
Nuclear During the fall of 1993, Niagara Mohawk Power Corporation (Niagara Mohawk), the operator of the Nine Mile Point nuclear generating unit No. 2 (NMP2), in which the Company has an 18% interest, completed the third refueling outage. The present core will support NMP2 operations to 1995. Enrichment services are under contract with the U.S. Department of Energy for 100% of the services through 1995 and 70% of the services from 1996 through 1998. Fuel fabrication services are under contract for the first seven reloads. Approximately 55% of the uranium and conversion requirements are under contract through 1998.
Natural Gas
As a result of FERC Order 636 (See Item 1(a)-Rates and regulatory matters - Federal Energy Regulatory Commission (FERC) Order 636), the Company undertook a major restructuring of its natural gas transportation, storage, and supply contracts. Bundled pipeline sales, gas and transportation contracts have been eliminated thereby giving the Company greater flexibility with respect to its supply of natural gas. The gas supply mix now includes long-term, short-term, and spot gas purchases transported on firm transportation contracts, as well as spot gas purchases transported on interruptible transportation contracts.
During 1993, about 15% of the Company's natural gas supply was purchased on firm sales contracts from CNG Transmission and Columbia Gas Transmission. The remaining 85% was purchased from other suppliers, approximately 25% under long-term and short-term sales contracts and 60% on the monthly spot natural gas market to maximize natural gas cost savings. An additional benefit of FERC Order 636 is that the Company now has access to increased natural gas storage space enabling it to purchase natural gas supply when prices are favorable.
(iv) Franchises
The Company has, with minor exceptions, valid franchises from the municipalities in which it renders service to the public. In 1993, the Company obtained PSC authorizations for natural gas transmission and distribution service in the towns of Skaneateles, Stillwater, Starkey, and the town and village of Champlain.
(v) Seasonal business
Sales of electricity are highest during the winter months primarily due to space heating usage and fewer daylight hours. Sales of natural gas are highest during the winter months primarily due to space heating usage.
(vi) Working capital items
The Company has been granted, through the ratemaking process, an allowance for working capital to operate its ongoing electric and natural gas utility services.
(vii) Single customer - Not applicable
(viii) Backlog of orders - Not applicable
(ix) Business subject to renegotiation - Not applicable
(x) Competitive conditions (See Item 1(a)-Rates and regulatory matters - Flexible Negotiable Rate Tariffs; Federal Energy Regulatory Commission (FERC) Order 636; and Restructuring and Item 1(c)(i)-Principal business)
The utility industry is rapidly changing and facing an increasingly competitive environment. Factors contributing to this competitive environment are: the National Energy Policy Act of 1992 (Energy Policy Act), which provides open access at the wholesale level to electric transmission service, and the FERC Order 636, which significantly affects the natural gas industry. In addition, the Company's response to the economic pressures on its electric industrial and other large use customers, high purchase costs of NUGs, rising health care costs, increasing taxes, weak economic conditions, conservation programs, and compliance with environmental laws and regulations are all factors that continue to place increased pressure on electric and natural gas prices.
The Energy Policy Act, enacted in October 1992, is expected to result in major changes to the utility industry. Certain provisions of the Energy Policy Act amended the Public Utility Holding Company Act of 1935 (PUHCA). These amendments encourage greater competition in the supply market by establishing a new category of wholesale electric generators that are exempt from PUHCA regulation. The Energy Policy Act also enables the FERC to order utilities to provide open access to transmission systems for wholesale transactions, expanding opportunities for utilities and NUGs to enter new and existing wholesale markets. These developments serve to underscore the increasingly competitive environment for utilities.
The Company's five-year strategic plan is designed to address the competitive, rapidly changing utility industry. The Company's objective is to remain competitive in its core businesses in the face of increased competition. One of the key strategies to meet competition is to improve customer value by becoming a low-cost provider of energy services in the Northeast.
The Company has developed a more aggressive and accelerated set of strategies in response to the increased challenges of competition which are necessary to achieve the objectives outlined in the Company's five-year strategic plan. The following represent strategies being implemented: - Reduce forecasted 1994 capital expenditures by one-third, or approximately $100 million. Additional reductions will be made in 1995 and 1996. - Reduce operating and maintenance expenses by five percent in 1994 and again in 1995. By 1995, this will save about $40 million annually. During 1993, the Company reduced its work force by 200 through attrition. In addition, as part of the O&M reduction, the Company's work force was further reduced by about 600 through an early retirement opportunity program and involuntary severance. - Streamline the field organization to eliminate walk-in customer service at 28 locations, and to close up to 10 electric and natural gas operations facilities statewide. - Place two generating units on long-term cold standby. - Continue to reduce NUG costs. The Company's previous NUG contract terminations and renegotiations will save customers more than $1 billion over the terms of the contracts. - Continue to reduce capital costs. Since 1988 the Company has refinanced over $1.4 billion in securities, and reduced annual interest expense by more than $55 million.
The PSC currently has a generic proceeding to study the broad subject of flexible, competitive rates, and will establish guidelines for the Company and other New York State utilities during 1994. Also in late 1993, the PSC instituted a proceeding to address issues associated with the restructuring of the emerging competitive natural gas market. The PSC intends to investigate services provided by New York State gas utilities after FERC Order 636 by the 1994-1995 heating season.
Other forms of competition stem from both federal and state action. Natural gas at the wellhead is available to be purchased directly by end users from the producer at a delivered price which may be less than that of the local distributor. Delivery
of such natural gas is by pipeline transportation. By law, the Company must provide transportation service so long as it is not an undue burden on the Company or its customers and the Company's ability to render adequate service to its customers is not impaired. The Company has developed, and its customers are using, various transportation tariff services. Transportation of natural gas in lieu of retail sales is not expected to have a material effect on the Company's 1994 earnings.
From time to time, the price of fuel oil has allowed oil suppliers to compete with the Company's sale of natural gas to large natural gas customers. To meet the competition from oil, the Company has flexible sales and transportation rates for qualifying natural gas customers. The flexible rates provide the Company with greater opportunity for making available rate offerings and setting rates which more closely reflect the competitive needs of dual-fuel customers. This capability enhances the Company's ability to set multiple rates each month in a manner which maximizes margins. The Company is now utilizing and receiving benefits from the various flexible pricing options. These flexible rates are not expected to have a material effect on the Company's 1994 earnings and enable the Company to minimize threats of bypass.
(xi) Research and development
Expenditures on research and development in 1993, 1992, and 1991 amounted to $18.9 million, $14.6 million, and $14.8 million, respectively, principally for the Company's internal research programs and for contributions to research administered by the Electric Power Research Institute, the Empire State Electric Energy Research Corporation, the New York Gas Group, and the New York State Energy Research and Development Authority. These expenditures are designed to improve existing technologies and to develop new technologies for the production, distribution, and conservation of energy.
(xii) Environmental matters (See Item 3 - Legal proceedings)
The Company is subject to regulation by the federal government and by state and local governments in New York and Pennsylvania with respect to environmental matters and is also subject to the New York State Public Service Law requiring environmental approval and certification of proposed major transmission facilities.
The Company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Compliance programs will increase the cost of electric and natural gas service by requiring changes to the Company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred for compliance with environmental laws and regulations.
Capital additions to meet environmental requirements during the three years ended December 31, 1993 were approximately $143.0 million and are estimated to be $76.5 million for 1994, $51.4 million for 1995, and $40 million for 1996.
Water quality
The Company is required to comply with federal and state water quality statutes and regulations including the Clean Water Act (Water Act). The Water Act requires that generating stations be in compliance with federally issued National Pollutant Discharge Elimination System Permits (NPDES Permits) or state issued State Pollutant Discharge Elimination System Permits (SPDES Permits), which must reflect water quality considerations and application of the best available technology. The Company has SPDES Permits for its six coal-fired generating stations in New York and has applied for permit renewals for five of those stations. Permits for these five stations have either been renewed or are currently being negotiated with the State of New York, in which case the existing permits for those facilities remain in effect. The permit for the sixth station will not expire until the fall of 1994. The Company's Homer City Generating Station received a NPDES Permit, which expires in the fall of 1994, from the Pennsylvania Department of Environmental Resources (PaDER). Prior to the expiration of the two permits which expire in the fall of 1994, renewal applications will be submitted by the Company. Until these permits are renewed, these stations will operate under their existing permits. SPDES licensing renewal is currently being addressed by the New York State Department of Environmental Conservation (NYSDEC) for NMP2.
In connection with the issuance of permits under the Water Act, the Company has conducted studies of the effects of its coal pile operations on groundwater quality at its Hickling, Jennison, Milliken, and Greenidge Stations. New York State groundwater standards are sometimes exceeded at certain locations at each of those stations and remedial action may be required. Jennison Station will require remedial action which is estimated to cost up to $1 million. The remedial action, if required, at Hickling, Milliken, and Greenidge Stations is estimated to cost $7.4 million. The Company expects to recover these expenditures in rates, since the Company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements. Remedial action has already been performed at the Goudey Station and the Company is currently monitoring the groundwater quality at this station. Groundwater monitoring data for Kintigh Station does not indicate facility induced groundwater contamination. Groundwater studies have been initiated at the Homer City Station.
Air quality
The Company is required to comply with federal and state air quality statutes and regulations. All stations have the required federal or state operating permits. Stack tests and continuous emission monitoring indicate that the stations are generally in compliance with permit emission limitations, although occasional opacity exceedances occur. Efforts are underway to identify and eliminate the causes of opacity exceedances.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in significant expenditures of approximately $178 million, on a present value basis, over a 25-year period, for all capital
and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the Company's coal-fired generating stations, of which $51 million has been incurred as of December 31, 1993. The Company's current estimate is a significant reduction from its prior estimate, primarily due to the postponement of the construction of a flue gas desulfurization (FGD) system at its Homer City Generating Station. The Company plans to re-evaluate the need to construct an FGD system at the Homer City Generating Station in 1995, since its present strategy to bank Phase I emissions allowances for use during Phase II, as discussed below, will allow the Company to meet Phase II allowance requirements through the year 2005. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative FGD system and a nitrogen oxide reduction system expected to be completed in 1995 at the Company's Milliken Generating Station. The Company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (begins January 1, 1995) and Phase II (begins January 1, 2000). As a result of the 1990 Amendments, the Company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the Company to meet the sulfur dioxide levels established for the Company, which is approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time. Regulations may be adopted at the state level which would limit toxic emissions even further, at an additional cost to the Company. The Company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the U.S. Environmental Protection Agency (EPA) to allocate annual emissions allowances to each of the Company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the Company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The Company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the Company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the Company by the EPA, the Company will receive a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers, as a result of the pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
Certain other environmental regulations limit the amount of particulate matter which may be emitted into the environment. The Company and Pennsylvania Electric Company may find it
necessary either to upgrade or install additional equipment at the Homer City Generating Station in order to consistently meet the particulate emission requirements.
Waste disposal
The Company has received or applied for SPDES Permits, Solid Waste Disposal Facilities Permits, and applicable local permits for its active ash disposal sites for its New York generating stations. Groundwater standards have been exceeded in areas close to portions of the Milliken and Weber ash disposal sites. Corrective actions have been taken and studies are continuing to monitor the effectiveness of the corrective actions.
The Company has received NPDES permits, a Solid Waste Disposal Permit, and applicable local permits for its active ash disposal site for the Homer City Generating Station and for the active refuse disposal site for the Homer City Coal Cleaning Plant. In September 1993, the Company completed its study of costs to comply with the new Pennsylvania residual waste regulations governing solid waste disposal over the next 30 years.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the Company will incur approximately $24 million, on a present value basis, of additional costs over the next 30 years, beginning in 1994, at the Homer City Generating Station. These costs will be incurred to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The Company expects to recover these expenditures in rates, since the Company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the Company may also incur costs from the past disposal of hazardous substances produced during the Company's operations or those of its predecessors. The Company has been notified by the EPA and the NYSDEC that it is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at seven waste sites, not including the Company's inactive gas manufacturing sites, which are discussed below. With respect to the seven sites, five sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry).
Any liability may be joint and several for certain of these sites. The ultimate cost to remediate these sites will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the Company. At December 31, 1993, the Company recorded a liability in the Consolidated Balance Sheets related to four of these seven waste sites of $1.8 million. The Company has notified the NYSDEC that it believes it has no responsibility at two sites and has already incurred expenditures related to the remediation at the remaining site. A deferred asset has also been recorded in the amount of $2.6 million, of which $.8 million
relates to costs that have already been incurred. The Company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the Company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites. This $1.8 million estimate was derived by multiplying the total estimated cost to clean up a particular site by the related Company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the Company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the Company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the Company's inactive gas manufacturing sites have been listed in the New York State Registry. The Company has filed petitions to delist the majority of the sites. The Company's program to investigate and initiate remediation at its 38 known inactive gas manufacturing sites has been extended through the year 2000. Expenditures over this time period are estimated to be $25 million. This estimate was determined by using the Company's experience and knowledge related to these sites as a result of the investigation and remediation that the Company has performed to date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability, to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites is reflected in the Company's Consolidated Balance Sheets at December 31, 1993 and 1992. The Company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the Company has previously been allowed by the PSC to recover such costs in rates. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A low level radioactive waste management and contingency plan that has been developed for NMP2 provides assurance that NMP2 is properly prepared to handle interim storage of low level radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of Energy (DOE) for disposal of high level radioactive waste (spent fuel) from NMP2. The Company is reimbursing Niagara Mohawk for its 18% share of the cost under the contract (currently approximately $1 per megawatt hour of net generation). The DOE's schedule for start of operations of their high level radioactive
waste repository has slipped from 2003 to no sooner than 2010. The Company has been advised by Niagara Mohawk that the NMP2 Spent Fuel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, the recent development of pre-licensed dry storage facilities for use at any nuclear power plant extends the on-site storage capability for spent fuel at NMP2 beyond 2014.
(xiii) Number of employees
The Company had 4,746 employees as of December 31, 1993 (See Item 1(a)-Restructuring)
(d) Financial information about foreign and domestic operations and export sales - Not applicable
Item 2.



Item 2. Properties
The Company's electric system includes coal-fired, nuclear, hydroelectric, and internal combustion generating stations, substations, and transmission and distribution lines, all of which are located in the State of New York, except for the Homer City Generating Station and related facilities which are located in the Commonwealth of Pennsylvania. Generating facilities are:
Name and location of station Generating capability (kw) Coal-fired Goudey * (Binghamton, N.Y.) 127,000 Greenidge * (Dresden, N.Y.) 162,000 Hickling (East Corning, N.Y.) 86,000 Jennison (Bainbridge, N.Y.) 72,000 Milliken (Lansing, N.Y.) 318,000 Kintigh (Somerset, N.Y.) 675,000 Homer City (Homer City, Pa.) 954,000** --------- Total coal-fired 2,394,000
Nuclear NMP2 (Oswego, N.Y.) 189,000***
Hydroelectric (Various - 9 locations) 66,500
Internal combustion (Various - 2 locations) 7,200 ---------
Total - all stations 2,656,700 ========= * In the spring and summer of 1994 the Company plans to place one unit at both Goudey and Greenidge on long-term cold standby. These units have a combined capability of 97 megawatts. ** Company's 50% share of the generating capability. ***Company's 18% share of the generating capability.
The Company owns 446 substations having an aggregate transformer capacity of 12,634,177 Kilovolt-amperes. The transmission system consists of 4,774 circuit miles of line and the distribution system of 33,410 pole miles of overhead lines
and 1,790 miles of underground lines.
The Company's natural gas system consists of the distribution of natural gas through 452 miles of transmission pipelines (3-inch equivalent) and 5,360 miles of distribution pipelines (3-inch equivalent).
Somerset Railroad Corporation (SRC), a wholly-owned subsidiary, owns a rail line consisting of 15 1/2 miles of track and related property rights in Lockport, Newfane, and Somerset, New York which is used to transport coal and other materials to the Kintigh Generating Station.
The Company's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all of the Company's properties. Substantially all of the properties of SRC, other than rolling stock, are subject to a lien of a mortgage and security agreement.
Item 3.

Item 3. Legal proceedings (See Item 1(a)-Rates and regulatory matters, 1(c)(i)-Principal business, (x)-Competitive conditions, and (xii)-Environmental matters)
The Company is unable to predict the ultimate disposition of the matters referred to below in (c), (d), (e), (g), (h), (i), and (j). There is no clear precedent with the PSC for rate recovery of the types of costs referred to in these matters. However, since the PSC has previously allowed the Company to recover similar costs in rates, such as investigation and clean- up costs relating to coal tar sites, the Company expects to recover in rates any remediation costs that it may incur. Therefore, the Company believes that the ultimate disposition of the matters referred to below in (c), (d), (e), (g), (h), (i), and (j) will not have a material adverse effect on its results of operations or financial position.
(a) On January 27, January 31, and February 15, 1984, and on June 29, 1987, numerous individual plaintiffs instituted lawsuits in the Supreme Court of the State of New York (Broome County) for personal injuries allegedly arising out of a transformer fire at the State Office Building in Binghamton, New York, in February 1981. Multiple defendants, including the Company, are named in the actions which seek an aggregate of $329 million in compensatory and exemplary damages. Because the transformers involved were not owned, installed, or serviced by the Company, the Company believes that these claims against the Company are without merit.
(b) On January 15 and January 30, 1985, numerous individual plaintiffs instituted two lawsuits against the Company in the Supreme Court of the State of New York (Broome County) seeking a total of $70 million in compensatory damages, plus punitive damages in an unstated amount. These actions arise out of a spill of PCB-contaminated oil on the Company's property on February 1, 1982. One of the lawsuits alleges mental anguish as the basis for recovery. The other lawsuit does not specify the nature of the damages claimed, except for an alleged decrease in the value of one residential property in the vicinity of the
spill and deprivation of plaintiffs' right to quiet enjoyment of their property. Because the spill was contained on the Company's property and was quickly removed, the Company believes that these claims are without merit. Plaintiffs' counsel terminated their representation of the plaintiffs in these actions in 1988. The Company has not been notified of a substitution of attorneys for any of the plaintiffs and there has been no activity in these lawsuits since February 1988.
(c) By letter dated February 29, 1988, the NYSDEC notified the Company that it has been identified as a potentially responsible party for investigation and remediation of the disposal of hazardous wastes at the Lockport City Landfill Site (Lockport Site) in Lockport, New York. The Lockport Site is listed on the New York State Registry. Four other potentially responsible parties were identified in the NYSDEC letter. The Company has been offered an opportunity to conduct remediation or finance remediation costs at the Lockport Site, failing which the NYSDEC might remediate the Lockport Site itself and commence an action to recover its costs and damages. The Company believes that remediation costs at the Lockport Site might rise to $6 million. By letter dated May 2, 1988, the Company notified the NYSDEC that it declined to finance remediation costs because it believes that the NYSDEC had not demonstrated that a significant threat to public health or the environment exists at the Lockport Site.
(d) By letter dated December 10, 1990, the NYSDEC notified the Company that it had been identified as a potentially responsible party for investigation and remediation of the disposal of hazardous wastes at the Schreck's scrapyard site (Schreck's Site) in the City of North Tonawanda, New York. The Schreck's Site is listed on the New York State Registry. Seven other potentially responsible parties were identified in the NYSDEC letter. On February 3, 1992, the NYSDEC again notified the Company that it had been identified as a potentially responsible party for investigation and remediation costs at the Schreck's Site, this time listing eight other potentially responsible parties. The Company has been offered an opportunity to conduct remediation or finance remediation costs at the Schreck's Site, failing which the NYSDEC might remediate the Schreck's Site itself and commence an action to recover its costs and damages. The NYSDEC currently estimates that remediation costs at the Schreck's Site will be $4.5 million. By letter dated April 1, 1992, the Company notified the NYSDEC that it believed it had no responsibility for the alleged contamination at the Schreck's Site, and it declined to conduct remediation or finance remediation costs.
(e) By letter dated June 7, 1991, the NYSDEC notified the Company that it had been identified as a potentially responsible party at the Pfohl Brothers Landfill inactive hazardous waste disposal site (Pfohl Site) in Cheektowaga, New York. The Pfohl Site is listed on the New York State Registry. The NYSDEC offered the Company an opportunity to enter into negotiations with it to undertake the investigation and remediation of the Pfohl Site. The NYSDEC informed the Company that if it declined such negotiations, the NYSDEC would perform the necessary work at the Pfohl Site using the Hazardous Waste Remedial Fund and would seek recovery of its expenses from the Company. On July 3, 1991, the Company responded to the NYSDEC by declining to negotiate to
undertake work at the Pfohl Site and noted that the NYSDEC had not shown any significant responsibility on the part of the Company for the situation at the Pfohl Site. The Company believes that remediation costs at the Pfohl Site will be $35 million to $55 million. By letter dated April 2, 1992, the NYSDEC again notified the Company that it had been identified as a potentially responsible party for the Pfohl Site and offered the Company an opportunity to conduct or finance the on-site remedial design and action. This notice letter was also sent to 19 other potentially responsible parties. Ten of these other named potentially responsible parties have agreed to perform the remedial work required by the NYSDEC. By letter dated June 1, 1992, the Company notified the NYSDEC that it declined to perform such remedial work because it believed that it was not a significant contributor to the Pfohl Site.
(f) By complaint dated October 31, 1991, General Motors Corporation (GM) commenced a lawsuit against the Company in the U. S. District Court for the Western District of New York. GM alleges, among other claims, that the Company violated various federal antitrust laws in connection with billings for electric service provided by the Company at GM's Harrison Radiator Plant at Lockport, New York. GM's claims are for damages incurred and to be incurred. The Company estimates that GM is claiming approximately $8 million, after trebling. The Company believes that it has not violated the federal antitrust laws and that this lawsuit is without merit.
On October 5, 1993, the Magistrate to whom the case had been referred issued a decision recommending that GM's complaint be dismissed. The District Judge responsible for the case, after reviewing GM's exceptions to the decision and the Company's reply, will decide whether to adopt the Magistrate's recommended decision.
(g) By letter dated January 21, 1992, the NYSDEC notified the Company that it had been identified as a potentially responsible party at the Peter Cooper Corporation's Landfill Site (Peter Cooper Site) in the village of Gowanda, New York. Three other potentially responsible parties were identified in the NYSDEC letter. The NYSDEC letter also notified the Company that state surface water and groundwater standards had been exceeded at the Peter Cooper Site and offered the Company an opportunity to conduct or finance a remedial program. NYSDEC indicated that if the Company did not agree to enter into a consent order it would perform the necessary work itself or seek a court order requiring the Company to conduct the work. The Company believes that remediation costs at the Peter Cooper Site might rise to $16 million. By letter dated May 12, 1992, the Company notified the NYSDEC that it believed it had no responsibility for the alleged contamination at the Peter Cooper Site, and it declined to conduct remediation or finance remediation costs.
(h) By letter dated April 20, 1992, the EPA notified the Company that it had been identified as a potentially responsible party at the Bern Metals Removal Site (Bern Metals Site) in Buffalo, New York. Four other potentially responsible parties have been identified by the EPA. The EPA has taken response actions at the Bern Metals Site, including investigation, excavation, and
removal of drums and contaminated soil, and implementation of measures to prevent surface water run-off. The EPA has demanded that the Company reimburse the EPA Hazardous Substances Superfund $2 million in response costs incurred to date by the EPA, with interest accruing from the date of the demand. Future response or remedial costs which the EPA may incur at the Bern Metals Site are not covered by the EPA demand and the EPA has reserved its rights relating to any such costs.
In addition to the foregoing, the NYSDEC, by letter dated July 21, 1992, notified the Company that it had been identified as a potentially responsible party at the Bern Metals Site, which the NYSDEC defined to include an adjacent property known as the Universal Iron & Metal Site (Bern Metals/Universal Iron Site). The Bern Metals/Universal Iron Site is listed on the New York State Registry. The NYSDEC has also identified eight other potentially responsible parties for the Bern Metals/Universal Iron Site. The NYSDEC has requested that the Company, and the eight other identified potentially responsible parties, enter into negotiations in which the Company and the other identified potentially responsible parties would agree to finance or conduct a Remedial Investigation and Feasibility Study (RI/FS) designed to determine what further remediation or removal actions may be appropriate for the Bern Metals/Universal Iron Site. The NYSDEC has provided no estimate of the cost of the response action it proposes. By letter dated December 3, 1992, the Company declined to negotiate with NYSDEC to finance or conduct an RI/FS for the Bern Metals/Universal Iron Site, because the Company believed it was only a very small contributor to the Bern Metals/Universal Iron Site. In addition, the Company believes that it does not have any connection with the Universal Iron & Metal Site.
(i) By letter dated April 20, 1992, the EPA notified the Company that the EPA had reason to believe that the Company was a potentially responsible party for the Clinton-Bender Removal Site (Clinton-Bender Site) in Buffalo, New York. Four other potentially responsible parties have been identified by the EPA. Nine private residential lots and one commercial property at the Clinton-Bender Site are contaminated with lead, allegedly due to run-off from the adjacent Bern Metals Site. The EPA has requested that the Company perform the necessary removal work at the Clinton-Bender Site and the Company is doing so in conjunction with the four other identified potentially responsible parties. The total cost of the removal actions to be performed at the Clinton-Bender Site is estimated to be $3.1 million.
On November 3, 1993, the Company was served with a summons and complaint filed on behalf of certain of the homeowners at the Clinton-Bender Site. Seven other defendants were named in the complaint, which was filed in the New York State Supreme Court, Erie County. The action has since been removed to the U.S. District Court for the Western District of New York (District Court). In their complaint, plaintiffs make general allegations that the defendants violated federal environmental laws without alleging facts in support of these allegations. Plaintiffs also allege personal injury, property damage, and fear of cancer which they claim were caused by the presence of hazardous substances on their property, allegedly resulting from the disposal of such
substances by the defendants at the Bern Metals Site. Any liability incurred as a result of these claims may be joint and several. The plaintiffs ask for $30 million in direct damages from all defendants, as well as treble damages (for unspecified reasons) from all defendants, and an additional $10 million in punitive damages from each defendant. The Company and some of the other defendants in this matter have made a motion to the District Court for dismissal of all claims based upon the Clean Air Act, the Clean Water Act, and the Comprehensive Environmental Response, Compensation, and Liability Act, which are the only claims based upon federal causes of action. The Company believes that its position in this action is meritorious, and it will defend this case vigorously.
(j) By letter dated February 12, 1993, NYSDEC notified the Company that it had been identified as a potentially responsible party for remediation of hazardous wastes at the Booth Oil Site (Booth Oil Site) in North Tonawanda, New York. The Booth Oil Site is listed on the New York State Registry. Twelve other potentially responsible parties were identified in the NYSDEC letter. Booth Oil Company is a waste oil re-refiner and recycler. The Company had sent waste oils to Booth Oil Company for disposal as had numerous other companies in the Buffalo area. According to NYSDEC, the Booth Oil Site is contaminated with PCBs, lead, and other substances. NYSDEC has requested that the Company and the other identified potentially responsible parties conduct remediation at the Booth Oil Site pursuant to an Order on Consent to be negotiated with NYSDEC. NYSDEC has estimated that the present value of costs for on-site treatment alternatives range from $12 million to $24 million.
Item 4.

Item 4. Submission of matters to a vote of security holders - Not applicable.
* * * * * * * * * *
Executive officers of the Registrant
Positions, offices and business experience - Name Age January 1989 to date
James A. Carrigg 60 Chairman, President and Chief Execu- tive Officer, January 1991 to date; Chairman and Chief Executive Officer, to January 1991.
Richard P. Fagan 53 Senior Vice President-Management Services Business Unit, April 1990 to date; Senior Vice President- Administration, March 1989 to April 1990; Senior Vice President to March 1989.
Executive officers of the Registrant (Cont'd)
Positions, offices and business experience - Name Age January 1989 to date
Russell Fleming, Jr. 55 Senior Vice President-Gas Business Unit, October 1990 to date; Partner in Putnam, Hayes and Bartlett (economic and management consultants), New York, New York May 1989 to September 1990; Partner in Theodore Barry & Associates (management consultants), New York, NY to May 1989.
Jack H. Roskoz 55 Senior Vice President-Electric Business Unit, April 1990 to date; Senior Vice President, March 1989 to April 1990; Senior Vice President-Administration to March 1989. John J. Bodkin 48 Vice President-Electric Transmission and Distribution, January 1991 to date; Manager-Power Supply, to January 1991.
Gerald E. Putman 43 Vice President-Fuel Supply and Opera- tion Services, May 1993 to date; Vice- President-East Region Electric, Septem- ber 1992 to May 1993; Executive Assistant to the Chairman, President and Chief Executive Officer, January 1991 to September 1992; District Manager, Auburn, NY to January 1991.
Sherwood J. Rafferty 46 Vice President and Treasurer, September 1990 to date; Treasurer, to September 1990.
Vincent W. Rider 62 Vice President-Generation.
Everett A. Robinson 50 Vice President and Controller, September 1990 to date; Controller, to September 1990.
Irene M. Stillings 54 Vice President-Electric Marketing, January 1991 to date; Assistant Vice President-Consumer Services and Communications, February 1989 to January 1991; Assistant Vice President- Consumer Affairs, to February 1989.
Ralph R. Tedesco 40 Vice President-Strategic Growth Business Unit, February 1994 to date; Executive Assistant to the Chairman, President and Chief Executive Officer, September 1992 to February 1994; Manager, Corporate Performance June 1991 to September 1992; Manager, Research and Development to June 1991.
Executive officers of the Registrant (Cont'd)
Positions, offices and business experience - Name Age January 1989 to date
Denis E. Wickham 45 Vice President-Electric Resource Planning, January 1991 to date; Assistant to Senior Vice President, to January 1991.
The Company has entered into an agreement with James A. Carrigg which provides for his employment as Chairman, President and Chief Executive Officer of the Company for a term ending on December 31, 1996, with automatic one-year extensions unless either he or the Company gives notice that the agreement is not to be extended.
Each officer holds office for the term for which he or she is elected or appointed, and until his or her successor shall be elected and shall qualify. The term of office for each officer extends to and expires at the meeting of the Board of Directors following the next annual meeting of stockholders.
PART II
Item 5.

Item 5. Market for Registrant's common stock and related stockholder matters
See Note 13 to the Consolidated Financial Statements on page 73.
Principal Sources of Electric and Natural Gas Revenues
Item 7. Management's discussion and analysis of financial condition and results of operations
Results of Operations 1993 1992 over over 1992 1991 1993 1992 1991 Change Change (Thousands, except Per Share Amounts)
Operating revenues $1,800,149 $1,691,689 $1,555,815 6% 9% Earnings available for common stock $145,390 $162,973 $148,313 (11%) 10% Average shares outstanding 69,990 67,972 62,906 3% 8% Earnings per share $2.08 $2.40 $2.36 (13%) 2% Dividends per share $2.18 $2.14 $2.10 2% 2%
In 1993, operating revenues increased $108 million, or 6%, compared to 1992. This increase is primarily because of increases in electric and natural gas rates that became effective in August 1992 and September 1993, which totaled $61 million, and the amounts billed to customers for higher costs of non-utility generation (NUG) power and natural gas totaling $51 million.
In 1992, operating revenues rose $136 million, or 9%, compared to 1991. The amounts billed to customers for higher costs of NUG power of $41 million, and increases in electric and natural gas rates effective in February 1991 and August 1992, which totaled $40 million, were the primary reasons for this increase. In addition, higher electric and natural gas retail sales due to an increase in retail customers, colder weather, and the April 1991 acquisition of Columbia Gas of New York, Inc. (CNY) helped boost operating revenues by $51 million in 1992.
Earnings per share decreased 32 cents, or 13%, in 1993 compared to 1992, while earnings per share increased 4 cents, or 2%, in 1992 compared to 1991. Both 1993 and 1992 had non- recurring items that lowered earnings per share. Earnings in 1993 were reduced by 25 cents per share as a result of a corporate restructuring that will reorganize the way the Company delivers services to its electric and natural gas customers beginning in March 1994. This restructuring resulted in a work force reduction throughout the organization of approximately 600, the elimination of customer walk-in services at 28 satellite locations, and the closing of up to 10 electric and natural gas operations facilities statewide. This is one of several actions the Company has taken to reduce future costs, enhance efficiencies in service to its customers, and be competitive in the rapidly changing utility industry (See Competitive
Conditions). A six-month electric rate moratorium, which began in February 1992, limited 1992 earnings per share by 24 cents. Excluding the effect of these non-recurring items, earnings per share decreased 31 cents in 1993 compared to 1992, and increased 28 cents in 1992 compared to 1991.
The 31 cent 1993 decrease in earnings per share was primarily due to lower electric retail sales prior to the effective date of the Company's modified revenue decoupling mechanism (See Regulatory Matters) and lower than anticipated natural gas sales, both resulting from the sluggish economy in the Company's service territory. Also, earnings per share decreased due to changes in the Company's allowed return on equity from 11.7% effective through July 1992, to 11.2% effective through July 1993, and then to 10.8% beginning in August 1993.
In 1992, earnings per share were favorably affected by the growth in electric and natural gas retail sales primarily due to an increase in retail customers, colder weather, and the April 1991 acquisition of CNY. The Company's efforts to control costs also contributed to the increase in 1992 earnings per share.
Average shares outstanding were 70 million in 1993, 68 million in 1992, and 63 million in 1991. Average shares outstanding increased 3% in 1993 compared to 1992 due to the issuance of 1.2 million shares of common stock through the Dividend Reinvestment and Stock Purchase Plan (DRP). In 1992, average shares outstanding increased 8% because of a public offering of 5 million shares of common stock in March 1992, and the issuance of 1 million shares of common stock through the DRP.
Interest Expense
Interest expense (before the reduction for allowance for borrowed funds used during construction) decreased by $10 million, or 6%, in 1993 and $8 million, or 5%, in 1992. Interest on long-term debt decreased in 1993 and 1992 mainly due to the refinancing of certain high-coupon long-term debt at lower interest rates, and lower interest rates on the Company's variable rate debt. In 1993 and 1992 interest expense also decreased due to a reduction in the interest rate on the commercial paper borrowings (See Financing Activities).
Operating Results by Business Unit
1993 1992 over over 1992 1991 Electric 1993 1992 1991 Change Change (Thousands)
Retail sales-kilowatt- hours(kwh) 13,088,175 13,294,466 13,107,115 (2%) 1% Operating revenues $1,527,362 $1,451,525 $1,367,936 5% 6% Operating expenses $1,250,000 $1,146,619 $1,056,969 9% 8%
Electric retail sales decreased 2% in 1993 compared to 1992 as a result of the sluggish economy in the Company's service territory and in spite of a 1% increase of customers. In 1992, electric retail sales increased 1% compared to 1991 mainly due to colder but more normal weather and an increase in customers.
The primary cause of the $76 million, or 5%, increase in electric operating revenues in 1993 was the increase in rates effective August 1992 and September 1993, which accounted for $53 million of the increase. Also contributing to this increase were higher costs of NUG power of $28 million, which were billed to customers. Electric operating revenues increased $84 million, or 6%, in 1992 compared to 1991. This increase reflects the increases in electric rates that became effective February 1991 and August 1992 and that increased revenues by $35 million. The revenue increase reflects higher NUG costs of $41 million and an increase in certain New York State gross receipts taxes of $12 million, both of which were billed to customers. Also, increased electric retail sales, due to colder weather and an increase in customers, boosted revenues by $9 million.
Electric operating expenses increased $103 million, or 9%, in 1993 compared to 1992, and $90 million, or 8%, in 1992 compared to 1991. In 1993, electricity purchased from NUGs increased $67 million. Other operating expenses increased primarily due to an increase in postretirement benefit costs other than pensions of $7 million. In addition, electric operating expenses increased $21 million due to the corporate restructuring. These increases were partially offset by a decrease of $17 million in fuel used in electric generation, the result of lower generation and a decrease in the price of coal, and a decrease of $12 million in federal income taxes, the
result of lower pre-tax book income.
In 1992, electricity purchased increased primarily because of the amounts billed to customers for higher NUG costs, which totaled $41 million. Other operating expenses increased primarily because of higher demand-side management (DSM) program costs of $6 million. Federal income taxes increased $4 million resulting from higher pre-tax book income. Other taxes increased primarily because of an increase in certain New York State gross receipts taxes and property taxes of $16 million. These increases were partially offset by a decrease of $12 million in fuel used in electric generation, the result of lower generation and a decrease in the price of coal, and a decrease in maintenance expense of $7 million.
1993 1992 over over 1992 1991 Natural Gas 1993 1992 1991 Change Change (Thousands)
Deliveries -dekatherms(dth) 58,046 56,366 42,404 3% 33% Retail sales-(dth) 39,345 39,357 29,874 - 32% Operating revenues $272,787 $240,164 $187,879 14% 28% Operating expenses $249,493 $221,307 $177,751 13% 25%
Natural gas deliveries increased 3% in 1993 compared to 1992 while natural gas retail sales were flat. In 1992, natural gas deliveries and retail sales increased 33% and 32%, respectively, compared to 1991. The increase in deliveries in 1993 reflects an increase in the number of transportation customers. The 1992 increases in deliveries, as well as retail sales, are largely because of the April 1991 acquisition of CNY. Excluding CNY, natural gas retail sales increased 8% in 1992, primarily because of the colder but more normal weather.
Natural gas operating revenues rose $33 million, or 14%, in 1993 compared to 1992, and $52 million, or 28%, in 1992 compared to 1991. In 1993, the increase was primarily due to higher costs of natural gas of $23 million, which were billed to customers, and the increases in rates in August 1992 and September 1993, which totalled $8 million. The 1992 revenue increases are principally the result of the acquisition of CNY, which added $35 million, and the increases in rates effective February 1991 and August 1992 amounting to $4 million. Also, the recovery of an increase in certain New York State gross receipts taxes, which were billed to customers, boosted 1992 revenues by $2 million.
Natural gas operating expenses increased $28 million, or 13%, in 1993 compared to 1992. The increase in natural gas purchased was primarily due to higher costs of natural gas amounting to $12 million. Federal income taxes increased $3 million due to higher pre-tax book income. Natural gas operating expenses increased $5 million due to the corporate restructuring.
Natural gas operating expenses increased $44 million, or 25%, in 1992 compared to 1991. Natural gas purchased increased $31 million due to an increase in the volume of natural gas purchased. This volume increase was primarily due to the CNY acquisition. Federal income taxes increased $4 million due to higher pre-tax book income. Other taxes increased primarily due to an increase of $3 million in certain New York State gross receipts taxes and $1 million in property taxes.
Liquidity and Capital Resources
Competitive Conditions
The utility industry is rapidly changing and facing an increasingly competitive environment. Factors contributing to this competitive environment are: the National Energy Policy Act of 1992 (Energy Policy Act), which provides open access at the wholesale level to electric transmission service, and the FERC Order 636, which significantly affects the natural gas industry. In addition, the Company's response to the economic pressures on its electric industrial and other large use customers, high purchase costs of NUGs, rising health care costs, increasing taxes, weak economic conditions, conservation programs, and compliance with environmental laws and regulations are all factors that continue to place increased pressure on electric and natural gas prices.
The Energy Policy Act, enacted in October 1992, is expected to result in major changes to the utility industry. Certain provisions of the Energy Policy Act amended the Public Utility Holding Company Act of 1935 (PUHCA). These amendments encourage greater competition in the supply market by establishing a new category of wholesale electric generators that are exempt from PUHCA regulation. The Energy Policy Act also enables the FERC to order utilities to provide open access to transmission systems for wholesale transactions, expanding opportunities for utilities and NUGs to enter new and existing wholesale markets. These developments serve to underscore the increasingly competitive environment for utilities.
The Company's five-year strategic plan is designed to address the competitive, rapidly changing utility industry. The Company's objective is to remain competitive in its core businesses in the face of increased competition. One of the key strategies to meet competition is to improve customer value by becoming a low-cost provider of energy services in the Northeast.
A major challenge to the Company's Electric Business Unit is to retain and grow its industrial base. The competitive energy supply options currently available to the Company's industrial customers include self-generation, shifting production to plants in other locations, or relocation. During 1993, the Company received PSC approval for a flexible, negotiable rate tariff for some of its high-use industrial customers. Discounts negotiated in agreements under this tariff are not expected to have a material effect on the Company's 1994 earnings. Two agreements have been negotiated which eliminated threats of self-generation and relocation.
The PSC currently has a generic proceeding to study the broad subject of flexible, competitive rates, and will establish guidelines for the Company and other New York State utilities during 1994. Also in late 1993, the PSC instituted a proceeding to address issues associated with the restructuring of the emerging competitive natural gas market. The PSC intends to investigate services provided by New York State gas utilities after FERC Order 636 by the 1994-1995 heating season.
In November 1993, the Company filed with the PSC an additional flexible, negotiable rate tariff to address opportunities for new load. The proposed tariff is for large additions to load (at least 500 kilowatts [kw]) for new or existing industrial and some commercial customers. The tariff will assist the Company in attracting new customers whose location or expansion decisions are influenced by electricity costs. Smaller customers will be assisted by a concurrent proposal to increase the Company's existing economic development incentives by one cent per kilowatt-hour. The Company has proposed and will continue to propose revisions or additional tariffs to respond to the opportunities or risks that develop in a changing electric utility industry.
A major challenge to the Company's Gas Business Unit is FERC Order 636, which became effective in November 1993, and requires interstate natural gas pipeline companies to offer customers unbundled or separate services equivalent to their former sales service. With the unbundling of services, primary responsibility for reliable natural gas supply will shift from interstate pipeline companies to local distribution companies, such as the Company. This should result in increased direct access to low cost natural gas supplies by local distribution companies and end users. One goal of FERC Order 636 is to provide equitable access
to interstate pipeline capacity. FERC Order 636 will substantially restructure the interstate natural gas market and intensify competition within the natural gas industry. FERC Order 636 will allow the Company, subject to PSC approval, to restructure rates and provide multiple service options to its customers.
In July 1993, certain interstate pipelines serving the Company began implementing restructured services in compliance with FERC Order 636. The remaining pipelines implemented restructured services by November 1993. As a result of these restructuring changes, pipelines have incurred and will continue to incur transition costs. These transition costs include those associated with restructuring existing natural gas supply contracts, the unrecovered natural gas cost that would otherwise have been billable to pipeline customers under previously existing rules, costs of assets needed to implement the order, and stranded investment costs. FERC Order 636 allows pipelines to recover all prudently incurred costs from their customers. The Company's liability for transition costs will be based on the pipelines' filings with FERC to recover transition costs. Only a few of those filings have been made. The Company recorded an estimated liability for transition costs of approximately $29 million. The Company also recorded a deferred asset for that amount since it is currently recovering transition costs from its customers through its gas adjustment clause and believes that such costs will continue to be recoverable from its customers.
The Company has developed a more aggressive and accelerated set of strategies in response to the increased challenges of competition which are necessary to achieve the objectives outlined in the Company's five-year strategic plan. The following represent strategies being implemented: - Reduce forecasted 1994 capital expenditures by one-third, or approximately $100 million. Additional reductions will be made in 1995 and 1996. - Reduce operating and maintenance expenses by five percent in 1994 and again in 1995. By 1995, this will save about $40 million annually. During 1993, the Company reduced its work force by 200 through attrition. In addition, as part of the O&M reduction, the Company's work force was further reduced by about 600 through an early retirement opportunity program and involuntary severance. - Streamline the field organization to eliminate walk-in customer service at 28 locations, and to close up to 10 electric and natural gas operations facilities statewide. - Place two generating units on long-term cold standby. - Continue to reduce NUG costs. The Company's previous NUG contract terminations and renegotiations will save customers more than $1 billion over the terms of the contracts. - Continue to reduce capital costs. Since 1988 the Company has refinanced over $1.4 billion in securities, and reduced
annual interest expense by more than $55 million.
The cost of the corporate restructuring was $26 million and was a one-time charge against the Company's 1993 earnings. The restructuring reduced 1993 earnings available for common stock by approximately $17.2 million or 25 cents per share. Included in this amount are $13.2 million for a voluntary early retirement program, $3.2 million for an involuntary severance program, and $.8 million for the elimination and closing of operations facilities. The Company expects to recoup the one-time charge from lower O&M costs in approximately one year.
As part of the Company's effort to meet competition and minimize future price increases associated with uneconomical power purchases from NUGs, it negotiated the termination of two cogeneration projects. This effort, along with the termination of NUG contracts due to developers' failures to meet contract obligations, will save customers nearly $1 billion over the terms of the contracts. The Company has also recently negotiated amendments with two NUGs whereby the Company may direct the NUGs to reduce their output or shut down for limited periods each year. During these periods, lower-cost generation will replace the NUG energy and result in additional customer savings. The Company is negotiating with other NUGs for similar amendments.
The Company has on line and under contract 362 megawatts (mw) of NUG power. In addition, another 240 mw of NUG power is under construction. The Company is required to make payments under these contracts only for the power it receives. During 1993, 1992, and 1991, the Company purchased approximately $138 million, $71 million, and $30 million, respectively, of NUG power. The Company estimates that it will purchase approximately $255 million, $291 million, and $335 million of NUG power for the years 1994, 1995, and 1996, respectively. Increases in NUG power purchase costs are expected to be a significant contributor to price increases over the next three years.
Diversification
Diversification will play an important role in the Company's future. While the strength of the Company's core electric and natural gas businesses remains its focus, and while the Company will not compromise its financial integrity, it is actively evaluating a number of corporate development opportunities for investment to help augment future earnings and dividend growth. In April 1992, the PSC issued an order allowing the Company to invest up to 5% of its consolidated capitalization (approximately $175 million at December 31, 1993) in one or more subsidiaries that may engage or invest in energy-related or environmental services businesses and provide related services. In May 1993, NGE Enterprises, Inc. (NGE), a wholly-owned subsidiary of the Company, formed a computer software company, EnerSoft Corporation
(EnerSoft), to produce and market software applications for natural gas utilities in the post-FERC Order 636 environment. This represents NGE's initial diversified investment.
In October 1993, EnerSoft began a strategic alliance with the New York Mercantile Exchange to develop an information superhighway that will provide the natural gas industry with a single system for monitoring and trading natural gas and pipeline capacity in the North American market. NGE invested approximately $9 million in EnerSoft through February 1994.
The Company and NGE plan to develop two natural gas storage projects. One of the projects, which will be regulated by the PSC, is expected to cost approximately $14 million and will be used to supplement the Company's natural gas supply. Construction of this project is scheduled to begin in 1994 and it is expected to be operating for the 1995-96 heating season. The other project, which will be regulated by the FERC, is an equal partnership between NGE and ANR Storage, Inc., and is expected to cost approximately $44 million in total. The entire capacity of this project will be marketed to local distribution companies and NUGs, as well as marketers, producers, and end users of natural gas. Construction of this project is scheduled to begin in 1995 and it is expected to be operating for the 1996-1997 heating season.
Financing Activities
The Company believes that maintaining a high degree of financial integrity and flexibility is critical to success in an increasingly competitive environment. The Company intends to build on the financial improvements realized over the past several years with a goal of achieving a 50% common equity ratio. New money needs are expected to be minimal and excess cash generated from reduced construction expenditures will be used to further manage the Company's capital structure (See Investing Activities - estimated sources and uses of funds for 1994-1996).
The PSC adopted a new, innovative approach in December 1993 when it issued an order to the Company that provides for advanced approval for financings during the Company's three-year rate settlement. That order includes authorization for refundings of first mortgage bonds, preferred stock, and tax-exempt pollution control notes, issuance of common stock through the Dividend Reinvestment and Stock Purchase Plan (DRP), and issuances of other securities as required. With this order, the Company has the flexibility to achieve its financial goals of further reducing financing costs and improving its financial health as market conditions allow.
The common stock equity ratio remained stable during 1993. Issuance of shares under the DRP was offset by the issuance of
$100 million of preferred stock and $70 million of tax-exempt pollution control notes in December 1993. The Company received $38.4 million from the issuance of 1.2 million shares of common stock through the DRP.
Common stock dividends paid in 1993 increased 5% over 1992 reflecting the increase in common stock outstanding and an increase in the dividend paid from $2.14 to $2.18 per share.
The Company's dividend payout ratio has been gradually rising over the past several years, primarily as a result of declining earnings. These weak earnings put additional pressure on an already high dividend payout ratio at a time when growing competition dictates that we consider a more moderate dividend policy. We must significantly improve earnings if we are to continue even modest annual dividend increases.
The Company sold $25 million of 6.30% preferred stock, $50 million of Adjustable Rate Series B preferred stock, and $25 million of 7.40% preferred stock in December 1993. The net proceeds were used to redeem $25 million of 8.80% preferred stock and $45 million of Adjustable Rate Series A preferred stock in January 1994, and $25 million of 8.48% preferred stock in February 1994. Those refundings will save approximately $1.8 million annually. After those refundings, the capital structure will be 49.8% long-term debt, 7.1% preferred stock, and 43.1% common stock equity.
In February 1993, the Company redeemed, at par, through a sinking fund provision in our mortgage, the remaining $22.5 million of 10 5/8% Series first mortgage bonds due 2018.
In February 1993, the Company priced $100 million of 6.05% tax-exempt pollution control bonds, due 2034. Proceeds from the sale, which will be delivered in April 1994, will be used to redeem, at a premium, $60 million of 12% pollution control bonds, due 2014, and $40 million of 12.3% pollution control bonds, due 2014. The refunding of those bonds in 1994 will save approximately $5.3 million annually in interest costs.
In April 1993, the Company sold $50 million of 7.55% Series first mortgage bonds due 2023. Net proceeds from the sale were used in connection with the redemption of $50 million of the 9 1/4% Series due 2016. The refunding of those bonds will save approximately $300,000 annually in interest costs.
In July 1993, the Company sold $100 million of 7.45% Series first mortgage bonds due 2023. Net proceeds from the sale were used in connection with the redemption of $100 million of the 9% Series due 2017. The refunding of those bonds will save approximately $650,000 annually in interest costs.
In November 1993, the Company redeemed $50 million of the 8 5/8% Series first mortgage bonds due 1996, at a premium. Proceeds for the redemption were provided by a borrowing under the Company's revolving credit agreement. The refunding of those bonds will save approximately $2 million annually in interest costs.
In December 1993, $70 million of 5.70% tax-exempt pollution control notes, due 2028, were issued by a governmental authority on behalf of the Company. Proceeds from the sale will be used to finance a portion of the costs incurred in the construction of certain solid waste disposal and other related facilities at the Company's Milliken Generating Station.
The Company has reduced its embedded cost of long-term debt to 7.2% at the end of 1993 from 9.2% in 1988. The Company has refinanced more than $1.2 billion in long-term debt since 1988, and reduced annual interest expense by more than $55 million. Unless interest rates fall further, however, it will be difficult to significantly improve from the 7.2% level. All opportunities continue to be pursued aggressively.
In February 1994, the Company redeemed, at par, through a sinking fund provision in its mortgage, $23 million of 8 5/8% Series first mortgage bonds due 2007.
In February 1994, $37.5 million of tax-exempt pollution control notes were issued by a governmental authority on behalf of the Company. The notes will have several interest rate options and have an initial rate of 2.4% through April 13, 1994. Proceeds from the sale will be used to redeem $37.5 million of annual adjustable rate pollution control notes, due 2015, in March 1994.
The Company uses interim financing in the form of short-term unsecured notes, usually commercial paper, to finance certain refundings and construction expenditures and for other corporate purposes, thereby providing flexibility in the timing and amounts of long-term financings. There was $50.2 million of commercial paper outstanding at December 31, 1993, at a weighted average interest rate of 3.5%. The weighted average interest rate during 1993 was 3.4%.
The Company also has a revolving credit agreement with certain banks that provides for borrowing up to $200 million to July 31, 1997. The Company had an outstanding $50 million loan under this agreement at December 31, 1993, at an interest rate of 4.06%.
In June 1993, the Company's first mortgage bonds and unsecured pollution control notes were upgraded by Standard & Poor's (S&P). The investment rating agency stated that the
higher ratings reflect expected continued improvements in the Company's financial condition as a result of the Company's three- year rate settlement, which was pending at the time of the upgrade, aggressive cost controls, and limited new money needs. S&P also noted that regulatory adjustment mechanisms, such as electric revenue decoupling and natural gas weather normalization, should add stability to earnings.
In October 1993, S&P completed its review of the U.S. investor-owned utility industry and concluded that more stringent financial benchmarks were appropriate for electric utilities to counter increased competition and mounting business risk. As a result, it revised the rating outlook downward for about one- third of the utility industry, including the Company. However, the Company's ratings were not changed.
Investing Activities
The Company's 1993 capital expenditures for its core electric and natural gas businesses totaled approximately $245 million. Most of the expenditures were for the extension of service and for improvements at existing facilities.
Capital expenditures for 1994-1996 have been significantly reduced from previously forecasted levels. This represents one of many actions the Company is taking to address competition (See Competitive Conditions). Capital expenditures for 1994-1996 will be primarily for extension of service, necessary improvements at existing facilities, and compliance with the Clean Air Act Amendments of 1990 (See Environmental Matters). The Company forecasts that its current reserve margin, coupled with more efficient use of energy (See Conservation Programs) and generation from NUGs, will eliminate the need for additional generating capacity until after the year 2005.
As part of the Company's effort to reduce costs, one of two generating units at each of its Goudey and Greenidge Generating Stations will be placed on long-term cold standby. These actions are being taken because the abundance of power in the Northeast has driven down wholesale prices. These units will continue to be utilized to provide electrical system support.
The following table provides information on the Company's estimated sources and uses of funds for 1994-1996. This forecast is subject to periodic review and revision, and actual construction costs may vary because of revised load estimates, imposition of additional regulatory requirements, and the availability and cost of capital.
1994 1995 1996 Total ---- ---- ---- ----- Sources of funds (Millions)
Internal funds $254 $265 $269 $788 Long-term financing Debt and stock proceeds 413 141 80 634 Debt proceeds held in trust 34 8 - 42 ---- ---- ---- ----- Net financing proceeds 447 149 80 676
Increase (decrease) in short-term debt (50) - - (50) Decrease (increase) in temporary cash investments 89 (69) (52) (32) ---- ---- ---- ------ Total $740 $345 $297 $1,382 ==== ==== ==== ====== Uses of funds
Construction Cash expenditures $202 $193 $193 $588 AFDC 8 7 7 22 ---- ---- ---- ------ Total construction 210 200 200 610 Retirement of securities and sinking fund obligations 501 108 63 672 Working capital and deferrals 29 37 34 100 ---- ---- ---- ------ Total $740 $345 $297 $1,382 ==== ==== ==== ======
As shown in the preceding table, internal sources of funds represent 129% of construction expenditures for 1994-1996.
Conservation Programs
The Company has implemented a number of demand-side management (DSM) programs. As a result of its three-year rate settlement agreement (See Regulatory Matters), incentives earned for conducting efficient DSM programs were reduced from 15% to 5% of the net resource savings achieved by these DSM programs. For 1994, the Company expects to earn approximately $3 million in incentives as a result of these DSM programs.
In 1993, the Company's customers saved approximately 282 million kilowatt-hours (kwh) on an annualized basis through the Company's DSM programs. The implementation of these programs cost $48 million in 1993 and will cost approximately $16 million in 1994 with estimated customer savings of 113 million kwh on an annualized basis. The Company has approximately $73 million and $44 million of deferred DSM program costs on the Consolidated Balance Sheets at December 31, 1993, and 1992, respectively. The two-year (1993-1994) DSM plan, which has received PSC approval, has been modified to improve cost-effectiveness and reduce rate impacts.
Environmental Matters
The Company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Compliance programs will increase the cost of electric and natural gas service by requiring changes to the Company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred for compliance with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the Company may also incur costs from the past disposal of hazardous substances produced during the Company's operations or those of its predecessors. The Company has been notified by the EPA and the NYSDEC that it is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at seven waste sites, not including the Company's inactive gas manufacturing sites, which are discussed below. With respect to the seven sites, five sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry).
Any liability may be joint and several for certain of these sites. The ultimate cost to remediate these sites will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the Company. At December 31, 1993, the Company recorded a liability in the Consolidated Balance Sheets related to four of these seven waste sites of $1.8 million. The Company has notified the NYSDEC that it believes it has no responsibility at two sites and has already incurred expenditures related to the remediation at the remaining site. A deferred asset has also been recorded in the amount of $2.6 million, of which $.8 million relates to costs that have already been incurred. The Company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the Company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites. This $1.8 million estimate was derived by
multiplying the total estimated cost to clean up a particular site by the related Company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the Company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the Company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the Company's inactive gas manufacturing sites have been listed in the New York State Registry. The Company has filed petitions to delist the majority of the sites. The Company's program to investigate and initiate remediation at its 38 known inactive gas manufacturing sites has been extended through the year 2000. Expenditures over this time period are estimated to be $25 million. This estimate was determined by using the Company's experience and knowledge related to these sites as a result of the investigation and remediation that the Company has performed to date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability, to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites is reflected in the Company's Consolidated Balance Sheets at December 31, 1993 and 1992. The Company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the Company has previously been allowed by the PSC to recover such costs in rates. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in significant expenditures of approximately $178 million, on a present value basis, over a 25-year period, for all capital and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the Company's coal-fired generating stations, of which $51 million has been incurred as of December 31, 1993. The Company's current estimate is a significant reduction from its prior estimate, primarily due to the postponement of the construction of a flue gas desulfurization (FGD) system at its Homer City Generating
Station. The Company plans to re-evaluate the need to construct an FGD system at the Homer City Generating Station in 1995, since its present strategy to bank Phase I emissions allowances for use during Phase II, as discussed below, will allow the Company to meet Phase II allowance requirements through the year 2005. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative FGD system and a nitrogen oxide reduction system expected to be completed in 1995 at the Company's Milliken Generating Station. The Company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (begins January 1, 1995) and Phase II (begins January 1, 2000). As a result of the 1990 Amendments, the Company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the Company to meet the sulfur dioxide levels established for the Company, which is approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time. Regulations may be adopted at the state level which would limit toxic emissions even further, at an additional cost to the Company. The Company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the U.S. Environmental Protection Agency (EPA) to allocate annual emissions allowances to each of the Company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the Company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The Company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the Company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the Company by the EPA, the Company will receive a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers, as a result of the pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the Company will incur approximately $24 million, on a present value basis, of additional costs over the next 30 years, beginning in 1994, at the Homer City Generating Station. These costs will be incurred to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The Company expects to recover these expenditures in rates, since the Company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Regulatory Matters
In September 1993, the Company reached a three-year electric and natural gas rate settlement agreement (Agreement) with the PSC. The new electric and natural gas rates became effective September 4, 1993.
The allowed return on equity is 10.8% in year one, 11.4% in year two, and 11.4% (subject to an indexing mechanism) in year three. Shareholders will be allowed to keep 100% of any earnings in excess of the allowed return in year one. Shareholders and customers will share, on a 50%/50% basis, any earnings in excess of the allowed return in years two and three.
The Agreement also includes a modified revenue decoupling mechanism (RDM) for electric sales. Rates are based on sales forecasts. Since actual sales may differ significantly from forecasted sales because of conservation efforts, unusual weather, or changing economic conditions, the revenue collected may be more or less than forecast. Subject to the caps described below, the modified RDM will let the Company adjust for most of the differences between forecasted and actual sales. For example, if revenues exceed the forecast for a given year, the excess would be passed back to customers in a future year. If revenues are below the forecast, customers would receive a surcharge in a future year. The Company will share excesses or shortfalls from most large commercial and industrial sales revenues on a 70%/30% (customer/stockholder) basis.
Customer savings for production and transmission operating costs of $21 million will be imputed over three years, $7 million each year, whether or not they are realized.
Incentives for customer service, production cost, and DSM could increase the allowed return to 12.3% or decrease it to 9.95% in year one, increase it to 13.05% or decrease it to 10.4% in year two, and increase it to 13.25% or decrease it to 10.2% in year three.
The electric and natural gas rate increases discussed below represent eleven months for year one and twelve months for years two and three.
The estimated total electric price increases below include base rate increases allowed by the Agreement plus estimates of fuel and purchased power increases which will be collected through the Fuel Adjustment Clause (FAC). Actual fuel and purchased power costs could vary from estimates causing the estimated FAC and total electric price increases below to change.
Base Rate Estimated FAC Total Electric (Dollar Amounts in Millions)
Year 1 $60.5 4.4% $39.1 3.0% $99.6 7.4% Year 2 $70.3 4.8% $39.2 2.8% $109.5 7.6% Year 3 $57.4 3.6% $30.4 2.0% $87.8 5.6%
The natural gas base rate increases allowed by the Agreement are $7.5 million, or 2.9%, $8.2 million, or 3.0%, and $7.2 million, or 2.5%, in years one, two, and three, respectively. They do not include changes in natural gas costs, which will be collected through the Gas Adjustment Clause. Natural gas costs can be expected to rise and fall with overall natural gas market conditions. Such fluctuations will affect the total natural gas price increases.
The Agreement also provides for the stated electric and natural gas base rate increases to be adjusted up or down in the second and third years, as well as the year after the Agreement period (year four). These adjustments will depend on several factors, such as electric sales and incentive mechanisms. The Agreement provides that no cap would apply to any downward revision to base rates for electric and natural gas service. The electric base rate increases could be increased by up to 1.5% in years two and three and 1.6% in year four (the caps). The natural gas base rate increases could also be increased by up to 1% in year two and 1.2% in year three. The Agreement does not specify a cap for natural gas base rates for year four.
Item 8. Financial statements and supplementary data
New York State Electric & Gas Corporation Consolidated Statements of Income
Year Ended December 31 1993 1992 1991 - ---------------------------------------------------------------------------- (Thousands, except Per Share Amounts)
Operating Revenues Electric . . . . . . . . . . . . . . . . $1,527,362 $1,451,525 $1,367,936 Natural gas. . . . . . . . . . . . . . . 272,787 240,164 187,879 ---------- ---------- ---------- Total Operating Revenues . . . . . . $1,800,149 1,691,689 1,555,815 ---------- ---------- ---------- Operating Expenses Fuel used in electric generation . . . . 245,283 262,531 274,877 Electricity purchased (Note 9) . . . . . 161,967 95,026 45,808 Natural gas purchased. . . . . . . . . . 141,635 126,815 99,528 Other operating expenses . . . . . . . . 349,177 318,680 279,364 Restructuring expenses (Notes 6 and 7) . 26,000 - - Maintenance. . . . . . . . . . . . . . . 111,757 102,500 110,131 Depreciation and amortization (Note 1) . 164,568 158,977 152,380 Federal income taxes (Notes 1 and 2) . . 94,144 102,456 94,447 Other taxes (Note 12). . . . . . . . . . 204,962 200,941 178,185 ---------- ---------- ---------- Total Operating Expenses . . . . . . . 1,499,493 1,367,926 1,234,720 ---------- ---------- ---------- Operating Income. . . . . . . . . . . . . 300,656 323,763 321,095 Other Income and Deductions . . . . . . . 6,471 12,036 6,076 ---------- ---------- ---------- Income Before Interest Charges. . . . . . 307,127 335,799 327,171 ---------- ---------- ---------- Interest Charges Interest on long-term debt . . . . . . . 134,330 145,822 151,649 Other interest . . . . . . . . . . . . . 11,120 9,566 11,877 Allowance for borrowed funds used during construction. . . . . . . . (4,351) (3,557) (4,998) ---------- ---------- ---------- Interest Charges - Net . . . . . . . . 141,099 151,831 158,528 ---------- ---------- ---------- Net Income. . . . . . . . . . . . . . . . 166,028 183,968 168,643 Preferred Stock Dividends . . . . . . . . 20,638 20,995 20,330 ---------- ---------- ---------- Earnings Available for Common Stock . . . $145,390 $162,973 $148,313 ========== ========== ========== Earnings Per Share. . . . . . . . . . . . $2.08 $2.40 $2.36 Average Shares Outstanding. . . . . . . . 69,990 67,972 62,906
The notes on pages 50 through 73 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1993 1992 - ------------------------------------------------------------------------------- (Thousands) Assets
Utility Plant, at Original Cost (Note 1) Electric (Note 8). . . . . . . . . . . . . . . . . . . $4,777,368 $4,573,444 Natural gas. . . . . . . . . . . . . . . . . . . . . . 381,389 352,059 Common . . . . . . . . . . . . . . . . . . . . . . . . 158,986 157,979 ---------- ---------- . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,317,743 5,083,482 Less accumulated depreciation. . . . . . . . . . . . . 1,541,456 1,427,793 ---------- ---------- Net Utility Plant in Service. . . . . . . . . . . . 3,776,287 3,655,689 Construction work in progress. . . . . . . . . . . . . 143,859 177,566 ---------- ---------- Total Utility Plant . . . . . . . . . . . . . . . . 3,920,146 3,833,255
Other Property and Investments, net . . . . . . . . . . 73,537 59,157
Current Assets Cash and cash equivalents (Notes 1 and 10) . . . . . . 4,264 3,968 Special deposits (Note 10) . . . . . . . . . . . . . . 145,335 96,432 Accounts receivable, net (Note 1). . . . . . . . . . . 181,586 171,683 Fuel, at average cost. . . . . . . . . . . . . . . . . 54,791 69,077 Materials and supplies, at average cost. . . . . . . . 48,910 50,637 Prepayments. . . . . . . . . . . . . . . . . . . . . . 30,092 37,897 Accumulated deferred federal income tax benefits (Notes 1 and 2). . . . . . . . . . . . - 1,182 ---------- ----------
Total Current Assets. . . . . . . . . . . . . . . . 464,978 430,876
Deferred Charges (Note 1) Unfunded future federal income taxes (Notes 1 and 2) . . . . . . . . . . . . . . . 380,056 393,720 Unamortized debt expense . . . . . . . . . . . . . . . 112,059 96,378 Demand-side management program costs . . . . . . . . . 73,113 44,049 Other. . . . . . . . . . . . . . . . . . . . . . . . . 252,127 220,481 ---------- ---------- Total Deferred Charges. . . . . . . . . . . . . . . 817,355 754,628 ---------- ---------- Total Assets. . . . . . . . . . . . . . . . . . . . $5,276,016 $5,077,916 ========== ==========
The notes on pages 50 through 73 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1993 1992 - ------------------------------------------------------------------------------ (Thousands) Capitalization and Liabilities
Capitalization Common stock equity Common stock ($6.66 2/3 par value, 90,000,000 shares authorized and 70,595,985 and 69,439,397 shares issued and outstanding at December 31, 1993 and 1992, respectively) . . . . . . . . . . $470,640 $462,929 Capital in excess of par value. . . . . . . . . . 824,943 796,505 Retained earnings . . . . . . . . . . . . . . . . 320,114 327,040 ---------- ---------- Total common stock equity. . . . . . . . . . . . . . . 1,615,697 1,586,474 Preferred stock redeemable solely at the option of the Company (Note 4). . . . . . . . . . . . . . . . 140,500 160,500 Preferred stock subject to mandatory redemption requirements (Notes 4 and 10) . . . . . . . . . . . 125,000 106,900 Long-term debt (Notes 3 and 10). . . . . . . . . . . . 1,630,629 1,777,027 ---------- ---------- Total Capitalization. . . . . . . . . . . . . . . 3,511,826 3,630,901 Current Liabilities Current portion of long-term debt and preferred stock (Notes 3 and 4) . . . . . . . . . . . . . . . 332,709 115,659 Commercial paper (Notes 5 and 10). . . . . . . . . . . 50,200 64,100 Accounts payable and accrued liabilities . . . . . . . 111,481 95,996 Interest accrued (Note 10) . . . . . . . . . . . . . . 31,348 37,690 Accumulated deferred federal income taxes (Notes 1 and 2) . . . . . . . . . . . . . . . . . . 1,132 - Other. . . . . . . . . . . . . . . . . . . . . . . . . 89,443 65,073 ---------- ---------- Total Current Liabilities . . . . . . . . . . . . 616,313 378,518
Deferred Credits Accumulated deferred investment tax credits (Notes 1 and 2) . . . . . . . . . . . . . . . . . . 138,478 141,729 Excess deferred federal income taxes (Notes 1 and 2) . 36,378 58,188 Other. . . . . . . . . . . . . . . . . . . . . . . . . 149,620 107,160 ---------- ---------- Total Deferred Credits. . . . . . . . . . . . . . 324,476 307,077
Accumulated Deferred Federal Income Taxes (Notes 1 and 2) Unfunded future federal income taxes . . . . . . . . . 380,056 393,720 Other. . . . . . . . . . . . . . . . . . . . . . . . . 416,545 342,700 ---------- ---------- Total Accumulated Deferred Federal Income Taxes . . . . . . . . . . . . . . . . . . 796,601 736,420
Commitments and Contingencies (Note 9). . . . . . . . . 26,800 25,000 ---------- ---------- Total Capitalization and Liabilities. . . . . . . $5,276,016 $5,077,916 ========== ==========
The notes on pages 50 through 73 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
1 Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the Company's wholly-owned subsidiaries, Somerset Railroad Corporation (SRC) and NGE Enterprises, Inc. (NGE). All significant intercompany balances and transactions are eliminated in consolidation.
Utility plant
The cost of repairs and minor replacements is charged to the appropriate operating expense accounts. The cost of renewals and betterments, including indirect cost, is capitalized. The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
Depreciation and amortization
Depreciation expense is determined using straight-line rates, based on the average service lives of groups of depreciable property in service. Depreciation accruals were equivalent to 3.4%, 3.3%, and 3.3%, of average depreciable property for 1993, 1992, and 1991, respectively. Depreciation expense includes the amortization of certain deferred charges authorized by the Public Service Commission of the State of New York (PSC).
Revenue
During 1993, 1992, and 1991, the Company recognized on the income statement approximately $12 million, $22 million, and $40 million, respectively, of electric and natural gas unbilled revenues that had been accrued on its balance sheet for energy provided but not yet billed to minimize the rate increases for these years in accordance with various PSC rate decisions. The July 1992 rate decision allowed the Company to recognize on its income statement, beginning in August 1992, electric and natural gas unbilled revenues on a full accrual basis.
The Company recognizes as revenue incentives earned as the result of conducting efficient demand-side management (DSM) programs. The Company is collecting those incentives in rates within approximately one year after they are recognized. During 1993, 1992, and 1991, incentives earned were $16.4 million, $15.6 million, and $12.4 million, respectively. At December 31, 1993 and 1992, approximately $14.3 million and $9.8 million, respectively, of DSM incentives were accrued and included in accounts receivable.
Accounts receivable
The Company has an agreement that expires in November 1996 to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allows the Company to receive up to $152 million from the sale of such interests. At December 31, 1993 and 1992, accounts receivable on the Consolidated Balance Sheets is shown net of $152 million and $138 million, respectively, of interests in accounts receivable sold. All fees associated with the program are included in other income and deductions on the Consolidated Statements of Income and amounted to approximately $5.7 million, $6.5 million, and $9.3 million in 1993, 1992, and 1991, respectively. Accounts receivable on the Consolidated Balance Sheets is also shown net of an allowance for doubtful accounts of $4 million and $1.9 million at December 31, 1993 and 1992, respectively. Bad debt expense was $15.3 million, $11.5 million, and $10.7 million in 1993, 1992, and 1991, respectively.
Federal income taxes
The Company adopted Statement of Financial Accounting Standards No. 109 (SFAS 109), Accounting for Income Taxes, in January 1993. Since the Company had been accounting for income taxes under Statement of Financial Accounting Standards No. 96, Accounting for Income Taxes, there was no effect on the Consolidated Statements of Income as a result of adopting SFAS 109. However, SFAS 109 did require the Company's deferred tax balances to be reclassified on its Consolidated Balance Sheets.
The Company files a consolidated federal income tax return with SRC and NGE. Deferred income taxes are provided on all temporary differences between financial statement basis and taxable income. Investment tax credits, which reduce federal income taxes currently payable, are deferred and amortized over the estimated lives of the applicable property. The effect of the alternative minimum tax, which increases federal income taxes currently payable and generates a tax credit available for future use, is deferred and amortized at such times as the tax credit is used on the Company's federal income tax return.
Deferred charges
The Company defers certain incurred expenses when authorized by the PSC. Those expenses will be recovered from customers in the future.
Consolidated Statements of Cash Flows
The Company considers all highly liquid investments with a maturity or put date of three months or less when acquired to be
cash equivalents. These investments are included in cash and cash equivalents on the Consolidated Balance Sheets.
Total income taxes paid were $27.3 million, $38.5 million, and $31.8 million for the years ended December 31, 1993, 1992, and 1991, respectively.
Interest paid, net of amounts capitalized, was $138.2 million, $149.3 million, and $159.9 million for the years ended December 31, 1993, 1992, and 1991, respectively.
The Company purchased all of the common stock of Columbia Gas of New York, Inc. in 1991. In conjunction with the acquisition, liabilities assumed were $24.9 million (fair value of assets acquired of $82 million less cash paid of $57.1 million).
Reclassification
Certain amounts have been reclassified on the consolidated financial statements to conform with the 1993 presentation.
2 Federal Income Taxes
Year ended December 31 1993 1992 1991 (Thousands) Charged to operations Current $34,989 $37,237 $22,991 Deferred - net Accelerated depreciation 49,580 41,492 37,409 Unbilled revenues 5,073 160 13,644 Alternative minimum tax (AMT) credit (3,194) 2,123 5,557 Demand-side management 13,479 9,324 8,589 NUG termination agreement 4,760 6,800 - Nine Mile No. 2 litigation proceeds 4,756 (2,047) - Restructuring expenses (6,965) - - Transmission facility agreement(7,778) (1,172) (1,162) Miscellaneous (6,198) (3,491) (9,365) Investment tax credit (ITC) deferred 5,642 12,030 16,784 ------- -------- ------- 94,144 102,456 94,447 Included in other income Amortization of deferred ITC (8,892) (16,927) (11,297) Miscellaneous 498 3,747 (533) ------- -------- ------- Total $85,750 $89,276 $82,617 ======= ======== =======
The Company's effective tax rate differed from the statutory rate of 35% in 1993 and 34% in 1992 and 1991 due to the following:
Year ended December 31 1993 1992 1991 (Thousands)
Tax expense at statutory rate $88,684 $92,903 $85,428 Depreciation not normalized 16,984 16,697 16,051 ITC amortization (8,892) (16,927) (11,297) Research & Development (R&D) credit (5,139) - - Cost of removal (4,921) (4,079) (6,120) Other - net (966) 682 (1,445) ------- ------- ------ Total $85,750 $89,276 $82,617 ======= ======= ======= The Company's current and noncurrent deferred taxes, which net to a tax liability of approximately $936.2 million as of December 31, 1993, consisted of the following deferred tax assets and liabilities:
Deferred Tax Deferred Tax Assets Liabilities (Thousands) Depreciation $ 698,939 Loss on reacquired debt 28,440 Regulatory Asset (SFAS 109) 149,636 Accumulated deferred ITC 91,006 Demand-side management 35,381 NUG contract settlement costs 15,163 Alternative minimum tax credit $ 19,953 Excess tax reserve 12,603 Nine Mile No. 2 disallowed plant 19,347 Contributions in aid of construction 20,913 Capitalized interest 8,690 Other 35,369 34,521 ----------- ------------ Total deferred taxes $116,875 $1,053,086 =========== ============
The Revenue Reconciliation Act (RRA) of 1993 was enacted on August 10, 1993. Among other things, RRA 1993 provided for an increase of 1% in the statutory corporate income tax rate and an extension of the R&D credit until June 30, 1995.
In September 1993, the Company reached a three-year rate settlement agreement with the PSC (Agreement) which included a provision for the Company to petition to defer the effect of RRA 1993 until it is reflected in rates. The Company has deferred for collection from customers $.6 million representing additional 1993 federal income taxes resulting from RRA 1993.
The Company has recorded unfunded future federal income taxes and a corresponding receivable from customers of approximately $381 million and $393 million as of December 31, 1993 and 1992, respectively, primarily representing the cumulative amount of federal income taxes on temporary depreciation differences, which were previously flowed through to customers. Those amounts, including the tax effect of the future revenue requirements, are being amortized over the life of the related depreciable assets concurrent with their recovery in rates.
The Company has approximately $20 million of AMT credits which do not expire, and $5.1 million of R&D credits which expire beginning in 2005.
3 Long-Term Debt
At December 31, 1993 and 1992, long-term debt was (Thousands):
First mortgage bonds Amount
Series Due 1993 1992
8 3/8% Aug. 15, 1994 $ 100,000 $100,000 8 5/8% June 1, 1996 - 50,000 5 5/8% Jan. 1, 1997 25,000 25,000 6 1/4% Sept. 1, 1997 25,000 25,000 6 1/2% Sept. 1, 1998 30,000 30,000 7 5/8% Nov. 1, 2001 50,000 50,000 6 3/4% Oct. 15, 2002 150,000 150,000 9 3/8% Jan. 1, 2006 - 3,000 7 1/4% June 1, 2006 12,000 12,000 6 7/8% Dec. 1, 2006 25,250 25,500 8 5/8% Nov. 1, 2007 60,000 60,000 9 1/4% Apr. 1, 2016 - 50,000 9% Mar. 1, 2017 - 100,000 10 5/8% Jan. 1, 2018 - 100,000 9 7/8% Feb. 1, 2020 100,000 100,000 9 7/8% May 1, 2020 100,000 100,000 9 7/8% Nov. 1, 2020 100,000 100,000 8 7/8% Nov. 1, 2021 150,000 150,000 8.30 % Dec. 15, 2022 100,000 100,000 7.55 % Apr. 1, 2023 50,000 - 7.45 % July 15, 2023 100,000 - --------- --------- Total first mortgage bonds 1,177,250 1,330,500 ========= =========
Pollution control notes
Interest Maturity Interest Rate Letter of Credit Amount Rate Date Adjustment Date Expiration Date 1993 1992 12% May 1, 2014* - - 60,000 60,000 12.30% July 1, 2014* - - 40,000 40,000 2.80% Dec. 1, 2014 Dec. 1, 1994 Dec. 15, 1995 74,000 74,000 2.75% Mar. 1, 2015 Mar. 1, 1994 Mar. 15, 1995 37,500 37,500 2.50% Mar. 15, 2015 Mar. 15, 1994 Mar. 31, 1995 60,000 60,000 2.60% July 15, 2015 July 15, 1994 July 31, 1995 63,500 63,500 2.85% Oct. 15, 2015 Oct. 15, 1994 Oct. 31, 1995 30,000 30,000 2.75% Dec. 1, 2015 Dec. 1, 1994 Dec. 15, 1995 42,000 42,000 4.10% July 1, 2026 July 1, 1996 July 15, 1996 65,000 65,000 5.95% Dec. 1, 2027 - - 34,000 34,000 5.70% Dec. 1, 2028 - - 70,000 - ---------- ---------- Total pollution control notes 576,000 506,000 ========== ========== Revolving Credit Agreement Note due July 31, 1997 50,000 - Long-term notes due December 31, 1996 36,100 27,707 CNG Transmission Corp. Note due November 10, 1996 8,862 - Obligations under capital leases 30,902 38,804 Unamortized premium and discount on debt-net (10,776) (11,975) ---------- ---------- 1,868,338 1,891,036 Less: debt due within one year-included in current liabilities 237,709 114,009 ---------- ---------- Total $1,630,629 $1,777,027 ========== ========== * Will be refunded in 1994 with proceeds from the issuance of $100 million of 6.05% pollution control notes due 2034.
At December 31, 1993, long-term debt and capital lease payments which will become due during the next five years are:
1994 1995 1996 1997 1998 (Thousands) $237,709 $12,552 $45,651 $102,196 $31,411
The Company's mortgage provides for a sinking and improvement fund. This provision requires the Company to make annual cash deposits with the Trustee equivalent to 1% of the principal amount of all bonds delivered and authenticated by the Trustee prior to January 1 of that year (excluding any bonds issued on the basis of the retirement of bonds). The Company satisfied this requirement in 1993 by depositing $22.5 million in cash which was used to redeem in February 1993, $22.5 million of 10 5/8% Series first mortgage bonds, due 2018. The Company satisfied this requirement in 1994 by depositing $23 million in cash which was used to redeem in February 1994, $23 million of 8 5/8% Series first mortgage bonds, due 2007.
Mandatory annual cash sinking fund requirements are $600,000 beginning June 1, 2001, for the 7 1/4% Series and $250,000 on December 1 in each year 1994 to 1996, for the 6 7/8% Series. The amount increases to $500,000 and $750,000 on December 1, 1997 and December 1, 2002, respectively, for the 6 7/8% Series.
The Company's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all utility plant.
Adjustable rate pollution control notes were issued to secure like amounts of tax-exempt adjustable rate pollution control revenue bonds (Revenue Bonds) issued by a governmental authority. The Revenue Bonds bear interest at the rate indicated through the date preceding the interest rate adjustment date. The pollution control notes bear interest at the same rate as the Revenue Bonds. On the interest rate adjustment date and annually thereafter (every three years thereafter in the case of the Revenue Bonds due July 1, 2026), the interest rate will be adjusted, not to exceed a rate of 15%, or at the option of the Company, subject to certain conditions, a fixed rate of interest, not to exceed 18%, may become effective. In the case of the Revenue Bonds due July 1, 2026, at the option of the Company, subject to certain conditions, a fixed rate of interest may become effective prior to the interest rate adjustment date or each third year thereafter. Bond owners may elect, subject to certain conditions, to have their Revenue Bonds purchased by the Trustee.
The Company has irrevocable letters of credit which expire on the letter of credit expiration dates and which the Company anticipates being able to extend if the interest rate on the related Revenue Bonds is not converted to a fixed interest rate. Those letters of credit support certain payments required to be made on the Revenue Bonds. If the Company is unable to extend the letter of credit that is related to a particular series of Revenue Bonds, that series will have to be redeemed unless a fixed rate of interest becomes effective. Payments made under the letters of credit in connection with purchases of Revenue Bonds by the Trustee are repaid with the proceeds from the remarketing of the Revenue Bonds. To the extent the proceeds are not sufficient, the Company is required to reimburse the bank that issued the letter of credit.
4 Preferred Stock
At December 31, 1993 and 1992, serial cumulative preferred stock was:
Shares Par Value Authorized Per Redeemable and Amount Series Share Prior to Per Share Outstanding(1) 1993 1992 (Thousands) Redeemable solely at the option of the Company: 3.75% $100 $104.00 150,000 $ 15,000 $ 15,000 4 1/2%(1949) 100 103.75 40,000 4,000 4,000 4.15% 100 101.00 40,000 4,000 4,000 4.40% 100 102.00 75,000 7,500 7,500 4.15% (1954) 100 102.00 50,000 5,000 5,000 6.48% 100 102.00 300,000 30,000 30,000 8.80% (2) 100 102.00 250,000 25,000 25,000 8.48% (3) 25 25.70 1,000,000 25,000 25,000 7.40% (4) 25 12/1/98 26.85 1,000,000 25,000 - Thereafter 25.00 Adjustable Rate (5) 25 25.00 1,800,000 45,000 45,000 Adjustable Rate (6) 25 12/1/98 27.50 2,000,000 50,000 - Thereafter 25.00 ---------- ---------- 235,500 160,500 Less: preferred stock redemptions within one year - included in current liabilities 95,000 - ---------- ---------- Total $ 140,500 $ 160,500 ========== ==========
Subject to mandatory redemption requirements: 9.00% (7) 100 - $ - $ 8,550 6.30% (8) 100 1/1/95 105.67 250,000 25,000 - 8.95% (9) 25 1/1/95 26.79 4,000,000 100,000 100,000 ---------- ---------- 125,000 108,550 Less: sinking fund requirements at par value - included in current liabilities - 1,650 ---------- ---------- Total $ 125,000 $ 106,900 ========== ==========
At December 31, 1993, preferred stock redemptions and annual redeemable preferred stock sinking fund requirements for the next five years are:
1994 1995 1996 1997 1998 (Thousands) $95,000 $ - $ - $5,000 $5,000
(1) At December 31, 1993, and after giving effect to the redemptions referred to in (2), (3), and (5) below, there were 1,550,000 shares of $100 par value preferred stock, 3,800,000 shares of $25 par value preferred stock and 1,000,000 shares of $100 par value preference stock authorized but unissued.
(2) Redeemed January 18, 1994.
(3) Redeemed February 1, 1994.
(4) The Company is restricted in its ability to redeem this Series prior to December 1, 1998.
(5) The Adjustable Rate Serial Preferred Stock, Series A, was redeemed January 10, 1994.
(6) The payment on the Adjustable Rate Serial Preferred Stock, Series B, for April 1, 1994, is at an annual rate of 5.12% and subsequent payments can vary from an annual rate of 4% to 10%, based on a formula included in the Company's Certificate of Incorporation. The Company is restricted in its ability to redeem this Series prior to December 1, 1998.
(7) On October 1, 1993, 33,000 shares were redeemed at par. The remaining 52,500 shares were redeemed at $100.50 per share on October 13, 1993. For the years 1991 and 1992, 16,500 shares were redeemed and cancelled annually.
(8) On January 1, in each year 2004 through 2008, the Company must redeem 12,500 shares at par, and on January 1, 2009, the Company must redeem the balance of the shares at par. This Series is redeemable at the option of the Company at $105.67 per share prior to January 1, 1995. The $105.67 price will be reduced annually by 63 cents for the years ending 1995 through 2002; thereafter, the redemption price is $100.00. The Company is restricted in its ability to redeem this Series prior to January 1, 2004.
(9) On January 1, in each year 1997 through 2016, the Company must redeem 200,000 shares at par. This Series is redeemable at the option of the Company at $26.79 per share prior to January 1, 1995. The $26.79 price will be reduced annually by 15 cents for
the years ending 1995 through 1999; by 14 cents for the year ending 2000; and by 15 cents for the years ending 2001 through 2005. The Company is restricted in its ability to redeem this Series prior to January 1, 1996.
5 Bank Loans and Other Borrowings
The Company has a revolving credit agreement with certain banks which provides for borrowing up to $200 million to July 31, 1997. At the option of the Company, the interest rate on borrowings is related to the prime rate, the London Interbank Offered Rate (LIBOR) or the interest rate applicable to certain certificates of deposit. The agreement also provides for the payment of a commitment fee which can fluctuate from .15% to .375% depending upon the ratings of the Company's first mortgage bonds. The commitment fee at December 31, 1993 is .1875%.
The Company had an outstanding loan of $50 million under the revolving credit agreement at December 31, 1993, at an interest rate of 4.06% under the LIBOR option, and did not have any outstanding loans under this agreement at December 31, 1992. The revolving credit agreement does not require compensating balances.
In order to provide flexibility in the timing and amounts of long-term financings, the Company uses interim financing in the form of short-term unsecured notes, usually commercial paper, to finance certain refundings and construction expenditures, and for other corporate purposes.
Information relative to short-term borrowings is as follows:
Commercial Paper 1993 1992 1991 (Thousands)
Ending balance $50,200 $64,100 $103,900 Maximum amount outstanding $95,400 $140,000 $111,000 Average amount outstanding (1) $56,300 $31,400 $66,700 Weighted average interest rate On ending balance 3.5% 4.0% 5.3% During the period (2) 3.4% 4.3% 6.2%
(1) Calculated as the average of the sum of daily outstanding borrowings.
(2) Calculated by dividing total interest expense by the average of the sum of daily outstanding borrowings.
6 Restructuring
In the fourth quarter of 1993, the Company recorded a $26 million restructuring charge. The corporate restructuring will reorganize the way the Company delivers services to its electric and natural gas customers beginning in March 1994. The restructuring reduced 1993 earnings available for common stock by approximately $17.2 million or 25 cents per share. Included in this amount are $13.2 million for a voluntary early retirement program, $3.2 million for an involuntary severance program, and $.8 million for the elimination and closing of electric and natural gas operations facilities statewide. During 1994, the restructuring resulted in a work force reduction throughout the organization of approximately 600, the elimination of customer walk-in services at 28 satellite locations, and the closing of up to 10 electric and natural gas operations facilities statewide. The work force reduction was accomplished through a voluntary early retirement program (See Note 7 - Retirement Benefits) and an involuntary severance program. 384 employees accepted the early retirement program.
7 Retirement Benefits
Pensions
The Company has a noncontributory retirement annuity plan that covers substantially all employees. Benefits are based principally on the employee's length of service and compensation for the five highest paid years out of the last 10 years of service. It is the Company's policy to fund pension costs accrued each year to the extent deductible for federal income tax purposes.
The net pension benefit for 1993, 1992, and 1991 totaled $5.7 million, $1.5 million, and $2.9 million, respectively.
Effective January 1, 1993, the retirement benefit plans for hourly and salaried employees were combined into one plan. Combining the two plans did not affect benefit levels.
Net pension benefit for 1993, 1992, and 1991 included the following components:
1993 1992 1991 (Thousands) Service cost: Benefits earned during the year $ 17,688 $ 15,387 $ 13,252 Interest cost on projected benefit obligation 40,710 35,253 32,096 Actual return on plan assets (77,129) (60,020) (111,749) Net amortization and deferral 12,989 7,844 63,487 ------- -------- -------- Net pension (benefit) $ (5,742) $ (1,536) $ (2,914) ======= ======== ========
The funded status of the plans at December 31, 1993 and 1992 were: 1993 1992 (Thousands) Actuarial present value of accumulated benefit obligation:
Vested $390,716 $287,504 Nonvested 55,476 42,286 -------- -------- Total 446,192 329,790 ======== ========
Fair value of plan assets $753,292 $701,893 Actuarial present value of projected benefit obligation (608,216) (480,429) -------- -------- Plan assets in excess of projected benefit obligation 145,076 221,464 Unrecognized net transition asset (73,612) (80,850) Unrecognized net (gain) loss (83,709) (139,729) Unrecognized prior service cost 4,182 5,209 --------- -------- Net pension (liability) asset $(8,063) $ 6,094 ========= ========
Plan assets primarily consist of equity securities, corporate, U.S. agency, and Treasury bonds, and cash equivalents.
The projected benefit obligation was measured using an assumed discount rate of 7% for 1993 and 7.75% for 1992 and 1991, and a long-term rate of increase in future compensation levels of 5% for 1993 and 6% for 1992 and 1991. The net pension benefit was measured using an expected long-term rate of return on plan assets of 8% in 1993 and 7.5% in 1992 and 1991.
Early Retirement
As part of the corporate restructuring that was announced in the fourth quarter of 1993 (See Note 6 - Restructuring), the Company offered a voluntary early retirement program from December 1, 1993, through January 21, 1994, to employees who were 55 years and older and who had at least 10 years of service with the Company. The program included two provisions: an unreduced pension benefit for those eligible employees who were under 60 years old, and a monthly supplemental payment to "bridge" employees to age 62 when they can begin collecting Social Security benefits. 384 employees accepted the early retirement opportunity. In 1993, the Company recorded a $19.9 million expense for the early retirement program.
Postretirement Benefits Other Than Pensions
The Company has postretirement benefit plans, such as a comprehensive health insurance plan and a prescription drug plan, that provide certain benefits for retired employees and their dependents. Substantially all of the Company's employees who retire under the Company's pension plan may become eligible for those benefits at retirement. At December 31, 1993, 1992, and 1991, 1,996, 1,905, and 1,866 retirees and their dependents, respectively, were covered under these plans. The postretirement benefit plans are unfunded as of December 31, 1993. However, the Company is examining the cost-effectiveness of certain funding alternatives.
In January 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (SFAS 106), Employers' Accounting for Postretirement Benefits Other Than Pensions, which requires that the Company accrue a liability for estimated future postretirement benefits during an employee's working career rather than recognize an expense when benefits are paid. At the time of adoption, the actuarially determined accumulated postretirement benefit obligation (APBO) was $206.6 million. The Company elected to recognize the APBO over 20 years.
In September 1993, the PSC issued a Statement of Policy concerning the accounting and ratemaking treatment for pensions and postretirement benefits other than pensions (PSC Policy). The PSC Policy was effective January 1993, adopted SFAS 106 for accounting and ratemaking purposes, and complies with generally accepted accounting principles.
Postretirement benefits cost other than pensions that was recognized on the income statement for the twelve months ended December 31, 1993, 1992, and 1991, was $11.4 million, $5 million, and $4.4 million, respectively. The amount for 1993 represents the portion of SFAS 106 costs that the Company has been allowed to collect from its customers. The amounts for the twelve months
ended December 31, 1992 and 1991, represent the postretirement benefits cost as determined prior to the adoption of SFAS 106, when the cost was not recognized as an expense until the benefits were paid. The Company has deferred $10.1 million of SFAS 106 costs as of December 31, 1993. The Company expects to recover any deferred SFAS 106 amounts in accordance with the PSC Policy.
The PSC Policy allows various rate mechanisms, including the use of excess pension fund assets, such as Internal Revenue Service Code of 1986 Section 420 transfers, to temper the effect of SFAS 106 on rates. In 1993, the Company transferred approximately $5 million of its excess pension plan assets to cover most of the cost of retirees' health care for that year. As a result of this transfer, the Company recognized a decrease in its deferred SFAS 106 asset.
The estimated net postretirement benefits cost other than pensions for the 12 months ended December 31, 1993, includes the following components:
(Thousands)
Service cost: Benefits accumulated during the year $ 6,888 Interest cost on accumulated postretirement benefit obligation 16,304 Amortization of transition obligation over 20 years 10,330 Deferral for future recovery (22,095) --------- Net periodic postretirement benefits cost $ 11,427 ==========
The status of the plans for postretirements benefits other than pensions, as reflected in the Company's Consolidated Balance Sheets at December 31, 1993, is as follows: (Thousands) Accumulated postretirement benefit obligation (APBO): Retired employees $ 69,947 Fully eligible active plan participants 36,454 Other active plan employees 107,708 ---------- Total APBO 214,109 ---------- Less unrecognized transition obligation 196,268 Less unrecognized net (gain) (10,233) ---------- Accrued postretirement liability $ 28,074 ==========
A 12% annual rate of increase in the per capita costs of covered health care benefits was assumed for 1994, gradually decreasing to 5% by the year 2003. Increasing the assumed health care cost trend rates by 1% in each year would increase the APBO as of January 1, 1994, by $41.5 million and increase the aggregate of the service cost and interest cost components of the net postretirement benefits cost for 1994 by $4.6 million. A discount rate of 7% was used to determine the APBO.
8 Jointly-Owned Generating Stations
Nine Mile Point Unit 2
The Company has an undivided 18% interest in the output and costs of the Nine Mile Point nuclear generating unit No. 2 (NMP2), which is being operated by Niagara Mohawk Power Corporation (Niagara Mohawk). Ownership of NMP2 is shared with Niagara Mohawk 41%, Long Island Lighting Company 18%, Rochester Gas and Electric Corporation 14%, and Central Hudson Gas & Electric Corporation 9%. The Company's share of the rated capability is 189,000 kilowatts. The Company's net utility plant investment, excluding nuclear fuel, was approximately $652 million and $660 million, at December 31, 1993 and 1992, respectively. The accumulated provision for depreciation was approximately $103 million and $90 million, at December 31, 1993 and 1992, respectively. The Company's share of operating expenses is included in the Consolidated Statements of Income.
A low level radioactive waste management and contingency plan that has been developed for NMP2 provides assurance that NMP2 is properly prepared to handle interim storage of low level radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of Energy (DOE) for disposal of high level radioactive waste (spent fuel) from NMP2. The Company is reimbursing Niagara Mohawk for its 18% share of the cost under the contract (currently approximately $1 per megawatt hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository has slipped from 2003 to no sooner than 2010. The Company has been advised by Niagara Mohawk that the NMP2 Spent Fuel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, the recent development of pre-licensed dry storage facilities for use at any nuclear power plant extends the on-site storage capability for spent fuel at NMP2 beyond 2014.
Nuclear Insurance
Niagara Mohawk maintains public liability and property insurance for NMP2. The Company reimburses Niagara Mohawk for its 18% share of those costs.
The public liability limit for a nuclear incident is approximately $8.8 billion. Should losses stemming from a nuclear incident exceed the commercially available public liability insurance, each licensee of a nuclear facility would be liable for up to a maximum of $75.5 million per incident, payable at a rate not to exceed $10 million per year. The Company's maximum liability for its 18% interest in NMP2 would be approximately $13.6 million per incident. The $75.5 million assessment is subject to periodic inflation indexing and a 5% surcharge should funds prove insufficient to pay claims associated with a nuclear incident. The Price-Anderson Act also requires indemnification for precautionary evacuations whether or not a nuclear incident actually occurs.
Niagara Mohawk maintains nuclear property insurance for NMP2 and is reimbursed by the Company for its 18% interest. Niagara Mohawk has procured property insurance aggregating approximately $2.7 billion through the Nuclear Insurance Pools and the Nuclear Electric Insurance Limited (NEIL). In addition, the Company has purchased NEIL insurance coverage for the extra expense incurred in purchasing replacement power during prolonged accidental outages. Under NEIL programs, should losses resulting from an incident at a member facility exceed the accumulated reserves of NEIL, each member, including the Company, would be liable for its share of the deficiency. The Company's maximum liability under the property damage and replacement power coverages is approximately $2.3 million.
Nuclear Plant Decommissioning Costs
In May 1993, the Nuclear Regulatory Commission (NRC) updated labor, energy, and burial cost factors for determining the minimum funding requirement for nuclear decommissioning. As a result, the Company's 18% share of the cost to decommission NMP2 is currently estimated to be $234 million in 2027, when decommissioning is expected to commence ($74 million in 1993 dollars).
The Company's annual decommissioning allowance currently included in electric rates is approximately $1.6 million and is sufficient to recover the minimum funding requirement. The Company believes that any increase in decommissioning costs will ultimately be recovered in rates.
The Company has established a Qualified Fund under applicable provisions of the federal tax law. The fund also
complies with the NRC regulations which require the use of an external trust fund to provide funds to decommission the contaminated portion of NMP2. The balance in this fund was approximately $5.7 million and $3.9 million at December 31, 1993 and 1992, respectively, and is included in other property and investments on the Consolidated Balance Sheets.
Homer City
The Company has an undivided 50% interest in the output and costs of the Homer City Generating Station, which is comprised of three generating units. The station is owned with Pennsylvania Electric Company, which operates the facility. The Company's share of the rated capability is 954,000 kilowatts and its net utility plant investment was approximately $258 million and $251 million at December 31, 1993 and 1992, respectively. The accumulated provision for depreciation was approximately $159 million and $148 million, at December 31, 1993 and 1992, respectively. The Company's share of operating expenses is included in the Consolidated Statements of Income.
9 Commitments and Contingencies
Capital Expenditures
The Company has substantial commitments in connection with its construction program and estimates that capital expenditures for 1994, 1995, and 1996 will approximate $210 million, $200 million, and $200 million, respectively. These forecasted levels have been significantly reduced as the Company is taking action to address competition. The program is subject to periodic review and revision, and actual construction costs may vary because of revised load estimates, imposition of additional regulatory requirements, and the availability and cost of capital.
Environmental Matters
The Company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Compliance programs will increase the cost of electric and natural gas service by requiring changes to the Company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred for compliance with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the Company may also incur costs from the past disposal of hazardous substances produced during the Company's operations or those of its predecessors. The Company has been notified by the U. S. Environmental Protection Agency (EPA) and the New York
State Department of Environmental Conservation (NYSDEC) that the Company is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at seven waste sites, not including the Company's inactive gas manufacturing sites, which are discussed below. With respect to the seven sites, five sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry).
Any liability may be joint and several for certain of these sites. The ultimate cost to remediate these sites will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the Company. At December 31, 1993, the Company recorded a liability in the Consolidated Balance Sheets related to four of these seven sites of $1.8 million. The Company has notified the NYSDEC that it believes it has no responsibility at two sites and has already incurred expenditures related to the remediation at the remaining site. A deferred asset has also been recorded in the amount of $2.6 million, of which $.8 million relates to costs that have already been incurred. The Company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the Company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites. This $1.8 million estimate was derived by multiplying the total estimated cost to clean up a particular site by the related Company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the Company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the Company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the Company's inactive gas manufacturing sites have been listed in the New York State Registry. The Company has filed petitions to delist the majority of the sites. The Company's program to investigate and initiate remediation at its 38 known inactive gas manufacturing sites has been extended through the year 2000. Expenditures over this time period are estimated to be $25 million. This estimate was determined by
using the Company's experience and knowledge related to these sites as a result of the investigation and remediation that the Company has performed to date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability, to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites, is reflected in the Company's Consolidated Balance Sheets at December 31, 1993 and 1992. The Company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the Company has previously been allowed by the PSC to recover such costs in rates. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in significant expenditures of approximately $178 million, on a present value basis, over a 25 year period, for all capital and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the Company's coal-fired generating stations of which $51 million has been incurred as of December 31, 1993. The Company's current estimate is a significant reduction from its prior estimate, primarily due to the postponement of the construction of a flue gas desulfurization (FGD) system at the Homer City Generating Station. The Company plans to reevaluate the need to construct an FGD system at the Homer City Generating Station in 1995, since its present strategy to bank Phase I emissions allowances for use during Phase II, as discussed below, will allow the Company to meet Phase II allowance requirements through the year 2005. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative FGD system and a nitrogen oxide reduction system expected to be completed in 1995 at the Company's Milliken Generating Station. The Company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (begins January 1, 1995) and Phase II (begins January 1, 2000). As a result of the 1990 Amendments, the Company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the Company to meet the sulfur dioxide levels established for the Company, which is approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time. Regulations may be adopted at the state level which would limit toxic emissions even further, at an additional cost to the Company. The Company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual emissions allowances to each of the Company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the Company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The Company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the Company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the Company by the EPA, the Company will receive a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers, as a result of the pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the Company will incur approximately $24 million, on a present value basis, of additional costs over the next 30 years, beginning in 1994, at the Homer City Generating Station. These costs will be incurred to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The Company expects to recover these expenditures in rates, since the Company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Long-term Power Purchase Contracts
The Company has on line and under contract 362 megawatts (mw) of non-utility generation (NUG) power. In addition, another 240 mw of NUG power is under construction. The Company is required to make payments under these contracts only for the power it receives. During 1993, 1992, and 1991 the Company purchased approximately $138 million, $71 million, and $30 million, respectively, of NUG power. The Company estimates that it will purchase approximately $255 million, $291 million, and $335 million of NUG power for the years 1994, 1995, and 1996, respectively. Increases in NUG power purchase costs are expected to be a significant contributor to price increases over the next three years.
As part of the Company's continuing effort to minimize future price increases associated with uneconomical power purchases from NUGs, the Company negotiated termination of
agreements for the South Corning and Indeck-Kirkwood cogeneration projects. The PSC approved full recovery of the $11.5 million in termination costs for the Indeck-Kirkwood project in rates. The Company expects to recover the $34 million in termination costs for the South Corning project in rates because the PSC issued an order in 1993 allowing the Company to defer these costs and the Company has been allowed by the PSC to recover costs for the Indeck-Kirkwood project in rates.
Coal Purchasing Contracts
The Company has long-term contracts with nonaffiliated mining companies for the purchase of coal for the jointly-owned Homer City Generating Station. The contracts, which expire between 1994 and the end of the expected service life of the generating station, require the purchase of either fixed or minimum amounts of the station's coal requirements. The price of the coal under one of these contracts is based on recovery of production costs plus incentives. The remaining contracts are based on fixed price plus escalation provisions. The Company's share of the cost of coal purchased under these agreements is expected to aggregate $66 million, $45 million, and $31 million for the years 1994, 1995, and 1996, respectively.
In addition, the Company has a long-term contract for the purchase of coal for the Kintigh Generating Station. The contract, which expires in 1997, supplies the annual coal requirements of the station. One-third of the tonnage price is renegotiated annually to reflect market conditions. The delivered cost of coal purchased under this agreement is expected to be $56 million, $55 million, and $56 million for the years 1994, 1995, and 1996, respectively.
10 Fair Value of Financial Instruments
The estimated fair values of the Company's financial instruments at December 31, 1993 and 1992, were as follows:
Carrying Amount Fair Value 1993 1992 1993 1992 (Thousands) First mortgage bonds $1,166,779 $1,318,845 $1,274,883 $1,388,990 Pollution control notes $575,695 $505,680 $581,928 $523,251 Preferred stock subject to mandatory redemption requirements $125,000 $108,550 $134,000 $119,031
The carrying amount for the following items approximates estimated fair value because of the short maturity of those instruments: cash and cash equivalents, commercial paper, and interest accrued.
Special deposits include restricted funds that are set aside for preferred stock and long-term debt redemptions. Special deposits also include restricted funds that are used to finance a portion of the costs incurred in the construction of certain solid waste disposal and other related facilities. The carrying amount approximates fair value because the special deposits have been invested in securities with a short-term maturity.
The carrying amount of the revolving credit agreement note approximates fair value because its pricing is based on short- term interest rates.
The fair value of the Company's first mortgage bonds, pollution control notes, and preferred stock is estimated based on the quoted market prices for the same or similar issues of the same remaining maturities.
11 Industry Segment Information
Certain information pertaining to the electric and natural gas operations of the Company is:
1993 1992 1991 Natural Natural Natural Electric Gas Electric Gas Electric Gas (Thousands) Operating Revenues $1,527,362 $272,787 $1,451,525 $240,164 $1,367,936 $187,879 Expenses $1,250,000 $249,493 $1,146,619 $221,307 $1,056,969 $177,751 Income $277,362 $23,294 $304,906 $18,857 $310,967 $10,128 Depreciation and amortization* $155,231 $9,337 $150,549 $8,428 $145,700 $6,680 Construction expenditures $208,576 $36,453 $210,185 $35,433 $210,127 $35,756 Identifiable assets** $4,615,963 $458,596 $4,540,724 $377,424 $4,515,237 $340,090
* Included in operating expenses. ** Assets used in both electric and natural gas operations not included above were $201,457, $159,768, and $69,509 at December 31, 1993, 1992, and 1991, respectively. They consist primarily of cash and cash equivalents, special deposits, and prepayments.
12 Supplementary Income Statement Information
Charges for maintenance, repairs, and depreciation and amortization, are set forth in the Consolidated Statements of Income. Taxes, other than federal income taxes, are:
1993 1992 1991 (Thousands)
Property $84,616 $81,640 $76,589 Franchise and gross receipts 92,810 92,153 76,721 Payroll 17,985 17,096 15,467 Miscellaneous 9,551 10,052 9,408 -------- -------- -------- Total Other Taxes $204,962 $200,941 $178,185 ======== ======== ========
13 Quarterly Financial Information (Unaudited)
Quarter ended March 31 June 30 Sept. 30 Dec. 31 (Thousands, Except Per Share Amounts) Operating revenues $522,383 $388,601 $396,410 $492,755 Operating income $109,893 $56,649 $66,108 $68,006 Net income $74,039 $21,500 $32,541 $37,948 (1) Earnings for common stock $68,838 $16,299 $27,340 $32,913 Earnings per share $.99 $.23 $.39 $.47 (1) Dividends per share $.54 $.54 $.55 $.55 Average shares outstanding 69,561 69,836 70,119 70,431 Common stock price* High $35.13 $36.50 $36.25 $35.50 Low $31.63 $32.13 $34.63 $28.75 Operating revenues $489,847 $401,934 $367,833 $432,075 Operating income $111,373 $82,755 $60,109 $69,526 Net income $76,416 $46,772 $26,581 $34,199 Earnings for common stock $71,167 $41,488 $21,320 $28,998 Earnings per share $1.10 (2) $.60 (2) $.31 (2) $.42 (2) Dividends per share $.53 $.53 $.54 $.54 Average shares outstanding 64,682 68,800 69,063 69,318 Common stock price* High $29.63 $29.38 $32.00 $32.75 Low $26.13 $26.75 $29.25 $30.38
(1) Fourth quarter 1993 results reflect the effects of restructuring expenses, which decreased net income and earnings for common stock by $17.2 million and decreased earnings per share by 24 cents. (2) Late in 1992, the Company began reflecting on its income statement the value of energy consumed but not yet billed. If the Company had been allowed by the PSC to include this unbilled revenue factor during all of 1992, quarterly earnings per share in 1992 would have been 94 cents, 39 cents, 38 cents, and 72 cents for the first, second, third, and fourth quarters, respectively. * The Company's common stock is listed on the New York Stock Exchange. The number of stockholders of record at December 31, 1993 was 58,990.
Dividend Limitations: After dividends on all outstanding preferred stock have been paid, or declared, and funds set apart for their payment, the common stock is entitled to cash dividends as may be declared by the Board of Directors out of retained earnings accumulated since December 31, 1946. Common Stock dividends are limited if Common Stock Equity (45% at December 31, 1993) falls below 25% of total capitalization, as defined in the Company's Certificate of Incorporation. Dividends on common stock cannot be paid unless sinking fund requirements of the preferred stock are met. The Company has not been restricted in the payment of dividends on common stock by these provisions. Retained earnings accumulated since December 31, 1946, were approximately $320 million and $327 million as of December 31, 1993 and 1992, respectively.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors New York State Electric & Gas Corporation and Subsidiaries Ithaca, New York
We have audited the consolidated financial statements and the financial statement schedules of New York State Electric & Gas Corporation and Subsidiaries listed in Item 14(a) of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of New York State Electric & Gas Corporation and Subsidiaries as of December 31, 1993 and 1992, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As discussed in Note 7 to the consolidated financial statements, the Company and Subsidiaries changed its method of accounting for postretirement benefits other than pensions in 1993.
COOPERS & LYBRAND
New York, New York January 28, 1994
Item 9. Changes in and disagreements with accountants on accounting and financial disclosure - None
PART III
Item 10. Directors and executive officers of the Registrant
Incorporated herein by reference to the information under the caption "Election of Directors" in the Company's Proxy Statement dated March 31, 1994. The information regarding executive officers is on pages 23-25 of this report.
Item 11. Executive compensation
Incorporated herein by reference to the information under the captions "Executive Compensation," "Employment and Change in Control Arrangements," "Directors' Compensation," "Compensation Committee Interlocks and Insider Participation," "Report of Executive Compensation and Succession Committee on Executive Compensation" and "Stock Performance Graph" in the Company's Proxy Statement dated March 31, 1994.
Item 12. Security ownership of certain beneficial owners and management
Incorporated herein by reference to the information under the caption "Security Ownership of Certain Beneficial Owners and Management" in the Company's Proxy Statement dated March 31, 1994.
Item 13. Certain relationships and related transactions
Incorporated herein by reference to the information under the captions "Election of Directors" and "Employment and Change in Control Arrangements" in the Company's Proxy Statement dated March 31, 1994.
PART IV
Item 14. Exhibits, financial statement schedules, and reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial statements Included in Part II of this report: a) Consolidated Statements of Income for the three years ended December 31, 1993 b) Consolidated Balance Sheets as of December 31, 1993 and 1992 c) For the three years ended December 31, 1993: Consolidated Statements of Cash Flows Consolidated Statements of Changes in Common Stock Equity d) Notes to Consolidated Financial Statements e) Report of Independent Accountants 2. Financial statement schedules Included in Part II of this report: For the three years ended December 31, 1993: V. Property, Plant and Equipment VI. Accumulated Depreciation of Property, Plant and Equipment VIII. Allowance for Doubtful Accounts - Accounts Receivable
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Consolidated Financial Statements or notes thereto.
3. Exhibits (a)(1) The following exhibits are delivered with this report:
Exhibit No. 3-11 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993. 3-12 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. 3-13 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. 3-15 - By-Laws of the Company as amended February 25, 1994. 10-14 - Coal Sales Agreement dated December 21, 1983 between New York State Electric & Gas Corporation and Consolidation Coal Company. (A) 10-21 - Retirement Plan for Directors Amendment No. 1. (A) 10-23 - Deferred Compensation Plan for Directors Amendment No. 1. (A) 10-32 - Supplemental Executive Retirement Plan Amendment No. 8. (A) 10-33 - Supplemental Executive Retirement Plan Amendment No. 9. (A) 10-35 - Annual Executive Incentive Compensation Plan Amendment No. 1. (A) 10-36 - Annual Executive Incentive Compensation Plan Amendment No. 2. (A) 10-41 - Performance Share Plan Amendment No. 4. (A) 10-43 - Performance Share Deferred Compensation Plan Amendment No. 1. (A) 10-46 - Employment Agreement for J. A. Carrigg. (A) 10-47 - Form of Severance Agreement for Senior Vice Presidents. (A) 10-48 - Form of Severance Agreement for Vice Presidents. 12 - Computation of Ratio of Earnings to Fixed Charges. 21 - Subsidiaries. 23 - Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 99-1 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.
(a)(2) The following exhibits are incorporated herein by reference: Exhibit No. Filed in As Exhibit No. 3-1 - Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988 - Registration No. 33-50719 . . . 4-11 3-2 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989 - Registration No. 33-50719 . . 4-12 3-3 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990 - Registration No. 33-50719 . . . . . . . . . . . . . 4-13 3-4 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990 - Registration No. 33-50719 . . 4-14 ______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
3-5 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991 - Registration No. 33-50719 . . 4-15 3-6 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991 - Registration No. 33-50719 . . 4-16 3-7 - Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991 - Registration No. 33-50719 . . . . . . . . . . . . . . . . . . . 4-20 3-8 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992 - Registration No. 33-50719 . . . . 4-17 3-9 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992 - Registration No. 33-50719 . . . 4-18 3-10 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993 Registration No. 33-50719 . . . . . . . . . . . . . . 4-19 3-14 - Certificates of the Secretary of the Company concern- ing consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness - Registration No. 2-69988. . . . . . . . . . . . . . 4-7 4-1 - First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee) - Registration No. 33-4186 . . . 4-1
Supplemental Indentures to First Mortgage dated as of July 1, 1921: 4-2 - No. 37 - Registration No. 33-31297. . . . . . . . . 4-2 4-3 - No. 39 - Registration No. 33-31297. . . . . . . . . 4-3 4-4 - No. 43 - Registration No. 33-31297. . . . . . . . . 4-4 4-5 - No. 51 - Registration No. 2-59840 . . . . . . . . . 2-B(46) 4-6 - No. 68 - Registration No. 2-59840 . . . . . . . . . 2-B(63) 4-7 - No. 69 - Registration No. 2-59840 . . . . . . . . . 2-B(64) 4-8 - No. 71 - Registration No. 2-59840 . . . . . . . . . 2-B(66) 4-9 - No. 74 - Registration No. 2-59840 . . . . . . . . . 2-B(69) 4-10 - No. 75 - Registration No. 2-59840 . . . . . . . . . 2-B(70) 4-11 - No. 80 - Registration No. 2-59840 . . . . . . . . . 2-B(75) 4-12 - No. 81 - Registration No. 2-59840 . . . . . . . . . 2-B(76) 4-13 - No. 83 - Registration No. 2-65948 . . . . . . . . . 2-B(78) 4-14 - No. 99 - Registration No. 33-11303. . . . . . . . . 4-9 4-15 - No. 102- Registration No. 33-33838. . . . . . . . . 4-8 4-16 - No. 103- Registration No. 33-43458. . . . . . . . . 4-8 4-17 - No. 104- Registration No. 33-43458. . . . . . . . . 4-9
4-18 - No. 105- Registration No. 33-52040. . . . . . . . . 4-8 4-19 - No. 106- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-23 4-20 - No. 107- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-24 4-21 - No. 108- Registration No. 33-50719. . . . . . . . . 4-8 4-22 - No. 109- Registration No. 33-50719. . . . . . . . . 4-9
Contracts, amendments, and letter agreement with the Power Authority of the State of New York: 10-1 - Contract UD-4 dated July 28, 1975 (FitzPatrick Power) - Registration No. 2-59840 . . . . . . . . . 5-5
Exhibit No. Filed in As Exhibit No.
10-2 - Contract PS-2 dated March 28, 1973 (Blenheim- Gilboa) - Registration No. 2-59840. . . . . . . . . 5-6 10-3 - Letter Agreement dated February 3, 1982 relating to transmission services - Registration No. 2-82192. . 10-1 10-4 - Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to trans- mission services - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . 10-4 10-5 - Contract effective as of February 22, 1989 relating to the purchase of hydroelectric power - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-5 10-6 - Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . 10-6 10-7 - Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Gener- ating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for the year ended December 31, 1989 File No. 1-3103-2. . . . . . . . . . . . . 10-7
Coal Sales Agreements and Amendments between New York State Electric & Gas Corporation, Pennsylvania Electric Company and: 10-8 - Helvetia Coal Company - Agreement made as of December 22, 1966 - Registration No. 2-59840. . . . 5-11 10-9 - Helvetia Coal Company - Amendment made as of April 1, 1974 - Registration No. 2-55131. . . . . . 5-F(1)b 10-10 - Amendment dated as of March 15, 1989 to the Coal Sales Agreement made as of December 22, 1966 between New York State Electric & Gas Corporation, Penn- sylvania Electric Company and Helvetia Coal Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . 10-10
10-11 - Amendment dated as of July 25, 1990 to the Coal Sales Agreement made as of December 22, 1966 between New York State Electric & Gas Corporation, Penn- sylvania Electric Company and Helvetia Coal Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . 10-11
* * * * * * * * * *
Exhibit No. Filed in As Exhibit No.
10-12 - New York Power Pool Agreement dated July 11, 1985 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-7 10-13 - Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-17 10-15 - Amendment No. 1 dated as of October 1, 1985 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-11 10-16 - Amendment No. 2 dated as of August 28, 1986 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-12 10-17 - Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2 - Registration No. 2-54903. . . 5-0 10-18 - Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others - Company's 10-K for the year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . 10-18 10-19 - Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation - Registration No. 2-82352. . . . . . . . . . . . . . 10 (A) 10-20 - Retirement Plan for Directors - Company's 10-K for the year ended December 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-26 (A) 10-22 - Form of Deferred Compensation Plan for Directors - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-22 (A) 10-24 - Supplemental Executive Retirement Plan - Company's 10-Q for quarter ended September 30, 1984 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-19 (A) 10-25 - Supplemental Executive Retirement Plan Amendment No. 1 - Company's 10-Q for quarter ended March 31, 1985 - File No. 1-3103-2. . . . . . . . . 10-21 ______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
(A) 10-26 - Supplemental Executive Retirement Plan Amendment No. 2 - Company's 10-K for year ended December 31, 1987 - File No. 1-3103-2. . . . . . . . . . . . 10-19 (A) 10-27 - Supplemental Executive Retirement Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . 10-24 (A) 10-28 - Supplemental Executive Retirement Plan Amendment No. 4 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-30 (A) 10-29 - Supplemental Executive Retirement Plan Amendment No. 5 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-31 (A) 10-30 - Supplemental Executive Retirement Plan Amendment No. 6 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2. . . . . . . . . . . . . . 10-37 (A) 10-31 - Supplemental Executive Retirement Plan Amendment No. 7 - Company's 10-Q for quarter ended June 30, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . 10-44 (A) 10-34 - Annual Executive Incentive Compensation Plan. Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-30 (A) 10-37 - Performance Share Plan - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . 10-36 (A) 10-38 - Performance Share Plan Amendment No. 1 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-38 (A) 10-39 - Performance Share Plan Amendment No. 2 - Company's 10-Q for quarter ended June 30, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-39 (A) 10-40 - Performance Share Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-34 (A) 10-42 - Performance Share Deferred Compensation Plan - Company's 10-K for year ended December 31, 1991 File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-40 (A) 10-44 - Employment Contract for A. E. Kintigh - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . 10-26 (A) 10-45 - Agreement with R. Fleming, Jr. - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . 10-34
The Company agrees to furnish to the Commission, upon request, a copy of the Revolving Credit Agreement dated as of July 31, 1992, between the Company, Chemical Bank, as Agent, and certain banks; a copy of the Participation Agreement dated as of February 1, 1984 between the Company and New York State Energy Research and Development Authority (NYSERDA) relating to Pollution Control Revenue Bonds; a copy of the Participation Agreements dated as of October 15, 1984, June 1, 1987 and December 1, 1988 between the Company and NYSERDA relating to Adjustable Rate Pollution Control Revenue Bonds (1984 Series A), (1987 Series A), and (1988 Series A), respectively; a copy of the Participation Agreements dated as of March 1, 1985, October 15, 1985, July 15, 1985 and December 1, 1985 between the Company and NYSERDA relating to Annual
______________________________ (A) Management contract or compensatory plan or arrangement.
Tender Pollution Control Revenue Bonds (1985 Series A), (1985 Series B), (1985 Series C) and (1985 Series D), respectively; a copy of the Participation Agreements dated as of February 1, 1993 and February 1, 1994 between the Company and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1994 Series A) and (1994 Series B) respectively; a copy of the Participation Agreement dated as of December 1, 1993 between the Company and NYSERDA relating to Solid Waste Disposal Revenue Bonds (1993 Series A); and a copy of the Credit Agreement dated as of March 9, 1983, as amended, between Somerset Railroad Corporation and Chemical Bank. The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
(b) Reports on Form 8-K
A report on Form 8-K, dated November 29, 1993, was filed during the fourth quarter of 1993 to report certain information under Item 5, "Other Events."
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.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Date: March 11, 1994 By Everett A. Robinson Everett A. Robinson Vice President and Controller (Chief Accounting 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.
PRINCIPAL EXECUTIVE OFFICER
Date: March 11, 1994 By James A. Carrigg James A. Carrigg Chairman, President, Chief Executive Officer and Director
PRINCIPAL FINANCIAL OFFICER
Date: March 11, 1994 By Sherwood J. Rafferty Sherwood J. Rafferty Vice President and Treasurer
PRINCIPAL ACCOUNTING OFFICER
Date: March 11, 1994 By Everett A. Robinson Everett A. Robinson Vice President and Controller
Signatures (Cont'd)
Date: March 11, 1994 By Alison P. Casarett Alison P. Casarett Director
Date: March 11, 1994 By Everett A. Gilmour Everett A. Gilmour Director
Date: March 11, 1994 By Paul L. Gioia Paul L. Gioia Director
Date: March 11, 1994 By John M. Keeler John M. Keeler Director
Date: March 11, 1994 By Allen E. Kintigh Allen E. Kintigh Director
Date: March 11, 1994 By Ben E. Lynch Ben E. Lynch Director
Date: March 11, 1994 By Alton G. Marshall Alton G. Marshall Director
Date: March 11, 1994 By David R. Newcomb David R. Newcomb Director
Date: March 11, 1994 By Robert A. Plane Robert A. Plane Director
Date: March 11, 1994 By C. William Stuart C. William Stuart Director
EXHIBIT INDEX
* 3-1 -- Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988. * 3-2 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989. * 3-3 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990. * 3-4 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990. * 3-5 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991. * 3-6 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991. * 3-7 -- Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991. * 3-8 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992. * 3-9 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992. * 3-10 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993. 3-11 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993. 3-12 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
3-13 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. * 3-14 -- Certificates of the Secretary of the Company concerning consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness. 3-15 -- By-Laws of the Company as amended February 25, 1994. * 4-1 -- First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee).
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
* 4-2 -- No. 37 * 4-9 -- No. 74 * 4-16 -- No. 103 * 4-3 -- No. 39 * 4-10 -- No. 75 * 4-17 -- No. 104 * 4-4 -- No. 43 * 4-11 -- No. 80 * 4-18 -- No. 105 * 4-5 -- No. 51 * 4-12 -- No. 81 * 4-19 -- No. 106 * 4-6 -- No. 68 * 4-13 -- No. 83 * 4-20 -- No. 107 * 4-7 -- No. 69 * 4-14 -- No. 99 * 4-21 -- No. 108 * 4-8 -- No. 71 * 4-15 -- No. 102 * 4-22 -- No. 109
Contracts, Amendments, and Letter Agreement with the Power Authority of the State of New York:
* 10-1 -- Contract UD-4 dated July 28, 1975 (FitzPatrick Power). * 10-2 -- Contract PS-2 dated March 28, 1973 (Blenheim- Gilboa). * 10-3 -- Letter Agreement dated February 3, 1982 relating to transmission services. * 10-4 -- Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to transmission services. * 10-5 -- Contract effective as of February 22, 1989 relating to the purchase of hydroelectric power. * 10-6 -- Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-7 -- Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
* * * * * * * * * *
Coal Sales Agreements and Amendments between New York State Electric & Gas Corporation, Pennsylvania Electric Company and:
* 10-8 -- Helvetia Coal Company--Agreement made as of December 22, 1966. * 10-9 -- Helvetia Coal Company--Amendment made as of April 1, 1974. * 10-10 -- Helvetia Coal Company--Amendment made as of March 15, 1989. * 10-11 -- Helvetia Coal Company--Amendment made as of July 25, 1990.
* * * * * * * * * *
* 10-12 -- New York Power Pool Agreement dated July 11, 1985. * 10-13 -- Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company.
* * * * * * * * * *
Coal Sales Agreement and Amendments between New York State Electric & Gas Corporation and Consolidation Coal Company:
10-14 -- Agreement dated December 21, 1983. * 10-15 -- Amendment No. 1 dated as of October 1, 1985. * 10-16 -- Amendment No. 2 dated as of August 28, 1986.
* * * * * * * * * *
* 10-17 -- Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2. * 10-18 -- Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-19 -- Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation. (A)* 10-20 -- Retirement Plan for Directors. (A) 10-21 -- Retirement Plan for Directors Amendment No. 1 (A)* 10-22 -- Form of Deferred Compensation Plan for Directors. (A) 10-23 -- Deferred Compensation Plan for Directors Amendment No. 1. (A)* 10-24 -- Supplemental Executive Retirement Plan (A)* 10-25 -- Supplemental Executive Retirement Plan Amendment No. 1. (A)* 10-26 -- Supplemental Executive Retirement Plan Amendment No. 2. (A)* 10-27 -- Supplemental Executive Retirement Plan Amendment No. 3. (A)* 10-28 -- Supplemental Executive Retirement Plan Amendment No. 4. (A)* 10-29 -- Supplemental Executive Retirement Plan Amendment No. 5. (A)* 10-30 -- Supplemental Executive Retirement Plan Amendment No. 6. (A)* 10-31 -- Supplemental Executive Retirement Plan Amendment No. 7. (A) 10-32 -- Supplemental Executive Retirement Plan Amendment No. 8. (A) 10-33 -- Supplemental Executive Retirement Plan Amendment No. 9. (A)* 10-34 -- Annual Executive Incentive Compensation Plan. (A) 10-35 -- Annual Executive Incentive Compensation Plan Amendment No. 1. (A) 10-36 -- Annual Executive Incentive Compensation Plan Amendment No. 2. (A)* 10-37 -- Performance Share Plan. (A)* 10-38 -- Performance Share Plan Amendment No. 1. (A)* 10-39 -- Performance Share Plan Amendment No. 2. (A)* 10-40 -- Performance Share Plan Amendment No. 3 (A) 10-41 -- Performance Share Plan Amendment No. 4 (A)* 10-42 -- Performance Share Deferred Compensation Plan. (A) 10-43 -- Performance Share Deferred Compensation Plan Amendment No. 1 (A)* 10-44 -- Employment Contract for A. E. Kintigh. (A)* 10-45 -- Agreement with R. Fleming, Jr. (A) 10-46 -- Employment Agreement for J. A. Carrigg. (A) 10-47 -- Form of Severance Agreement for Senior Vice Presidents. (A) 10-48 -- Form of Severance Agreement for Vice Presidents.
___________________________________ (A) Management contract or compenstory plan or arrangement. * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
12 -- Computation of Ratio of Earnings to Fixed Charges. 21 -- Subsidiaries. 23 -- Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 99-1 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.


Item 7. Management's discussion and analysis of financial condition and results of operations
Results of Operations 1993 1992 over over 1992 1991 1993 1992 1991 Change Change (Thousands, except Per Share Amounts)
Operating revenues $1,800,149 $1,691,689 $1,555,815 6% 9% Earnings available for common stock $145,390 $162,973 $148,313 (11%) 10% Average shares outstanding 69,990 67,972 62,906 3% 8% Earnings per share $2.08 $2.40 $2.36 (13%) 2% Dividends per share $2.18 $2.14 $2.10 2% 2%
In 1993, operating revenues increased $108 million, or 6%, compared to 1992. This increase is primarily because of increases in electric and natural gas rates that became effective in August 1992 and September 1993, which totaled $61 million, and the amounts billed to customers for higher costs of non-utility generation (NUG) power and natural gas totaling $51 million.
In 1992, operating revenues rose $136 million, or 9%, compared to 1991. The amounts billed to customers for higher costs of NUG power of $41 million, and increases in electric and natural gas rates effective in February 1991 and August 1992, which totaled $40 million, were the primary reasons for this increase. In addition, higher electric and natural gas retail sales due to an increase in retail customers, colder weather, and the April 1991 acquisition of Columbia Gas of New York, Inc. (CNY) helped boost operating revenues by $51 million in 1992.
Earnings per share decreased 32 cents, or 13%, in 1993 compared to 1992, while earnings per share increased 4 cents, or 2%, in 1992 compared to 1991. Both 1993 and 1992 had non- recurring items that lowered earnings per share. Earnings in 1993 were reduced by 25 cents per share as a result of a corporate restructuring that will reorganize the way the Company delivers services to its electric and natural gas customers beginning in March 1994. This restructuring resulted in a work force reduction throughout the organization of approximately 600, the elimination of customer walk-in services at 28 satellite locations, and the closing of up to 10 electric and natural gas operations facilities statewide. This is one of several actions the Company has taken to reduce future costs, enhance efficiencies in service to its customers, and be competitive in the rapidly changing utility industry (See Competitive
Conditions). A six-month electric rate moratorium, which began in February 1992, limited 1992 earnings per share by 24 cents. Excluding the effect of these non-recurring items, earnings per share decreased 31 cents in 1993 compared to 1992, and increased 28 cents in 1992 compared to 1991.
The 31 cent 1993 decrease in earnings per share was primarily due to lower electric retail sales prior to the effective date of the Company's modified revenue decoupling mechanism (See Regulatory Matters) and lower than anticipated natural gas sales, both resulting from the sluggish economy in the Company's service territory. Also, earnings per share decreased due to changes in the Company's allowed return on equity from 11.7% effective through July 1992, to 11.2% effective through July 1993, and then to 10.8% beginning in August 1993.
In 1992, earnings per share were favorably affected by the growth in electric and natural gas retail sales primarily due to an increase in retail customers, colder weather, and the April 1991 acquisition of CNY. The Company's efforts to control costs also contributed to the increase in 1992 earnings per share.
Average shares outstanding were 70 million in 1993, 68 million in 1992, and 63 million in 1991. Average shares outstanding increased 3% in 1993 compared to 1992 due to the issuance of 1.2 million shares of common stock through the Dividend Reinvestment and Stock Purchase Plan (DRP). In 1992, average shares outstanding increased 8% because of a public offering of 5 million shares of common stock in March 1992, and the issuance of 1 million shares of common stock through the DRP.
Interest Expense
Interest expense (before the reduction for allowance for borrowed funds used during construction) decreased by $10 million, or 6%, in 1993 and $8 million, or 5%, in 1992. Interest on long-term debt decreased in 1993 and 1992 mainly due to the refinancing of certain high-coupon long-term debt at lower interest rates, and lower interest rates on the Company's variable rate debt. In 1993 and 1992 interest expense also decreased due to a reduction in the interest rate on the commercial paper borrowings (See Financing Activities).
Operating Results by Business Unit
1993 1992 over over 1992 1991 Electric 1993 1992 1991 Change Change (Thousands)
Retail sales-kilowatt- hours(kwh) 13,088,175 13,294,466 13,107,115 (2%) 1% Operating revenues $1,527,362 $1,451,525 $1,367,936 5% 6% Operating expenses $1,250,000 $1,146,619 $1,056,969 9% 8%
Electric retail sales decreased 2% in 1993 compared to 1992 as a result of the sluggish economy in the Company's service territory and in spite of a 1% increase of customers. In 1992, electric retail sales increased 1% compared to 1991 mainly due to colder but more normal weather and an increase in customers.
The primary cause of the $76 million, or 5%, increase in electric operating revenues in 1993 was the increase in rates effective August 1992 and September 1993, which accounted for $53 million of the increase. Also contributing to this increase were higher costs of NUG power of $28 million, which were billed to customers. Electric operating revenues increased $84 million, or 6%, in 1992 compared to 1991. This increase reflects the increases in electric rates that became effective February 1991 and August 1992 and that increased revenues by $35 million. The revenue increase reflects higher NUG costs of $41 million and an increase in certain New York State gross receipts taxes of $12 million, both of which were billed to customers. Also, increased electric retail sales, due to colder weather and an increase in customers, boosted revenues by $9 million.
Electric operating expenses increased $103 million, or 9%, in 1993 compared to 1992, and $90 million, or 8%, in 1992 compared to 1991. In 1993, electricity purchased from NUGs increased $67 million. Other operating expenses increased primarily due to an increase in postretirement benefit costs other than pensions of $7 million. In addition, electric operating expenses increased $21 million due to the corporate restructuring. These increases were partially offset by a decrease of $17 million in fuel used in electric generation, the result of lower generation and a decrease in the price of coal, and a decrease of $12 million in federal income taxes, the
result of lower pre-tax book income.
In 1992, electricity purchased increased primarily because of the amounts billed to customers for higher NUG costs, which totaled $41 million. Other operating expenses increased primarily because of higher demand-side management (DSM) program costs of $6 million. Federal income taxes increased $4 million resulting from higher pre-tax book income. Other taxes increased primarily because of an increase in certain New York State gross receipts taxes and property taxes of $16 million. These increases were partially offset by a decrease of $12 million in fuel used in electric generation, the result of lower generation and a decrease in the price of coal, and a decrease in maintenance expense of $7 million.
1993 1992 over over 1992 1991 Natural Gas 1993 1992 1991 Change Change (Thousands)
Deliveries -dekatherms(dth) 58,046 56,366 42,404 3% 33% Retail sales-(dth) 39,345 39,357 29,874 - 32% Operating revenues $272,787 $240,164 $187,879 14% 28% Operating expenses $249,493 $221,307 $177,751 13% 25%
Natural gas deliveries increased 3% in 1993 compared to 1992 while natural gas retail sales were flat. In 1992, natural gas deliveries and retail sales increased 33% and 32%, respectively, compared to 1991. The increase in deliveries in 1993 reflects an increase in the number of transportation customers. The 1992 increases in deliveries, as well as retail sales, are largely because of the April 1991 acquisition of CNY. Excluding CNY, natural gas retail sales increased 8% in 1992, primarily because of the colder but more normal weather.
Natural gas operating revenues rose $33 million, or 14%, in 1993 compared to 1992, and $52 million, or 28%, in 1992 compared to 1991. In 1993, the increase was primarily due to higher costs of natural gas of $23 million, which were billed to customers, and the increases in rates in August 1992 and September 1993, which totalled $8 million. The 1992 revenue increases are principally the result of the acquisition of CNY, which added $35 million, and the increases in rates effective February 1991 and August 1992 amounting to $4 million. Also, the recovery of an increase in certain New York State gross receipts taxes, which were billed to customers, boosted 1992 revenues by $2 million.
Natural gas operating expenses increased $28 million, or 13%, in 1993 compared to 1992. The increase in natural gas purchased was primarily due to higher costs of natural gas amounting to $12 million. Federal income taxes increased $3 million due to higher pre-tax book income. Natural gas operating expenses increased $5 million due to the corporate restructuring.
Natural gas operating expenses increased $44 million, or 25%, in 1992 compared to 1991. Natural gas purchased increased $31 million due to an increase in the volume of natural gas purchased. This volume increase was primarily due to the CNY acquisition. Federal income taxes increased $4 million due to higher pre-tax book income. Other taxes increased primarily due to an increase of $3 million in certain New York State gross receipts taxes and $1 million in property taxes.
Liquidity and Capital Resources
Competitive Conditions
The utility industry is rapidly changing and facing an increasingly competitive environment. Factors contributing to this competitive environment are: the National Energy Policy Act of 1992 (Energy Policy Act), which provides open access at the wholesale level to electric transmission service, and the FERC Order 636, which significantly affects the natural gas industry. In addition, the Company's response to the economic pressures on its electric industrial and other large use customers, high purchase costs of NUGs, rising health care costs, increasing taxes, weak economic conditions, conservation programs, and compliance with environmental laws and regulations are all factors that continue to place increased pressure on electric and natural gas prices.
The Energy Policy Act, enacted in October 1992, is expected to result in major changes to the utility industry. Certain provisions of the Energy Policy Act amended the Public Utility Holding Company Act of 1935 (PUHCA). These amendments encourage greater competition in the supply market by establishing a new category of wholesale electric generators that are exempt from PUHCA regulation. The Energy Policy Act also enables the FERC to order utilities to provide open access to transmission systems for wholesale transactions, expanding opportunities for utilities and NUGs to enter new and existing wholesale markets. These developments serve to underscore the increasingly competitive environment for utilities.
The Company's five-year strategic plan is designed to address the competitive, rapidly changing utility industry. The Company's objective is to remain competitive in its core businesses in the face of increased competition. One of the key strategies to meet competition is to improve customer value by becoming a low-cost provider of energy services in the Northeast.
A major challenge to the Company's Electric Business Unit is to retain and grow its industrial base. The competitive energy supply options currently available to the Company's industrial customers include self-generation, shifting production to plants in other locations, or relocation. During 1993, the Company received PSC approval for a flexible, negotiable rate tariff for some of its high-use industrial customers. Discounts negotiated in agreements under this tariff are not expected to have a material effect on the Company's 1994 earnings. Two agreements have been negotiated which eliminated threats of self-generation and relocation.
The PSC currently has a generic proceeding to study the broad subject of flexible, competitive rates, and will establish guidelines for the Company and other New York State utilities during 1994. Also in late 1993, the PSC instituted a proceeding to address issues associated with the restructuring of the emerging competitive natural gas market. The PSC intends to investigate services provided by New York State gas utilities after FERC Order 636 by the 1994-1995 heating season.
In November 1993, the Company filed with the PSC an additional flexible, negotiable rate tariff to address opportunities for new load. The proposed tariff is for large additions to load (at least 500 kilowatts [kw]) for new or existing industrial and some commercial customers. The tariff will assist the Company in attracting new customers whose location or expansion decisions are influenced by electricity costs. Smaller customers will be assisted by a concurrent proposal to increase the Company's existing economic development incentives by one cent per kilowatt-hour. The Company has proposed and will continue to propose revisions or additional tariffs to respond to the opportunities or risks that develop in a changing electric utility industry.
A major challenge to the Company's Gas Business Unit is FERC Order 636, which became effective in November 1993, and requires interstate natural gas pipeline companies to offer customers unbundled or separate services equivalent to their former sales service. With the unbundling of services, primary responsibility for reliable natural gas supply will shift from interstate pipeline companies to local distribution companies, such as the Company. This should result in increased direct access to low cost natural gas supplies by local distribution companies and end users. One goal of FERC Order 636 is to provide equitable access
to interstate pipeline capacity. FERC Order 636 will substantially restructure the interstate natural gas market and intensify competition within the natural gas industry. FERC Order 636 will allow the Company, subject to PSC approval, to restructure rates and provide multiple service options to its customers.
In July 1993, certain interstate pipelines serving the Company began implementing restructured services in compliance with FERC Order 636. The remaining pipelines implemented restructured services by November 1993. As a result of these restructuring changes, pipelines have incurred and will continue to incur transition costs. These transition costs include those associated with restructuring existing natural gas supply contracts, the unrecovered natural gas cost that would otherwise have been billable to pipeline customers under previously existing rules, costs of assets needed to implement the order, and stranded investment costs. FERC Order 636 allows pipelines to recover all prudently incurred costs from their customers. The Company's liability for transition costs will be based on the pipelines' filings with FERC to recover transition costs. Only a few of those filings have been made. The Company recorded an estimated liability for transition costs of approximately $29 million. The Company also recorded a deferred asset for that amount since it is currently recovering transition costs from its customers through its gas adjustment clause and believes that such costs will continue to be recoverable from its customers.
The Company has developed a more aggressive and accelerated set of strategies in response to the increased challenges of competition which are necessary to achieve the objectives outlined in the Company's five-year strategic plan. The following represent strategies being implemented: - Reduce forecasted 1994 capital expenditures by one-third, or approximately $100 million. Additional reductions will be made in 1995 and 1996. - Reduce operating and maintenance expenses by five percent in 1994 and again in 1995. By 1995, this will save about $40 million annually. During 1993, the Company reduced its work force by 200 through attrition. In addition, as part of the O&M reduction, the Company's work force was further reduced by about 600 through an early retirement opportunity program and involuntary severance. - Streamline the field organization to eliminate walk-in customer service at 28 locations, and to close up to 10 electric and natural gas operations facilities statewide. - Place two generating units on long-term cold standby. - Continue to reduce NUG costs. The Company's previous NUG contract terminations and renegotiations will save customers more than $1 billion over the terms of the contracts. - Continue to reduce capital costs. Since 1988 the Company has refinanced over $1.4 billion in securities, and reduced
annual interest expense by more than $55 million.
The cost of the corporate restructuring was $26 million and was a one-time charge against the Company's 1993 earnings. The restructuring reduced 1993 earnings available for common stock by approximately $17.2 million or 25 cents per share. Included in this amount are $13.2 million for a voluntary early retirement program, $3.2 million for an involuntary severance program, and $.8 million for the elimination and closing of operations facilities. The Company expects to recoup the one-time charge from lower O&M costs in approximately one year.
As part of the Company's effort to meet competition and minimize future price increases associated with uneconomical power purchases from NUGs, it negotiated the termination of two cogeneration projects. This effort, along with the termination of NUG contracts due to developers' failures to meet contract obligations, will save customers nearly $1 billion over the terms of the contracts. The Company has also recently negotiated amendments with two NUGs whereby the Company may direct the NUGs to reduce their output or shut down for limited periods each year. During these periods, lower-cost generation will replace the NUG energy and result in additional customer savings. The Company is negotiating with other NUGs for similar amendments.
The Company has on line and under contract 362 megawatts (mw) of NUG power. In addition, another 240 mw of NUG power is under construction. The Company is required to make payments under these contracts only for the power it receives. During 1993, 1992, and 1991, the Company purchased approximately $138 million, $71 million, and $30 million, respectively, of NUG power. The Company estimates that it will purchase approximately $255 million, $291 million, and $335 million of NUG power for the years 1994, 1995, and 1996, respectively. Increases in NUG power purchase costs are expected to be a significant contributor to price increases over the next three years.
Diversification
Diversification will play an important role in the Company's future. While the strength of the Company's core electric and natural gas businesses remains its focus, and while the Company will not compromise its financial integrity, it is actively evaluating a number of corporate development opportunities for investment to help augment future earnings and dividend growth. In April 1992, the PSC issued an order allowing the Company to invest up to 5% of its consolidated capitalization (approximately $175 million at December 31, 1993) in one or more subsidiaries that may engage or invest in energy-related or environmental services businesses and provide related services. In May 1993, NGE Enterprises, Inc. (NGE), a wholly-owned subsidiary of the Company, formed a computer software company, EnerSoft Corporation
(EnerSoft), to produce and market software applications for natural gas utilities in the post-FERC Order 636 environment. This represents NGE's initial diversified investment.
In October 1993, EnerSoft began a strategic alliance with the New York Mercantile Exchange to develop an information superhighway that will provide the natural gas industry with a single system for monitoring and trading natural gas and pipeline capacity in the North American market. NGE invested approximately $9 million in EnerSoft through February 1994.
The Company and NGE plan to develop two natural gas storage projects. One of the projects, which will be regulated by the PSC, is expected to cost approximately $14 million and will be used to supplement the Company's natural gas supply. Construction of this project is scheduled to begin in 1994 and it is expected to be operating for the 1995-96 heating season. The other project, which will be regulated by the FERC, is an equal partnership between NGE and ANR Storage, Inc., and is expected to cost approximately $44 million in total. The entire capacity of this project will be marketed to local distribution companies and NUGs, as well as marketers, producers, and end users of natural gas. Construction of this project is scheduled to begin in 1995 and it is expected to be operating for the 1996-1997 heating season.
Financing Activities
The Company believes that maintaining a high degree of financial integrity and flexibility is critical to success in an increasingly competitive environment. The Company intends to build on the financial improvements realized over the past several years with a goal of achieving a 50% common equity ratio. New money needs are expected to be minimal and excess cash generated from reduced construction expenditures will be used to further manage the Company's capital structure (See Investing Activities - estimated sources and uses of funds for 1994-1996).
The PSC adopted a new, innovative approach in December 1993 when it issued an order to the Company that provides for advanced approval for financings during the Company's three-year rate settlement. That order includes authorization for refundings of first mortgage bonds, preferred stock, and tax-exempt pollution control notes, issuance of common stock through the Dividend Reinvestment and Stock Purchase Plan (DRP), and issuances of other securities as required. With this order, the Company has the flexibility to achieve its financial goals of further reducing financing costs and improving its financial health as market conditions allow.
The common stock equity ratio remained stable during 1993. Issuance of shares under the DRP was offset by the issuance of
$100 million of preferred stock and $70 million of tax-exempt pollution control notes in December 1993. The Company received $38.4 million from the issuance of 1.2 million shares of common stock through the DRP.
Common stock dividends paid in 1993 increased 5% over 1992 reflecting the increase in common stock outstanding and an increase in the dividend paid from $2.14 to $2.18 per share.
The Company's dividend payout ratio has been gradually rising over the past several years, primarily as a result of declining earnings. These weak earnings put additional pressure on an already high dividend payout ratio at a time when growing competition dictates that we consider a more moderate dividend policy. We must significantly improve earnings if we are to continue even modest annual dividend increases.
The Company sold $25 million of 6.30% preferred stock, $50 million of Adjustable Rate Series B preferred stock, and $25 million of 7.40% preferred stock in December 1993. The net proceeds were used to redeem $25 million of 8.80% preferred stock and $45 million of Adjustable Rate Series A preferred stock in January 1994, and $25 million of 8.48% preferred stock in February 1994. Those refundings will save approximately $1.8 million annually. After those refundings, the capital structure will be 49.8% long-term debt, 7.1% preferred stock, and 43.1% common stock equity.
In February 1993, the Company redeemed, at par, through a sinking fund provision in our mortgage, the remaining $22.5 million of 10 5/8% Series first mortgage bonds due 2018.
In February 1993, the Company priced $100 million of 6.05% tax-exempt pollution control bonds, due 2034. Proceeds from the sale, which will be delivered in April 1994, will be used to redeem, at a premium, $60 million of 12% pollution control bonds, due 2014, and $40 million of 12.3% pollution control bonds, due 2014. The refunding of those bonds in 1994 will save approximately $5.3 million annually in interest costs.
In April 1993, the Company sold $50 million of 7.55% Series first mortgage bonds due 2023. Net proceeds from the sale were used in connection with the redemption of $50 million of the 9 1/4% Series due 2016. The refunding of those bonds will save approximately $300,000 annually in interest costs.
In July 1993, the Company sold $100 million of 7.45% Series first mortgage bonds due 2023. Net proceeds from the sale were used in connection with the redemption of $100 million of the 9% Series due 2017. The refunding of those bonds will save approximately $650,000 annually in interest costs.
In November 1993, the Company redeemed $50 million of the 8 5/8% Series first mortgage bonds due 1996, at a premium. Proceeds for the redemption were provided by a borrowing under the Company's revolving credit agreement. The refunding of those bonds will save approximately $2 million annually in interest costs.
In December 1993, $70 million of 5.70% tax-exempt pollution control notes, due 2028, were issued by a governmental authority on behalf of the Company. Proceeds from the sale will be used to finance a portion of the costs incurred in the construction of certain solid waste disposal and other related facilities at the Company's Milliken Generating Station.
The Company has reduced its embedded cost of long-term debt to 7.2% at the end of 1993 from 9.2% in 1988. The Company has refinanced more than $1.2 billion in long-term debt since 1988, and reduced annual interest expense by more than $55 million. Unless interest rates fall further, however, it will be difficult to significantly improve from the 7.2% level. All opportunities continue to be pursued aggressively.
In February 1994, the Company redeemed, at par, through a sinking fund provision in its mortgage, $23 million of 8 5/8% Series first mortgage bonds due 2007.
In February 1994, $37.5 million of tax-exempt pollution control notes were issued by a governmental authority on behalf of the Company. The notes will have several interest rate options and have an initial rate of 2.4% through April 13, 1994. Proceeds from the sale will be used to redeem $37.5 million of annual adjustable rate pollution control notes, due 2015, in March 1994.
The Company uses interim financing in the form of short-term unsecured notes, usually commercial paper, to finance certain refundings and construction expenditures and for other corporate purposes, thereby providing flexibility in the timing and amounts of long-term financings. There was $50.2 million of commercial paper outstanding at December 31, 1993, at a weighted average interest rate of 3.5%. The weighted average interest rate during 1993 was 3.4%.
The Company also has a revolving credit agreement with certain banks that provides for borrowing up to $200 million to July 31, 1997. The Company had an outstanding $50 million loan under this agreement at December 31, 1993, at an interest rate of 4.06%.
In June 1993, the Company's first mortgage bonds and unsecured pollution control notes were upgraded by Standard & Poor's (S&P). The investment rating agency stated that the
higher ratings reflect expected continued improvements in the Company's financial condition as a result of the Company's three- year rate settlement, which was pending at the time of the upgrade, aggressive cost controls, and limited new money needs. S&P also noted that regulatory adjustment mechanisms, such as electric revenue decoupling and natural gas weather normalization, should add stability to earnings.
In October 1993, S&P completed its review of the U.S. investor-owned utility industry and concluded that more stringent financial benchmarks were appropriate for electric utilities to counter increased competition and mounting business risk. As a result, it revised the rating outlook downward for about one- third of the utility industry, including the Company. However, the Company's ratings were not changed.
Investing Activities
The Company's 1993 capital expenditures for its core electric and natural gas businesses totaled approximately $245 million. Most of the expenditures were for the extension of service and for improvements at existing facilities.
Capital expenditures for 1994-1996 have been significantly reduced from previously forecasted levels. This represents one of many actions the Company is taking to address competition (See Competitive Conditions). Capital expenditures for 1994-1996 will be primarily for extension of service, necessary improvements at existing facilities, and compliance with the Clean Air Act Amendments of 1990 (See Environmental Matters). The Company forecasts that its current reserve margin, coupled with more efficient use of energy (See Conservation Programs) and generation from NUGs, will eliminate the need for additional generating capacity until after the year 2005.
As part of the Company's effort to reduce costs, one of two generating units at each of its Goudey and Greenidge Generating Stations will be placed on long-term cold standby. These actions are being taken because the abundance of power in the Northeast has driven down wholesale prices. These units will continue to be utilized to provide electrical system support.
The following table provides information on the Company's estimated sources and uses of funds for 1994-1996. This forecast is subject to periodic review and revision, and actual construction costs may vary because of revised load estimates, imposition of additional regulatory requirements, and the availability and cost of capital.
1994 1995 1996 Total ---- ---- ---- ----- Sources of funds (Millions)
Internal funds $254 $265 $269 $788 Long-term financing Debt and stock proceeds 413 141 80 634 Debt proceeds held in trust 34 8 - 42 ---- ---- ---- ----- Net financing proceeds 447 149 80 676
Increase (decrease) in short-term debt (50) - - (50) Decrease (increase) in temporary cash investments 89 (69) (52) (32) ---- ---- ---- ------ Total $740 $345 $297 $1,382 ==== ==== ==== ====== Uses of funds
Construction Cash expenditures $202 $193 $193 $588 AFDC 8 7 7 22 ---- ---- ---- ------ Total construction 210 200 200 610 Retirement of securities and sinking fund obligations 501 108 63 672 Working capital and deferrals 29 37 34 100 ---- ---- ---- ------ Total $740 $345 $297 $1,382 ==== ==== ==== ======
As shown in the preceding table, internal sources of funds represent 129% of construction expenditures for 1994-1996.
Conservation Programs
The Company has implemented a number of demand-side management (DSM) programs. As a result of its three-year rate settlement agreement (See Regulatory Matters), incentives earned for conducting efficient DSM programs were reduced from 15% to 5% of the net resource savings achieved by these DSM programs. For 1994, the Company expects to earn approximately $3 million in incentives as a result of these DSM programs.
In 1993, the Company's customers saved approximately 282 million kilowatt-hours (kwh) on an annualized basis through the Company's DSM programs. The implementation of these programs cost $48 million in 1993 and will cost approximately $16 million in 1994 with estimated customer savings of 113 million kwh on an annualized basis. The Company has approximately $73 million and $44 million of deferred DSM program costs on the Consolidated Balance Sheets at December 31, 1993, and 1992, respectively. The two-year (1993-1994) DSM plan, which has received PSC approval, has been modified to improve cost-effectiveness and reduce rate impacts.
Environmental Matters
The Company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Compliance programs will increase the cost of electric and natural gas service by requiring changes to the Company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred for compliance with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the Company may also incur costs from the past disposal of hazardous substances produced during the Company's operations or those of its predecessors. The Company has been notified by the EPA and the NYSDEC that it is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at seven waste sites, not including the Company's inactive gas manufacturing sites, which are discussed below. With respect to the seven sites, five sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry).
Any liability may be joint and several for certain of these sites. The ultimate cost to remediate these sites will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the Company. At December 31, 1993, the Company recorded a liability in the Consolidated Balance Sheets related to four of these seven waste sites of $1.8 million. The Company has notified the NYSDEC that it believes it has no responsibility at two sites and has already incurred expenditures related to the remediation at the remaining site. A deferred asset has also been recorded in the amount of $2.6 million, of which $.8 million relates to costs that have already been incurred. The Company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the Company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites. This $1.8 million estimate was derived by
multiplying the total estimated cost to clean up a particular site by the related Company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the Company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the Company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the Company's inactive gas manufacturing sites have been listed in the New York State Registry. The Company has filed petitions to delist the majority of the sites. The Company's program to investigate and initiate remediation at its 38 known inactive gas manufacturing sites has been extended through the year 2000. Expenditures over this time period are estimated to be $25 million. This estimate was determined by using the Company's experience and knowledge related to these sites as a result of the investigation and remediation that the Company has performed to date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability, to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites is reflected in the Company's Consolidated Balance Sheets at December 31, 1993 and 1992. The Company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the Company has previously been allowed by the PSC to recover such costs in rates. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in significant expenditures of approximately $178 million, on a present value basis, over a 25-year period, for all capital and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the Company's coal-fired generating stations, of which $51 million has been incurred as of December 31, 1993. The Company's current estimate is a significant reduction from its prior estimate, primarily due to the postponement of the construction of a flue gas desulfurization (FGD) system at its Homer City Generating
Station. The Company plans to re-evaluate the need to construct an FGD system at the Homer City Generating Station in 1995, since its present strategy to bank Phase I emissions allowances for use during Phase II, as discussed below, will allow the Company to meet Phase II allowance requirements through the year 2005. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative FGD system and a nitrogen oxide reduction system expected to be completed in 1995 at the Company's Milliken Generating Station. The Company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (begins January 1, 1995) and Phase II (begins January 1, 2000). As a result of the 1990 Amendments, the Company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the Company to meet the sulfur dioxide levels established for the Company, which is approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time. Regulations may be adopted at the state level which would limit toxic emissions even further, at an additional cost to the Company. The Company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the U.S. Environmental Protection Agency (EPA) to allocate annual emissions allowances to each of the Company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the Company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The Company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the Company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the Company by the EPA, the Company will receive a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers, as a result of the pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the Company will incur approximately $24 million, on a present value basis, of additional costs over the next 30 years, beginning in 1994, at the Homer City Generating Station. These costs will be incurred to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The Company expects to recover these expenditures in rates, since the Company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Regulatory Matters
In September 1993, the Company reached a three-year electric and natural gas rate settlement agreement (Agreement) with the PSC. The new electric and natural gas rates became effective September 4, 1993.
The allowed return on equity is 10.8% in year one, 11.4% in year two, and 11.4% (subject to an indexing mechanism) in year three. Shareholders will be allowed to keep 100% of any earnings in excess of the allowed return in year one. Shareholders and customers will share, on a 50%/50% basis, any earnings in excess of the allowed return in years two and three.
The Agreement also includes a modified revenue decoupling mechanism (RDM) for electric sales. Rates are based on sales forecasts. Since actual sales may differ significantly from forecasted sales because of conservation efforts, unusual weather, or changing economic conditions, the revenue collected may be more or less than forecast. Subject to the caps described below, the modified RDM will let the Company adjust for most of the differences between forecasted and actual sales. For example, if revenues exceed the forecast for a given year, the excess would be passed back to customers in a future year. If revenues are below the forecast, customers would receive a surcharge in a future year. The Company will share excesses or shortfalls from most large commercial and industrial sales revenues on a 70%/30% (customer/stockholder) basis.
Customer savings for production and transmission operating costs of $21 million will be imputed over three years, $7 million each year, whether or not they are realized.
Incentives for customer service, production cost, and DSM could increase the allowed return to 12.3% or decrease it to 9.95% in year one, increase it to 13.05% or decrease it to 10.4% in year two, and increase it to 13.25% or decrease it to 10.2% in year three.
The electric and natural gas rate increases discussed below represent eleven months for year one and twelve months for years two and three.
The estimated total electric price increases below include base rate increases allowed by the Agreement plus estimates of fuel and purchased power increases which will be collected through the Fuel Adjustment Clause (FAC). Actual fuel and purchased power costs could vary from estimates causing the estimated FAC and total electric price increases below to change.
Base Rate Estimated FAC Total Electric (Dollar Amounts in Millions)
Year 1 $60.5 4.4% $39.1 3.0% $99.6 7.4% Year 2 $70.3 4.8% $39.2 2.8% $109.5 7.6% Year 3 $57.4 3.6% $30.4 2.0% $87.8 5.6%
The natural gas base rate increases allowed by the Agreement are $7.5 million, or 2.9%, $8.2 million, or 3.0%, and $7.2 million, or 2.5%, in years one, two, and three, respectively. They do not include changes in natural gas costs, which will be collected through the Gas Adjustment Clause. Natural gas costs can be expected to rise and fall with overall natural gas market conditions. Such fluctuations will affect the total natural gas price increases.
The Agreement also provides for the stated electric and natural gas base rate increases to be adjusted up or down in the second and third years, as well as the year after the Agreement period (year four). These adjustments will depend on several factors, such as electric sales and incentive mechanisms. The Agreement provides that no cap would apply to any downward revision to base rates for electric and natural gas service. The electric base rate increases could be increased by up to 1.5% in years two and three and 1.6% in year four (the caps). The natural gas base rate increases could also be increased by up to 1% in year two and 1.2% in year three. The Agreement does not specify a cap for natural gas base rates for year four.
Item 8.


Item 8. Financial statements and supplementary data
New York State Electric & Gas Corporation Consolidated Statements of Income
Year Ended December 31 1993 1992 1991 - ---------------------------------------------------------------------------- (Thousands, except Per Share Amounts)
Operating Revenues Electric . . . . . . . . . . . . . . . . $1,527,362 $1,451,525 $1,367,936 Natural gas. . . . . . . . . . . . . . . 272,787 240,164 187,879 ---------- ---------- ---------- Total Operating Revenues . . . . . . $1,800,149 1,691,689 1,555,815 ---------- ---------- ---------- Operating Expenses Fuel used in electric generation . . . . 245,283 262,531 274,877 Electricity purchased (Note 9) . . . . . 161,967 95,026 45,808 Natural gas purchased. . . . . . . . . . 141,635 126,815 99,528 Other operating expenses . . . . . . . . 349,177 318,680 279,364 Restructuring expenses (Notes 6 and 7) . 26,000 - - Maintenance. . . . . . . . . . . . . . . 111,757 102,500 110,131 Depreciation and amortization (Note 1) . 164,568 158,977 152,380 Federal income taxes (Notes 1 and 2) . . 94,144 102,456 94,447 Other taxes (Note 12). . . . . . . . . . 204,962 200,941 178,185 ---------- ---------- ---------- Total Operating Expenses . . . . . . . 1,499,493 1,367,926 1,234,720 ---------- ---------- ---------- Operating Income. . . . . . . . . . . . . 300,656 323,763 321,095 Other Income and Deductions . . . . . . . 6,471 12,036 6,076 ---------- ---------- ---------- Income Before Interest Charges. . . . . . 307,127 335,799 327,171 ---------- ---------- ---------- Interest Charges Interest on long-term debt . . . . . . . 134,330 145,822 151,649 Other interest . . . . . . . . . . . . . 11,120 9,566 11,877 Allowance for borrowed funds used during construction. . . . . . . . (4,351) (3,557) (4,998) ---------- ---------- ---------- Interest Charges - Net . . . . . . . . 141,099 151,831 158,528 ---------- ---------- ---------- Net Income. . . . . . . . . . . . . . . . 166,028 183,968 168,643 Preferred Stock Dividends . . . . . . . . 20,638 20,995 20,330 ---------- ---------- ---------- Earnings Available for Common Stock . . . $145,390 $162,973 $148,313 ========== ========== ========== Earnings Per Share. . . . . . . . . . . . $2.08 $2.40 $2.36 Average Shares Outstanding. . . . . . . . 69,990 67,972 62,906
The notes on pages 50 through 73 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1993 1992 - ------------------------------------------------------------------------------- (Thousands) Assets
Utility Plant, at Original Cost (Note 1) Electric (Note 8). . . . . . . . . . . . . . . . . . . $4,777,368 $4,573,444 Natural gas. . . . . . . . . . . . . . . . . . . . . . 381,389 352,059 Common . . . . . . . . . . . . . . . . . . . . . . . . 158,986 157,979 ---------- ---------- . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,317,743 5,083,482 Less accumulated depreciation. . . . . . . . . . . . . 1,541,456 1,427,793 ---------- ---------- Net Utility Plant in Service. . . . . . . . . . . . 3,776,287 3,655,689 Construction work in progress. . . . . . . . . . . . . 143,859 177,566 ---------- ---------- Total Utility Plant . . . . . . . . . . . . . . . . 3,920,146 3,833,255
Other Property and Investments, net . . . . . . . . . . 73,537 59,157
Current Assets Cash and cash equivalents (Notes 1 and 10) . . . . . . 4,264 3,968 Special deposits (Note 10) . . . . . . . . . . . . . . 145,335 96,432 Accounts receivable, net (Note 1). . . . . . . . . . . 181,586 171,683 Fuel, at average cost. . . . . . . . . . . . . . . . . 54,791 69,077 Materials and supplies, at average cost. . . . . . . . 48,910 50,637 Prepayments. . . . . . . . . . . . . . . . . . . . . . 30,092 37,897 Accumulated deferred federal income tax benefits (Notes 1 and 2). . . . . . . . . . . . - 1,182 ---------- ----------
Total Current Assets. . . . . . . . . . . . . . . . 464,978 430,876
Deferred Charges (Note 1) Unfunded future federal income taxes (Notes 1 and 2) . . . . . . . . . . . . . . . 380,056 393,720 Unamortized debt expense . . . . . . . . . . . . . . . 112,059 96,378 Demand-side management program costs . . . . . . . . . 73,113 44,049 Other. . . . . . . . . . . . . . . . . . . . . . . . . 252,127 220,481 ---------- ---------- Total Deferred Charges. . . . . . . . . . . . . . . 817,355 754,628 ---------- ---------- Total Assets. . . . . . . . . . . . . . . . . . . . $5,276,016 $5,077,916 ========== ==========
The notes on pages 50 through 73 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1993 1992 - ------------------------------------------------------------------------------ (Thousands) Capitalization and Liabilities
Capitalization Common stock equity Common stock ($6.66 2/3 par value, 90,000,000 shares authorized and 70,595,985 and 69,439,397 shares issued and outstanding at December 31, 1993 and 1992, respectively) . . . . . . . . . . $470,640 $462,929 Capital in excess of par value. . . . . . . . . . 824,943 796,505 Retained earnings . . . . . . . . . . . . . . . . 320,114 327,040 ---------- ---------- Total common stock equity. . . . . . . . . . . . . . . 1,615,697 1,586,474 Preferred stock redeemable solely at the option of the Company (Note 4). . . . . . . . . . . . . . . . 140,500 160,500 Preferred stock subject to mandatory redemption requirements (Notes 4 and 10) . . . . . . . . . . . 125,000 106,900 Long-term debt (Notes 3 and 10). . . . . . . . . . . . 1,630,629 1,777,027 ---------- ---------- Total Capitalization. . . . . . . . . . . . . . . 3,511,826 3,630,901 Current Liabilities Current portion of long-term debt and preferred stock (Notes 3 and 4) . . . . . . . . . . . . . . . 332,709 115,659 Commercial paper (Notes 5 and 10). . . . . . . . . . . 50,200 64,100 Accounts payable and accrued liabilities . . . . . . . 111,481 95,996 Interest accrued (Note 10) . . . . . . . . . . . . . . 31,348 37,690 Accumulated deferred federal income taxes (Notes 1 and 2) . . . . . . . . . . . . . . . . . . 1,132 - Other. . . . . . . . . . . . . . . . . . . . . . . . . 89,443 65,073 ---------- ---------- Total Current Liabilities . . . . . . . . . . . . 616,313 378,518
Deferred Credits Accumulated deferred investment tax credits (Notes 1 and 2) . . . . . . . . . . . . . . . . . . 138,478 141,729 Excess deferred federal income taxes (Notes 1 and 2) . 36,378 58,188 Other. . . . . . . . . . . . . . . . . . . . . . . . . 149,620 107,160 ---------- ---------- Total Deferred Credits. . . . . . . . . . . . . . 324,476 307,077
Accumulated Deferred Federal Income Taxes (Notes 1 and 2) Unfunded future federal income taxes . . . . . . . . . 380,056 393,720 Other. . . . . . . . . . . . . . . . . . . . . . . . . 416,545 342,700 ---------- ---------- Total Accumulated Deferred Federal Income Taxes . . . . . . . . . . . . . . . . . . 796,601 736,420
Commitments and Contingencies (Note 9). . . . . . . . . 26,800 25,000 ---------- ---------- Total Capitalization and Liabilities. . . . . . . $5,276,016 $5,077,916 ========== ==========
The notes on pages 50 through 73 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
1 Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the Company's wholly-owned subsidiaries, Somerset Railroad Corporation (SRC) and NGE Enterprises, Inc. (NGE). All significant intercompany balances and transactions are eliminated in consolidation.
Utility plant
The cost of repairs and minor replacements is charged to the appropriate operating expense accounts. The cost of renewals and betterments, including indirect cost, is capitalized. The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
Depreciation and amortization
Depreciation expense is determined using straight-line rates, based on the average service lives of groups of depreciable property in service. Depreciation accruals were equivalent to 3.4%, 3.3%, and 3.3%, of average depreciable property for 1993, 1992, and 1991, respectively. Depreciation expense includes the amortization of certain deferred charges authorized by the Public Service Commission of the State of New York (PSC).
Revenue
During 1993, 1992, and 1991, the Company recognized on the income statement approximately $12 million, $22 million, and $40 million, respectively, of electric and natural gas unbilled revenues that had been accrued on its balance sheet for energy provided but not yet billed to minimize the rate increases for these years in accordance with various PSC rate decisions. The July 1992 rate decision allowed the Company to recognize on its income statement, beginning in August 1992, electric and natural gas unbilled revenues on a full accrual basis.
The Company recognizes as revenue incentives earned as the result of conducting efficient demand-side management (DSM) programs. The Company is collecting those incentives in rates within approximately one year after they are recognized. During 1993, 1992, and 1991, incentives earned were $16.4 million, $15.6 million, and $12.4 million, respectively. At December 31, 1993 and 1992, approximately $14.3 million and $9.8 million, respectively, of DSM incentives were accrued and included in accounts receivable.
Accounts receivable
The Company has an agreement that expires in November 1996 to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allows the Company to receive up to $152 million from the sale of such interests. At December 31, 1993 and 1992, accounts receivable on the Consolidated Balance Sheets is shown net of $152 million and $138 million, respectively, of interests in accounts receivable sold. All fees associated with the program are included in other income and deductions on the Consolidated Statements of Income and amounted to approximately $5.7 million, $6.5 million, and $9.3 million in 1993, 1992, and 1991, respectively. Accounts receivable on the Consolidated Balance Sheets is also shown net of an allowance for doubtful accounts of $4 million and $1.9 million at December 31, 1993 and 1992, respectively. Bad debt expense was $15.3 million, $11.5 million, and $10.7 million in 1993, 1992, and 1991, respectively.
Federal income taxes
The Company adopted Statement of Financial Accounting Standards No. 109 (SFAS 109), Accounting for Income Taxes, in January 1993. Since the Company had been accounting for income taxes under Statement of Financial Accounting Standards No. 96, Accounting for Income Taxes, there was no effect on the Consolidated Statements of Income as a result of adopting SFAS 109. However, SFAS 109 did require the Company's deferred tax balances to be reclassified on its Consolidated Balance Sheets.
The Company files a consolidated federal income tax return with SRC and NGE. Deferred income taxes are provided on all temporary differences between financial statement basis and taxable income. Investment tax credits, which reduce federal income taxes currently payable, are deferred and amortized over the estimated lives of the applicable property. The effect of the alternative minimum tax, which increases federal income taxes currently payable and generates a tax credit available for future use, is deferred and amortized at such times as the tax credit is used on the Company's federal income tax return.
Deferred charges
The Company defers certain incurred expenses when authorized by the PSC. Those expenses will be recovered from customers in the future.
Consolidated Statements of Cash Flows
The Company considers all highly liquid investments with a maturity or put date of three months or less when acquired to be
cash equivalents. These investments are included in cash and cash equivalents on the Consolidated Balance Sheets.
Total income taxes paid were $27.3 million, $38.5 million, and $31.8 million for the years ended December 31, 1993, 1992, and 1991, respectively.
Interest paid, net of amounts capitalized, was $138.2 million, $149.3 million, and $159.9 million for the years ended December 31, 1993, 1992, and 1991, respectively.
The Company purchased all of the common stock of Columbia Gas of New York, Inc. in 1991. In conjunction with the acquisition, liabilities assumed were $24.9 million (fair value of assets acquired of $82 million less cash paid of $57.1 million).
Reclassification
Certain amounts have been reclassified on the consolidated financial statements to conform with the 1993 presentation.
2 Federal Income Taxes
Year ended December 31 1993 1992 1991 (Thousands) Charged to operations Current $34,989 $37,237 $22,991 Deferred - net Accelerated depreciation 49,580 41,492 37,409 Unbilled revenues 5,073 160 13,644 Alternative minimum tax (AMT) credit (3,194) 2,123 5,557 Demand-side management 13,479 9,324 8,589 NUG termination agreement 4,760 6,800 - Nine Mile No. 2 litigation proceeds 4,756 (2,047) - Restructuring expenses (6,965) - - Transmission facility agreement(7,778) (1,172) (1,162) Miscellaneous (6,198) (3,491) (9,365) Investment tax credit (ITC) deferred 5,642 12,030 16,784 ------- -------- ------- 94,144 102,456 94,447 Included in other income Amortization of deferred ITC (8,892) (16,927) (11,297) Miscellaneous 498 3,747 (533) ------- -------- ------- Total $85,750 $89,276 $82,617 ======= ======== =======
The Company's effective tax rate differed from the statutory rate of 35% in 1993 and 34% in 1992 and 1991 due to the following:
Year ended December 31 1993 1992 1991 (Thousands)
Tax expense at statutory rate $88,684 $92,903 $85,428 Depreciation not normalized 16,984 16,697 16,051 ITC amortization (8,892) (16,927) (11,297) Research & Development (R&D) credit (5,139) - - Cost of removal (4,921) (4,079) (6,120) Other - net (966) 682 (1,445) ------- ------- ------ Total $85,750 $89,276 $82,617 ======= ======= ======= The Company's current and noncurrent deferred taxes, which net to a tax liability of approximately $936.2 million as of December 31, 1993, consisted of the following deferred tax assets and liabilities:
Deferred Tax Deferred Tax Assets Liabilities (Thousands) Depreciation $ 698,939 Loss on reacquired debt 28,440 Regulatory Asset (SFAS 109) 149,636 Accumulated deferred ITC 91,006 Demand-side management 35,381 NUG contract settlement costs 15,163 Alternative minimum tax credit $ 19,953 Excess tax reserve 12,603 Nine Mile No. 2 disallowed plant 19,347 Contributions in aid of construction 20,913 Capitalized interest 8,690 Other 35,369 34,521 ----------- ------------ Total deferred taxes $116,875 $1,053,086 =========== ============
The Revenue Reconciliation Act (RRA) of 1993 was enacted on August 10, 1993. Among other things, RRA 1993 provided for an increase of 1% in the statutory corporate income tax rate and an extension of the R&D credit until June 30, 1995.
In September 1993, the Company reached a three-year rate settlement agreement with the PSC (Agreement) which included a provision for the Company to petition to defer the effect of RRA 1993 until it is reflected in rates. The Company has deferred for collection from customers $.6 million representing additional 1993 federal income taxes resulting from RRA 1993.
The Company has recorded unfunded future federal income taxes and a corresponding receivable from customers of approximately $381 million and $393 million as of December 31, 1993 and 1992, respectively, primarily representing the cumulative amount of federal income taxes on temporary depreciation differences, which were previously flowed through to customers. Those amounts, including the tax effect of the future revenue requirements, are being amortized over the life of the related depreciable assets concurrent with their recovery in rates.
The Company has approximately $20 million of AMT credits which do not expire, and $5.1 million of R&D credits which expire beginning in 2005.
3 Long-Term Debt
At December 31, 1993 and 1992, long-term debt was (Thousands):
First mortgage bonds Amount
Series Due 1993 1992
8 3/8% Aug. 15, 1994 $ 100,000 $100,000 8 5/8% June 1, 1996 - 50,000 5 5/8% Jan. 1, 1997 25,000 25,000 6 1/4% Sept. 1, 1997 25,000 25,000 6 1/2% Sept. 1, 1998 30,000 30,000 7 5/8% Nov. 1, 2001 50,000 50,000 6 3/4% Oct. 15, 2002 150,000 150,000 9 3/8% Jan. 1, 2006 - 3,000 7 1/4% June 1, 2006 12,000 12,000 6 7/8% Dec. 1, 2006 25,250 25,500 8 5/8% Nov. 1, 2007 60,000 60,000 9 1/4% Apr. 1, 2016 - 50,000 9% Mar. 1, 2017 - 100,000 10 5/8% Jan. 1, 2018 - 100,000 9 7/8% Feb. 1, 2020 100,000 100,000 9 7/8% May 1, 2020 100,000 100,000 9 7/8% Nov. 1, 2020 100,000 100,000 8 7/8% Nov. 1, 2021 150,000 150,000 8.30 % Dec. 15, 2022 100,000 100,000 7.55 % Apr. 1, 2023 50,000 - 7.45 % July 15, 2023 100,000 - --------- --------- Total first mortgage bonds 1,177,250 1,330,500 ========= =========
Pollution control notes
Interest Maturity Interest Rate Letter of Credit Amount Rate Date Adjustment Date Expiration Date 1993 1992 12% May 1, 2014* - - 60,000 60,000 12.30% July 1, 2014* - - 40,000 40,000 2.80% Dec. 1, 2014 Dec. 1, 1994 Dec. 15, 1995 74,000 74,000 2.75% Mar. 1, 2015 Mar. 1, 1994 Mar. 15, 1995 37,500 37,500 2.50% Mar. 15, 2015 Mar. 15, 1994 Mar. 31, 1995 60,000 60,000 2.60% July 15, 2015 July 15, 1994 July 31, 1995 63,500 63,500 2.85% Oct. 15, 2015 Oct. 15, 1994 Oct. 31, 1995 30,000 30,000 2.75% Dec. 1, 2015 Dec. 1, 1994 Dec. 15, 1995 42,000 42,000 4.10% July 1, 2026 July 1, 1996 July 15, 1996 65,000 65,000 5.95% Dec. 1, 2027 - - 34,000 34,000 5.70% Dec. 1, 2028 - - 70,000 - ---------- ---------- Total pollution control notes 576,000 506,000 ========== ========== Revolving Credit Agreement Note due July 31, 1997 50,000 - Long-term notes due December 31, 1996 36,100 27,707 CNG Transmission Corp. Note due November 10, 1996 8,862 - Obligations under capital leases 30,902 38,804 Unamortized premium and discount on debt-net (10,776) (11,975) ---------- ---------- 1,868,338 1,891,036 Less: debt due within one year-included in current liabilities 237,709 114,009 ---------- ---------- Total $1,630,629 $1,777,027 ========== ========== * Will be refunded in 1994 with proceeds from the issuance of $100 million of 6.05% pollution control notes due 2034.
At December 31, 1993, long-term debt and capital lease payments which will become due during the next five years are:
1994 1995 1996 1997 1998 (Thousands) $237,709 $12,552 $45,651 $102,196 $31,411
The Company's mortgage provides for a sinking and improvement fund. This provision requires the Company to make annual cash deposits with the Trustee equivalent to 1% of the principal amount of all bonds delivered and authenticated by the Trustee prior to January 1 of that year (excluding any bonds issued on the basis of the retirement of bonds). The Company satisfied this requirement in 1993 by depositing $22.5 million in cash which was used to redeem in February 1993, $22.5 million of 10 5/8% Series first mortgage bonds, due 2018. The Company satisfied this requirement in 1994 by depositing $23 million in cash which was used to redeem in February 1994, $23 million of 8 5/8% Series first mortgage bonds, due 2007.
Mandatory annual cash sinking fund requirements are $600,000 beginning June 1, 2001, for the 7 1/4% Series and $250,000 on December 1 in each year 1994 to 1996, for the 6 7/8% Series. The amount increases to $500,000 and $750,000 on December 1, 1997 and December 1, 2002, respectively, for the 6 7/8% Series.
The Company's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all utility plant.
Adjustable rate pollution control notes were issued to secure like amounts of tax-exempt adjustable rate pollution control revenue bonds (Revenue Bonds) issued by a governmental authority. The Revenue Bonds bear interest at the rate indicated through the date preceding the interest rate adjustment date. The pollution control notes bear interest at the same rate as the Revenue Bonds. On the interest rate adjustment date and annually thereafter (every three years thereafter in the case of the Revenue Bonds due July 1, 2026), the interest rate will be adjusted, not to exceed a rate of 15%, or at the option of the Company, subject to certain conditions, a fixed rate of interest, not to exceed 18%, may become effective. In the case of the Revenue Bonds due July 1, 2026, at the option of the Company, subject to certain conditions, a fixed rate of interest may become effective prior to the interest rate adjustment date or each third year thereafter. Bond owners may elect, subject to certain conditions, to have their Revenue Bonds purchased by the Trustee.
The Company has irrevocable letters of credit which expire on the letter of credit expiration dates and which the Company anticipates being able to extend if the interest rate on the related Revenue Bonds is not converted to a fixed interest rate. Those letters of credit support certain payments required to be made on the Revenue Bonds. If the Company is unable to extend the letter of credit that is related to a particular series of Revenue Bonds, that series will have to be redeemed unless a fixed rate of interest becomes effective. Payments made under the letters of credit in connection with purchases of Revenue Bonds by the Trustee are repaid with the proceeds from the remarketing of the Revenue Bonds. To the extent the proceeds are not sufficient, the Company is required to reimburse the bank that issued the letter of credit.
4 Preferred Stock
At December 31, 1993 and 1992, serial cumulative preferred stock was:
Shares Par Value Authorized Per Redeemable and Amount Series Share Prior to Per Share Outstanding(1) 1993 1992 (Thousands) Redeemable solely at the option of the Company: 3.75% $100 $104.00 150,000 $ 15,000 $ 15,000 4 1/2%(1949) 100 103.75 40,000 4,000 4,000 4.15% 100 101.00 40,000 4,000 4,000 4.40% 100 102.00 75,000 7,500 7,500 4.15% (1954) 100 102.00 50,000 5,000 5,000 6.48% 100 102.00 300,000 30,000 30,000 8.80% (2) 100 102.00 250,000 25,000 25,000 8.48% (3) 25 25.70 1,000,000 25,000 25,000 7.40% (4) 25 12/1/98 26.85 1,000,000 25,000 - Thereafter 25.00 Adjustable Rate (5) 25 25.00 1,800,000 45,000 45,000 Adjustable Rate (6) 25 12/1/98 27.50 2,000,000 50,000 - Thereafter 25.00 ---------- ---------- 235,500 160,500 Less: preferred stock redemptions within one year - included in current liabilities 95,000 - ---------- ---------- Total $ 140,500 $ 160,500 ========== ==========
Subject to mandatory redemption requirements: 9.00% (7) 100 - $ - $ 8,550 6.30% (8) 100 1/1/95 105.67 250,000 25,000 - 8.95% (9) 25 1/1/95 26.79 4,000,000 100,000 100,000 ---------- ---------- 125,000 108,550 Less: sinking fund requirements at par value - included in current liabilities - 1,650 ---------- ---------- Total $ 125,000 $ 106,900 ========== ==========
At December 31, 1993, preferred stock redemptions and annual redeemable preferred stock sinking fund requirements for the next five years are:
1994 1995 1996 1997 1998 (Thousands) $95,000 $ - $ - $5,000 $5,000
(1) At December 31, 1993, and after giving effect to the redemptions referred to in (2), (3), and (5) below, there were 1,550,000 shares of $100 par value preferred stock, 3,800,000 shares of $25 par value preferred stock and 1,000,000 shares of $100 par value preference stock authorized but unissued.
(2) Redeemed January 18, 1994.
(3) Redeemed February 1, 1994.
(4) The Company is restricted in its ability to redeem this Series prior to December 1, 1998.
(5) The Adjustable Rate Serial Preferred Stock, Series A, was redeemed January 10, 1994.
(6) The payment on the Adjustable Rate Serial Preferred Stock, Series B, for April 1, 1994, is at an annual rate of 5.12% and subsequent payments can vary from an annual rate of 4% to 10%, based on a formula included in the Company's Certificate of Incorporation. The Company is restricted in its ability to redeem this Series prior to December 1, 1998.
(7) On October 1, 1993, 33,000 shares were redeemed at par. The remaining 52,500 shares were redeemed at $100.50 per share on October 13, 1993. For the years 1991 and 1992, 16,500 shares were redeemed and cancelled annually.
(8) On January 1, in each year 2004 through 2008, the Company must redeem 12,500 shares at par, and on January 1, 2009, the Company must redeem the balance of the shares at par. This Series is redeemable at the option of the Company at $105.67 per share prior to January 1, 1995. The $105.67 price will be reduced annually by 63 cents for the years ending 1995 through 2002; thereafter, the redemption price is $100.00. The Company is restricted in its ability to redeem this Series prior to January 1, 2004.
(9) On January 1, in each year 1997 through 2016, the Company must redeem 200,000 shares at par. This Series is redeemable at the option of the Company at $26.79 per share prior to January 1, 1995. The $26.79 price will be reduced annually by 15 cents for
the years ending 1995 through 1999; by 14 cents for the year ending 2000; and by 15 cents for the years ending 2001 through 2005. The Company is restricted in its ability to redeem this Series prior to January 1, 1996.
5 Bank Loans and Other Borrowings
The Company has a revolving credit agreement with certain banks which provides for borrowing up to $200 million to July 31, 1997. At the option of the Company, the interest rate on borrowings is related to the prime rate, the London Interbank Offered Rate (LIBOR) or the interest rate applicable to certain certificates of deposit. The agreement also provides for the payment of a commitment fee which can fluctuate from .15% to .375% depending upon the ratings of the Company's first mortgage bonds. The commitment fee at December 31, 1993 is .1875%.
The Company had an outstanding loan of $50 million under the revolving credit agreement at December 31, 1993, at an interest rate of 4.06% under the LIBOR option, and did not have any outstanding loans under this agreement at December 31, 1992. The revolving credit agreement does not require compensating balances.
In order to provide flexibility in the timing and amounts of long-term financings, the Company uses interim financing in the form of short-term unsecured notes, usually commercial paper, to finance certain refundings and construction expenditures, and for other corporate purposes.
Information relative to short-term borrowings is as follows:
Commercial Paper 1993 1992 1991 (Thousands)
Ending balance $50,200 $64,100 $103,900 Maximum amount outstanding $95,400 $140,000 $111,000 Average amount outstanding (1) $56,300 $31,400 $66,700 Weighted average interest rate On ending balance 3.5% 4.0% 5.3% During the period (2) 3.4% 4.3% 6.2%
(1) Calculated as the average of the sum of daily outstanding borrowings.
(2) Calculated by dividing total interest expense by the average of the sum of daily outstanding borrowings.
6 Restructuring
In the fourth quarter of 1993, the Company recorded a $26 million restructuring charge. The corporate restructuring will reorganize the way the Company delivers services to its electric and natural gas customers beginning in March 1994. The restructuring reduced 1993 earnings available for common stock by approximately $17.2 million or 25 cents per share. Included in this amount are $13.2 million for a voluntary early retirement program, $3.2 million for an involuntary severance program, and $.8 million for the elimination and closing of electric and natural gas operations facilities statewide. During 1994, the restructuring resulted in a work force reduction throughout the organization of approximately 600, the elimination of customer walk-in services at 28 satellite locations, and the closing of up to 10 electric and natural gas operations facilities statewide. The work force reduction was accomplished through a voluntary early retirement program (See Note 7 - Retirement Benefits) and an involuntary severance program. 384 employees accepted the early retirement program.
7 Retirement Benefits
Pensions
The Company has a noncontributory retirement annuity plan that covers substantially all employees. Benefits are based principally on the employee's length of service and compensation for the five highest paid years out of the last 10 years of service. It is the Company's policy to fund pension costs accrued each year to the extent deductible for federal income tax purposes.
The net pension benefit for 1993, 1992, and 1991 totaled $5.7 million, $1.5 million, and $2.9 million, respectively.
Effective January 1, 1993, the retirement benefit plans for hourly and salaried employees were combined into one plan. Combining the two plans did not affect benefit levels.
Net pension benefit for 1993, 1992, and 1991 included the following components:
1993 1992 1991 (Thousands) Service cost: Benefits earned during the year $ 17,688 $ 15,387 $ 13,252 Interest cost on projected benefit obligation 40,710 35,253 32,096 Actual return on plan assets (77,129) (60,020) (111,749) Net amortization and deferral 12,989 7,844 63,487 ------- -------- -------- Net pension (benefit) $ (5,742) $ (1,536) $ (2,914) ======= ======== ========
The funded status of the plans at December 31, 1993 and 1992 were: 1993 1992 (Thousands) Actuarial present value of accumulated benefit obligation:
Vested $390,716 $287,504 Nonvested 55,476 42,286 -------- -------- Total 446,192 329,790 ======== ========
Fair value of plan assets $753,292 $701,893 Actuarial present value of projected benefit obligation (608,216) (480,429) -------- -------- Plan assets in excess of projected benefit obligation 145,076 221,464 Unrecognized net transition asset (73,612) (80,850) Unrecognized net (gain) loss (83,709) (139,729) Unrecognized prior service cost 4,182 5,209 --------- -------- Net pension (liability) asset $(8,063) $ 6,094 ========= ========
Plan assets primarily consist of equity securities, corporate, U.S. agency, and Treasury bonds, and cash equivalents.
The projected benefit obligation was measured using an assumed discount rate of 7% for 1993 and 7.75% for 1992 and 1991, and a long-term rate of increase in future compensation levels of 5% for 1993 and 6% for 1992 and 1991. The net pension benefit was measured using an expected long-term rate of return on plan assets of 8% in 1993 and 7.5% in 1992 and 1991.
Early Retirement
As part of the corporate restructuring that was announced in the fourth quarter of 1993 (See Note 6 - Restructuring), the Company offered a voluntary early retirement program from December 1, 1993, through January 21, 1994, to employees who were 55 years and older and who had at least 10 years of service with the Company. The program included two provisions: an unreduced pension benefit for those eligible employees who were under 60 years old, and a monthly supplemental payment to "bridge" employees to age 62 when they can begin collecting Social Security benefits. 384 employees accepted the early retirement opportunity. In 1993, the Company recorded a $19.9 million expense for the early retirement program.
Postretirement Benefits Other Than Pensions
The Company has postretirement benefit plans, such as a comprehensive health insurance plan and a prescription drug plan, that provide certain benefits for retired employees and their dependents. Substantially all of the Company's employees who retire under the Company's pension plan may become eligible for those benefits at retirement. At December 31, 1993, 1992, and 1991, 1,996, 1,905, and 1,866 retirees and their dependents, respectively, were covered under these plans. The postretirement benefit plans are unfunded as of December 31, 1993. However, the Company is examining the cost-effectiveness of certain funding alternatives.
In January 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (SFAS 106), Employers' Accounting for Postretirement Benefits Other Than Pensions, which requires that the Company accrue a liability for estimated future postretirement benefits during an employee's working career rather than recognize an expense when benefits are paid. At the time of adoption, the actuarially determined accumulated postretirement benefit obligation (APBO) was $206.6 million. The Company elected to recognize the APBO over 20 years.
In September 1993, the PSC issued a Statement of Policy concerning the accounting and ratemaking treatment for pensions and postretirement benefits other than pensions (PSC Policy). The PSC Policy was effective January 1993, adopted SFAS 106 for accounting and ratemaking purposes, and complies with generally accepted accounting principles.
Postretirement benefits cost other than pensions that was recognized on the income statement for the twelve months ended December 31, 1993, 1992, and 1991, was $11.4 million, $5 million, and $4.4 million, respectively. The amount for 1993 represents the portion of SFAS 106 costs that the Company has been allowed to collect from its customers. The amounts for the twelve months
ended December 31, 1992 and 1991, represent the postretirement benefits cost as determined prior to the adoption of SFAS 106, when the cost was not recognized as an expense until the benefits were paid. The Company has deferred $10.1 million of SFAS 106 costs as of December 31, 1993. The Company expects to recover any deferred SFAS 106 amounts in accordance with the PSC Policy.
The PSC Policy allows various rate mechanisms, including the use of excess pension fund assets, such as Internal Revenue Service Code of 1986 Section 420 transfers, to temper the effect of SFAS 106 on rates. In 1993, the Company transferred approximately $5 million of its excess pension plan assets to cover most of the cost of retirees' health care for that year. As a result of this transfer, the Company recognized a decrease in its deferred SFAS 106 asset.
The estimated net postretirement benefits cost other than pensions for the 12 months ended December 31, 1993, includes the following components:
(Thousands)
Service cost: Benefits accumulated during the year $ 6,888 Interest cost on accumulated postretirement benefit obligation 16,304 Amortization of transition obligation over 20 years 10,330 Deferral for future recovery (22,095) --------- Net periodic postretirement benefits cost $ 11,427 ==========
The status of the plans for postretirements benefits other than pensions, as reflected in the Company's Consolidated Balance Sheets at December 31, 1993, is as follows: (Thousands) Accumulated postretirement benefit obligation (APBO): Retired employees $ 69,947 Fully eligible active plan participants 36,454 Other active plan employees 107,708 ---------- Total APBO 214,109 ---------- Less unrecognized transition obligation 196,268 Less unrecognized net (gain) (10,233) ---------- Accrued postretirement liability $ 28,074 ==========
A 12% annual rate of increase in the per capita costs of covered health care benefits was assumed for 1994, gradually decreasing to 5% by the year 2003. Increasing the assumed health care cost trend rates by 1% in each year would increase the APBO as of January 1, 1994, by $41.5 million and increase the aggregate of the service cost and interest cost components of the net postretirement benefits cost for 1994 by $4.6 million. A discount rate of 7% was used to determine the APBO.
8 Jointly-Owned Generating Stations
Nine Mile Point Unit 2
The Company has an undivided 18% interest in the output and costs of the Nine Mile Point nuclear generating unit No. 2 (NMP2), which is being operated by Niagara Mohawk Power Corporation (Niagara Mohawk). Ownership of NMP2 is shared with Niagara Mohawk 41%, Long Island Lighting Company 18%, Rochester Gas and Electric Corporation 14%, and Central Hudson Gas & Electric Corporation 9%. The Company's share of the rated capability is 189,000 kilowatts. The Company's net utility plant investment, excluding nuclear fuel, was approximately $652 million and $660 million, at December 31, 1993 and 1992, respectively. The accumulated provision for depreciation was approximately $103 million and $90 million, at December 31, 1993 and 1992, respectively. The Company's share of operating expenses is included in the Consolidated Statements of Income.
A low level radioactive waste management and contingency plan that has been developed for NMP2 provides assurance that NMP2 is properly prepared to handle interim storage of low level radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of Energy (DOE) for disposal of high level radioactive waste (spent fuel) from NMP2. The Company is reimbursing Niagara Mohawk for its 18% share of the cost under the contract (currently approximately $1 per megawatt hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository has slipped from 2003 to no sooner than 2010. The Company has been advised by Niagara Mohawk that the NMP2 Spent Fuel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, the recent development of pre-licensed dry storage facilities for use at any nuclear power plant extends the on-site storage capability for spent fuel at NMP2 beyond 2014.
Nuclear Insurance
Niagara Mohawk maintains public liability and property insurance for NMP2. The Company reimburses Niagara Mohawk for its 18% share of those costs.
The public liability limit for a nuclear incident is approximately $8.8 billion. Should losses stemming from a nuclear incident exceed the commercially available public liability insurance, each licensee of a nuclear facility would be liable for up to a maximum of $75.5 million per incident, payable at a rate not to exceed $10 million per year. The Company's maximum liability for its 18% interest in NMP2 would be approximately $13.6 million per incident. The $75.5 million assessment is subject to periodic inflation indexing and a 5% surcharge should funds prove insufficient to pay claims associated with a nuclear incident. The Price-Anderson Act also requires indemnification for precautionary evacuations whether or not a nuclear incident actually occurs.
Niagara Mohawk maintains nuclear property insurance for NMP2 and is reimbursed by the Company for its 18% interest. Niagara Mohawk has procured property insurance aggregating approximately $2.7 billion through the Nuclear Insurance Pools and the Nuclear Electric Insurance Limited (NEIL). In addition, the Company has purchased NEIL insurance coverage for the extra expense incurred in purchasing replacement power during prolonged accidental outages. Under NEIL programs, should losses resulting from an incident at a member facility exceed the accumulated reserves of NEIL, each member, including the Company, would be liable for its share of the deficiency. The Company's maximum liability under the property damage and replacement power coverages is approximately $2.3 million.
Nuclear Plant Decommissioning Costs
In May 1993, the Nuclear Regulatory Commission (NRC) updated labor, energy, and burial cost factors for determining the minimum funding requirement for nuclear decommissioning. As a result, the Company's 18% share of the cost to decommission NMP2 is currently estimated to be $234 million in 2027, when decommissioning is expected to commence ($74 million in 1993 dollars).
The Company's annual decommissioning allowance currently included in electric rates is approximately $1.6 million and is sufficient to recover the minimum funding requirement. The Company believes that any increase in decommissioning costs will ultimately be recovered in rates.
The Company has established a Qualified Fund under applicable provisions of the federal tax law. The fund also
complies with the NRC regulations which require the use of an external trust fund to provide funds to decommission the contaminated portion of NMP2. The balance in this fund was approximately $5.7 million and $3.9 million at December 31, 1993 and 1992, respectively, and is included in other property and investments on the Consolidated Balance Sheets.
Homer City
The Company has an undivided 50% interest in the output and costs of the Homer City Generating Station, which is comprised of three generating units. The station is owned with Pennsylvania Electric Company, which operates the facility. The Company's share of the rated capability is 954,000 kilowatts and its net utility plant investment was approximately $258 million and $251 million at December 31, 1993 and 1992, respectively. The accumulated provision for depreciation was approximately $159 million and $148 million, at December 31, 1993 and 1992, respectively. The Company's share of operating expenses is included in the Consolidated Statements of Income.
9 Commitments and Contingencies
Capital Expenditures
The Company has substantial commitments in connection with its construction program and estimates that capital expenditures for 1994, 1995, and 1996 will approximate $210 million, $200 million, and $200 million, respectively. These forecasted levels have been significantly reduced as the Company is taking action to address competition. The program is subject to periodic review and revision, and actual construction costs may vary because of revised load estimates, imposition of additional regulatory requirements, and the availability and cost of capital.
Environmental Matters
The Company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Compliance programs will increase the cost of electric and natural gas service by requiring changes to the Company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred for compliance with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the Company may also incur costs from the past disposal of hazardous substances produced during the Company's operations or those of its predecessors. The Company has been notified by the U. S. Environmental Protection Agency (EPA) and the New York
State Department of Environmental Conservation (NYSDEC) that the Company is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at seven waste sites, not including the Company's inactive gas manufacturing sites, which are discussed below. With respect to the seven sites, five sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry).
Any liability may be joint and several for certain of these sites. The ultimate cost to remediate these sites will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the Company. At December 31, 1993, the Company recorded a liability in the Consolidated Balance Sheets related to four of these seven sites of $1.8 million. The Company has notified the NYSDEC that it believes it has no responsibility at two sites and has already incurred expenditures related to the remediation at the remaining site. A deferred asset has also been recorded in the amount of $2.6 million, of which $.8 million relates to costs that have already been incurred. The Company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the Company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites. This $1.8 million estimate was derived by multiplying the total estimated cost to clean up a particular site by the related Company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the Company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the Company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the Company's inactive gas manufacturing sites have been listed in the New York State Registry. The Company has filed petitions to delist the majority of the sites. The Company's program to investigate and initiate remediation at its 38 known inactive gas manufacturing sites has been extended through the year 2000. Expenditures over this time period are estimated to be $25 million. This estimate was determined by
using the Company's experience and knowledge related to these sites as a result of the investigation and remediation that the Company has performed to date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability, to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites, is reflected in the Company's Consolidated Balance Sheets at December 31, 1993 and 1992. The Company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the Company has previously been allowed by the PSC to recover such costs in rates. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in significant expenditures of approximately $178 million, on a present value basis, over a 25 year period, for all capital and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the Company's coal-fired generating stations of which $51 million has been incurred as of December 31, 1993. The Company's current estimate is a significant reduction from its prior estimate, primarily due to the postponement of the construction of a flue gas desulfurization (FGD) system at the Homer City Generating Station. The Company plans to reevaluate the need to construct an FGD system at the Homer City Generating Station in 1995, since its present strategy to bank Phase I emissions allowances for use during Phase II, as discussed below, will allow the Company to meet Phase II allowance requirements through the year 2005. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative FGD system and a nitrogen oxide reduction system expected to be completed in 1995 at the Company's Milliken Generating Station. The Company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (begins January 1, 1995) and Phase II (begins January 1, 2000). As a result of the 1990 Amendments, the Company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the Company to meet the sulfur dioxide levels established for the Company, which is approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time. Regulations may be adopted at the state level which would limit toxic emissions even further, at an additional cost to the Company. The Company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual emissions allowances to each of the Company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the Company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The Company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the Company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the Company by the EPA, the Company will receive a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers, as a result of the pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the Company will incur approximately $24 million, on a present value basis, of additional costs over the next 30 years, beginning in 1994, at the Homer City Generating Station. These costs will be incurred to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The Company expects to recover these expenditures in rates, since the Company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Long-term Power Purchase Contracts
The Company has on line and under contract 362 megawatts (mw) of non-utility generation (NUG) power. In addition, another 240 mw of NUG power is under construction. The Company is required to make payments under these contracts only for the power it receives. During 1993, 1992, and 1991 the Company purchased approximately $138 million, $71 million, and $30 million, respectively, of NUG power. The Company estimates that it will purchase approximately $255 million, $291 million, and $335 million of NUG power for the years 1994, 1995, and 1996, respectively. Increases in NUG power purchase costs are expected to be a significant contributor to price increases over the next three years.
As part of the Company's continuing effort to minimize future price increases associated with uneconomical power purchases from NUGs, the Company negotiated termination of
agreements for the South Corning and Indeck-Kirkwood cogeneration projects. The PSC approved full recovery of the $11.5 million in termination costs for the Indeck-Kirkwood project in rates. The Company expects to recover the $34 million in termination costs for the South Corning project in rates because the PSC issued an order in 1993 allowing the Company to defer these costs and the Company has been allowed by the PSC to recover costs for the Indeck-Kirkwood project in rates.
Coal Purchasing Contracts
The Company has long-term contracts with nonaffiliated mining companies for the purchase of coal for the jointly-owned Homer City Generating Station. The contracts, which expire between 1994 and the end of the expected service life of the generating station, require the purchase of either fixed or minimum amounts of the station's coal requirements. The price of the coal under one of these contracts is based on recovery of production costs plus incentives. The remaining contracts are based on fixed price plus escalation provisions. The Company's share of the cost of coal purchased under these agreements is expected to aggregate $66 million, $45 million, and $31 million for the years 1994, 1995, and 1996, respectively.
In addition, the Company has a long-term contract for the purchase of coal for the Kintigh Generating Station. The contract, which expires in 1997, supplies the annual coal requirements of the station. One-third of the tonnage price is renegotiated annually to reflect market conditions. The delivered cost of coal purchased under this agreement is expected to be $56 million, $55 million, and $56 million for the years 1994, 1995, and 1996, respectively.
10 Fair Value of Financial Instruments
The estimated fair values of the Company's financial instruments at December 31, 1993 and 1992, were as follows:
Carrying Amount Fair Value 1993 1992 1993 1992 (Thousands) First mortgage bonds $1,166,779 $1,318,845 $1,274,883 $1,388,990 Pollution control notes $575,695 $505,680 $581,928 $523,251 Preferred stock subject to mandatory redemption requirements $125,000 $108,550 $134,000 $119,031
The carrying amount for the following items approximates estimated fair value because of the short maturity of those instruments: cash and cash equivalents, commercial paper, and interest accrued.
Special deposits include restricted funds that are set aside for preferred stock and long-term debt redemptions. Special deposits also include restricted funds that are used to finance a portion of the costs incurred in the construction of certain solid waste disposal and other related facilities. The carrying amount approximates fair value because the special deposits have been invested in securities with a short-term maturity.
The carrying amount of the revolving credit agreement note approximates fair value because its pricing is based on short- term interest rates.
The fair value of the Company's first mortgage bonds, pollution control notes, and preferred stock is estimated based on the quoted market prices for the same or similar issues of the same remaining maturities.
11 Industry Segment Information
Certain information pertaining to the electric and natural gas operations of the Company is:
1993 1992 1991 Natural Natural Natural Electric Gas Electric Gas Electric Gas (Thousands) Operating Revenues $1,527,362 $272,787 $1,451,525 $240,164 $1,367,936 $187,879 Expenses $1,250,000 $249,493 $1,146,619 $221,307 $1,056,969 $177,751 Income $277,362 $23,294 $304,906 $18,857 $310,967 $10,128 Depreciation and amortization* $155,231 $9,337 $150,549 $8,428 $145,700 $6,680 Construction expenditures $208,576 $36,453 $210,185 $35,433 $210,127 $35,756 Identifiable assets** $4,615,963 $458,596 $4,540,724 $377,424 $4,515,237 $340,090
* Included in operating expenses. ** Assets used in both electric and natural gas operations not included above were $201,457, $159,768, and $69,509 at December 31, 1993, 1992, and 1991, respectively. They consist primarily of cash and cash equivalents, special deposits, and prepayments.
12 Supplementary Income Statement Information
Charges for maintenance, repairs, and depreciation and amortization, are set forth in the Consolidated Statements of Income. Taxes, other than federal income taxes, are:
1993 1992 1991 (Thousands)
Property $84,616 $81,640 $76,589 Franchise and gross receipts 92,810 92,153 76,721 Payroll 17,985 17,096 15,467 Miscellaneous 9,551 10,052 9,408 -------- -------- -------- Total Other Taxes $204,962 $200,941 $178,185 ======== ======== ========
13 Quarterly Financial Information (Unaudited)
Quarter ended March 31 June 30 Sept. 30 Dec. 31 (Thousands, Except Per Share Amounts) Operating revenues $522,383 $388,601 $396,410 $492,755 Operating income $109,893 $56,649 $66,108 $68,006 Net income $74,039 $21,500 $32,541 $37,948 (1) Earnings for common stock $68,838 $16,299 $27,340 $32,913 Earnings per share $.99 $.23 $.39 $.47 (1) Dividends per share $.54 $.54 $.55 $.55 Average shares outstanding 69,561 69,836 70,119 70,431 Common stock price* High $35.13 $36.50 $36.25 $35.50 Low $31.63 $32.13 $34.63 $28.75 Operating revenues $489,847 $401,934 $367,833 $432,075 Operating income $111,373 $82,755 $60,109 $69,526 Net income $76,416 $46,772 $26,581 $34,199 Earnings for common stock $71,167 $41,488 $21,320 $28,998 Earnings per share $1.10 (2) $.60 (2) $.31 (2) $.42 (2) Dividends per share $.53 $.53 $.54 $.54 Average shares outstanding 64,682 68,800 69,063 69,318 Common stock price* High $29.63 $29.38 $32.00 $32.75 Low $26.13 $26.75 $29.25 $30.38
(1) Fourth quarter 1993 results reflect the effects of restructuring expenses, which decreased net income and earnings for common stock by $17.2 million and decreased earnings per share by 24 cents. (2) Late in 1992, the Company began reflecting on its income statement the value of energy consumed but not yet billed. If the Company had been allowed by the PSC to include this unbilled revenue factor during all of 1992, quarterly earnings per share in 1992 would have been 94 cents, 39 cents, 38 cents, and 72 cents for the first, second, third, and fourth quarters, respectively. * The Company's common stock is listed on the New York Stock Exchange. The number of stockholders of record at December 31, 1993 was 58,990.
Dividend Limitations: After dividends on all outstanding preferred stock have been paid, or declared, and funds set apart for their payment, the common stock is entitled to cash dividends as may be declared by the Board of Directors out of retained earnings accumulated since December 31, 1946. Common Stock dividends are limited if Common Stock Equity (45% at December 31, 1993) falls below 25% of total capitalization, as defined in the Company's Certificate of Incorporation. Dividends on common stock cannot be paid unless sinking fund requirements of the preferred stock are met. The Company has not been restricted in the payment of dividends on common stock by these provisions. Retained earnings accumulated since December 31, 1946, were approximately $320 million and $327 million as of December 31, 1993 and 1992, respectively.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors New York State Electric & Gas Corporation and Subsidiaries Ithaca, New York
We have audited the consolidated financial statements and the financial statement schedules of New York State Electric & Gas Corporation and Subsidiaries listed in Item 14(a) of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of New York State Electric & Gas Corporation and Subsidiaries as of December 31, 1993 and 1992, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As discussed in Note 7 to the consolidated financial statements, the Company and Subsidiaries changed its method of accounting for postretirement benefits other than pensions in 1993.
COOPERS & LYBRAND
New York, New York January 28, 1994
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
Incorporated herein by reference to the information under the caption "Election of Directors" in the Company's Proxy Statement dated March 31, 1994. The information regarding executive officers is on pages 23-25 of this report.
Item 11.

Item 11. Executive compensation
Incorporated herein by reference to the information under the captions "Executive Compensation," "Employment and Change in Control Arrangements," "Directors' Compensation," "Compensation Committee Interlocks and Insider Participation," "Report of Executive Compensation and Succession Committee on Executive Compensation" and "Stock Performance Graph" in the Company's Proxy Statement dated March 31, 1994.
Item 12.

Item 12. Security ownership of certain beneficial owners and management
Incorporated herein by reference to the information under the caption "Security Ownership of Certain Beneficial Owners and Management" in the Company's Proxy Statement dated March 31, 1994.
Item 13.

Item 13. Certain relationships and related transactions
Incorporated herein by reference to the information under the captions "Election of Directors" and "Employment and Change in Control Arrangements" in the Company's Proxy Statement dated March 31, 1994.
PART IV
Item 14.

Item 14. Exhibits, financial statement schedules, and reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial statements Included in Part II of this report: a) Consolidated Statements of Income for the three years ended December 31, 1993 b) Consolidated Balance Sheets as of December 31, 1993 and 1992 c) For the three years ended December 31, 1993: Consolidated Statements of Cash Flows Consolidated Statements of Changes in Common Stock Equity d) Notes to Consolidated Financial Statements e) Report of Independent Accountants 2. Financial statement schedules Included in Part II of this report: For the three years ended December 31, 1993: V. Property, Plant and Equipment VI. Accumulated Depreciation of Property, Plant and Equipment VIII. Allowance for Doubtful Accounts - Accounts Receivable
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Consolidated Financial Statements or notes thereto.
3. Exhibits (a)(1) The following exhibits are delivered with this report:
Exhibit No. 3-11 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993. 3-12 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. 3-13 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. 3-15 - By-Laws of the Company as amended February 25, 1994. 10-14 - Coal Sales Agreement dated December 21, 1983 between New York State Electric & Gas Corporation and Consolidation Coal Company. (A) 10-21 - Retirement Plan for Directors Amendment No. 1. (A) 10-23 - Deferred Compensation Plan for Directors Amendment No. 1. (A) 10-32 - Supplemental Executive Retirement Plan Amendment No. 8. (A) 10-33 - Supplemental Executive Retirement Plan Amendment No. 9. (A) 10-35 - Annual Executive Incentive Compensation Plan Amendment No. 1. (A) 10-36 - Annual Executive Incentive Compensation Plan Amendment No. 2. (A) 10-41 - Performance Share Plan Amendment No. 4. (A) 10-43 - Performance Share Deferred Compensation Plan Amendment No. 1. (A) 10-46 - Employment Agreement for J. A. Carrigg. (A) 10-47 - Form of Severance Agreement for Senior Vice Presidents. (A) 10-48 - Form of Severance Agreement for Vice Presidents. 12 - Computation of Ratio of Earnings to Fixed Charges. 21 - Subsidiaries. 23 - Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 99-1 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.
(a)(2) The following exhibits are incorporated herein by reference: Exhibit No. Filed in As Exhibit No. 3-1 - Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988 - Registration No. 33-50719 . . . 4-11 3-2 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989 - Registration No. 33-50719 . . 4-12 3-3 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990 - Registration No. 33-50719 . . . . . . . . . . . . . 4-13 3-4 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990 - Registration No. 33-50719 . . 4-14 ______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
3-5 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991 - Registration No. 33-50719 . . 4-15 3-6 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991 - Registration No. 33-50719 . . 4-16 3-7 - Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991 - Registration No. 33-50719 . . . . . . . . . . . . . . . . . . . 4-20 3-8 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992 - Registration No. 33-50719 . . . . 4-17 3-9 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992 - Registration No. 33-50719 . . . 4-18 3-10 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993 Registration No. 33-50719 . . . . . . . . . . . . . . 4-19 3-14 - Certificates of the Secretary of the Company concern- ing consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness - Registration No. 2-69988. . . . . . . . . . . . . . 4-7 4-1 - First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee) - Registration No. 33-4186 . . . 4-1
Supplemental Indentures to First Mortgage dated as of July 1, 1921: 4-2 - No. 37 - Registration No. 33-31297. . . . . . . . . 4-2 4-3 - No. 39 - Registration No. 33-31297. . . . . . . . . 4-3 4-4 - No. 43 - Registration No. 33-31297. . . . . . . . . 4-4 4-5 - No. 51 - Registration No. 2-59840 . . . . . . . . . 2-B(46) 4-6 - No. 68 - Registration No. 2-59840 . . . . . . . . . 2-B(63) 4-7 - No. 69 - Registration No. 2-59840 . . . . . . . . . 2-B(64) 4-8 - No. 71 - Registration No. 2-59840 . . . . . . . . . 2-B(66) 4-9 - No. 74 - Registration No. 2-59840 . . . . . . . . . 2-B(69) 4-10 - No. 75 - Registration No. 2-59840 . . . . . . . . . 2-B(70) 4-11 - No. 80 - Registration No. 2-59840 . . . . . . . . . 2-B(75) 4-12 - No. 81 - Registration No. 2-59840 . . . . . . . . . 2-B(76) 4-13 - No. 83 - Registration No. 2-65948 . . . . . . . . . 2-B(78) 4-14 - No. 99 - Registration No. 33-11303. . . . . . . . . 4-9 4-15 - No. 102- Registration No. 33-33838. . . . . . . . . 4-8 4-16 - No. 103- Registration No. 33-43458. . . . . . . . . 4-8 4-17 - No. 104- Registration No. 33-43458. . . . . . . . . 4-9
4-18 - No. 105- Registration No. 33-52040. . . . . . . . . 4-8 4-19 - No. 106- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-23 4-20 - No. 107- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-24 4-21 - No. 108- Registration No. 33-50719. . . . . . . . . 4-8 4-22 - No. 109- Registration No. 33-50719. . . . . . . . . 4-9
Contracts, amendments, and letter agreement with the Power Authority of the State of New York: 10-1 - Contract UD-4 dated July 28, 1975 (FitzPatrick Power) - Registration No. 2-59840 . . . . . . . . . 5-5
Exhibit No. Filed in As Exhibit No.
10-2 - Contract PS-2 dated March 28, 1973 (Blenheim- Gilboa) - Registration No. 2-59840. . . . . . . . . 5-6 10-3 - Letter Agreement dated February 3, 1982 relating to transmission services - Registration No. 2-82192. . 10-1 10-4 - Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to trans- mission services - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . 10-4 10-5 - Contract effective as of February 22, 1989 relating to the purchase of hydroelectric power - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-5 10-6 - Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . 10-6 10-7 - Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Gener- ating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for the year ended December 31, 1989 File No. 1-3103-2. . . . . . . . . . . . . 10-7
Coal Sales Agreements and Amendments between New York State Electric & Gas Corporation, Pennsylvania Electric Company and: 10-8 - Helvetia Coal Company - Agreement made as of December 22, 1966 - Registration No. 2-59840. . . . 5-11 10-9 - Helvetia Coal Company - Amendment made as of April 1, 1974 - Registration No. 2-55131. . . . . . 5-F(1)b 10-10 - Amendment dated as of March 15, 1989 to the Coal Sales Agreement made as of December 22, 1966 between New York State Electric & Gas Corporation, Penn- sylvania Electric Company and Helvetia Coal Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . 10-10
10-11 - Amendment dated as of July 25, 1990 to the Coal Sales Agreement made as of December 22, 1966 between New York State Electric & Gas Corporation, Penn- sylvania Electric Company and Helvetia Coal Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . 10-11
* * * * * * * * * *
Exhibit No. Filed in As Exhibit No.
10-12 - New York Power Pool Agreement dated July 11, 1985 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-7 10-13 - Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-17 10-15 - Amendment No. 1 dated as of October 1, 1985 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-11 10-16 - Amendment No. 2 dated as of August 28, 1986 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-12 10-17 - Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2 - Registration No. 2-54903. . . 5-0 10-18 - Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others - Company's 10-K for the year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . 10-18 10-19 - Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation - Registration No. 2-82352. . . . . . . . . . . . . . 10 (A) 10-20 - Retirement Plan for Directors - Company's 10-K for the year ended December 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-26 (A) 10-22 - Form of Deferred Compensation Plan for Directors - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-22 (A) 10-24 - Supplemental Executive Retirement Plan - Company's 10-Q for quarter ended September 30, 1984 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-19 (A) 10-25 - Supplemental Executive Retirement Plan Amendment No. 1 - Company's 10-Q for quarter ended March 31, 1985 - File No. 1-3103-2. . . . . . . . . 10-21 ______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
(A) 10-26 - Supplemental Executive Retirement Plan Amendment No. 2 - Company's 10-K for year ended December 31, 1987 - File No. 1-3103-2. . . . . . . . . . . . 10-19 (A) 10-27 - Supplemental Executive Retirement Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . 10-24 (A) 10-28 - Supplemental Executive Retirement Plan Amendment No. 4 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-30 (A) 10-29 - Supplemental Executive Retirement Plan Amendment No. 5 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-31 (A) 10-30 - Supplemental Executive Retirement Plan Amendment No. 6 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2. . . . . . . . . . . . . . 10-37 (A) 10-31 - Supplemental Executive Retirement Plan Amendment No. 7 - Company's 10-Q for quarter ended June 30, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . 10-44 (A) 10-34 - Annual Executive Incentive Compensation Plan. Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-30 (A) 10-37 - Performance Share Plan - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . 10-36 (A) 10-38 - Performance Share Plan Amendment No. 1 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-38 (A) 10-39 - Performance Share Plan Amendment No. 2 - Company's 10-Q for quarter ended June 30, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-39 (A) 10-40 - Performance Share Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-34 (A) 10-42 - Performance Share Deferred Compensation Plan - Company's 10-K for year ended December 31, 1991 File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-40 (A) 10-44 - Employment Contract for A. E. Kintigh - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . 10-26 (A) 10-45 - Agreement with R. Fleming, Jr. - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . 10-34
The Company agrees to furnish to the Commission, upon request, a copy of the Revolving Credit Agreement dated as of July 31, 1992, between the Company, Chemical Bank, as Agent, and certain banks; a copy of the Participation Agreement dated as of February 1, 1984 between the Company and New York State Energy Research and Development Authority (NYSERDA) relating to Pollution Control Revenue Bonds; a copy of the Participation Agreements dated as of October 15, 1984, June 1, 1987 and December 1, 1988 between the Company and NYSERDA relating to Adjustable Rate Pollution Control Revenue Bonds (1984 Series A), (1987 Series A), and (1988 Series A), respectively; a copy of the Participation Agreements dated as of March 1, 1985, October 15, 1985, July 15, 1985 and December 1, 1985 between the Company and NYSERDA relating to Annual
______________________________ (A) Management contract or compensatory plan or arrangement.
Tender Pollution Control Revenue Bonds (1985 Series A), (1985 Series B), (1985 Series C) and (1985 Series D), respectively; a copy of the Participation Agreements dated as of February 1, 1993 and February 1, 1994 between the Company and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1994 Series A) and (1994 Series B) respectively; a copy of the Participation Agreement dated as of December 1, 1993 between the Company and NYSERDA relating to Solid Waste Disposal Revenue Bonds (1993 Series A); and a copy of the Credit Agreement dated as of March 9, 1983, as amended, between Somerset Railroad Corporation and Chemical Bank. The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
(b) Reports on Form 8-K
A report on Form 8-K, dated November 29, 1993, was filed during the fourth quarter of 1993 to report certain information under Item 5, "Other Events."
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.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Date: March 11, 1994 By Everett A. Robinson Everett A. Robinson Vice President and Controller (Chief Accounting 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.
PRINCIPAL EXECUTIVE OFFICER
Date: March 11, 1994 By James A. Carrigg James A. Carrigg Chairman, President, Chief Executive Officer and Director
PRINCIPAL FINANCIAL OFFICER
Date: March 11, 1994 By Sherwood J. Rafferty Sherwood J. Rafferty Vice President and Treasurer
PRINCIPAL ACCOUNTING OFFICER
Date: March 11, 1994 By Everett A. Robinson Everett A. Robinson Vice President and Controller
Signatures (Cont'd)
Date: March 11, 1994 By Alison P. Casarett Alison P. Casarett Director
Date: March 11, 1994 By Everett A. Gilmour Everett A. Gilmour Director
Date: March 11, 1994 By Paul L. Gioia Paul L. Gioia Director
Date: March 11, 1994 By John M. Keeler John M. Keeler Director
Date: March 11, 1994 By Allen E. Kintigh Allen E. Kintigh Director
Date: March 11, 1994 By Ben E. Lynch Ben E. Lynch Director
Date: March 11, 1994 By Alton G. Marshall Alton G. Marshall Director
Date: March 11, 1994 By David R. Newcomb David R. Newcomb Director
Date: March 11, 1994 By Robert A. Plane Robert A. Plane Director
Date: March 11, 1994 By C. William Stuart C. William Stuart Director
EXHIBIT INDEX
* 3-1 -- Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988. * 3-2 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989. * 3-3 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990. * 3-4 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990. * 3-5 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991. * 3-6 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991. * 3-7 -- Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991. * 3-8 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992. * 3-9 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992. * 3-10 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993. 3-11 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993. 3-12 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
3-13 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. * 3-14 -- Certificates of the Secretary of the Company concerning consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness. 3-15 -- By-Laws of the Company as amended February 25, 1994. * 4-1 -- First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee).
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
* 4-2 -- No. 37 * 4-9 -- No. 74 * 4-16 -- No. 103 * 4-3 -- No. 39 * 4-10 -- No. 75 * 4-17 -- No. 104 * 4-4 -- No. 43 * 4-11 -- No. 80 * 4-18 -- No. 105 * 4-5 -- No. 51 * 4-12 -- No. 81 * 4-19 -- No. 106 * 4-6 -- No. 68 * 4-13 -- No. 83 * 4-20 -- No. 107 * 4-7 -- No. 69 * 4-14 -- No. 99 * 4-21 -- No. 108 * 4-8 -- No. 71 * 4-15 -- No. 102 * 4-22 -- No. 109
Contracts, Amendments, and Letter Agreement with the Power Authority of the State of New York:
* 10-1 -- Contract UD-4 dated July 28, 1975 (FitzPatrick Power). * 10-2 -- Contract PS-2 dated March 28, 1973 (Blenheim- Gilboa). * 10-3 -- Letter Agreement dated February 3, 1982 relating to transmission services. * 10-4 -- Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to transmission services. * 10-5 -- Contract effective as of February 22, 1989 relating to the purchase of hydroelectric power. * 10-6 -- Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-7 -- Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
* * * * * * * * * *
Coal Sales Agreements and Amendments between New York State Electric & Gas Corporation, Pennsylvania Electric Company and:
* 10-8 -- Helvetia Coal Company--Agreement made as of December 22, 1966. * 10-9 -- Helvetia Coal Company--Amendment made as of April 1, 1974. * 10-10 -- Helvetia Coal Company--Amendment made as of March 15, 1989. * 10-11 -- Helvetia Coal Company--Amendment made as of July 25, 1990.
* * * * * * * * * *
* 10-12 -- New York Power Pool Agreement dated July 11, 1985. * 10-13 -- Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company.
* * * * * * * * * *
Coal Sales Agreement and Amendments between New York State Electric & Gas Corporation and Consolidation Coal Company:
10-14 -- Agreement dated December 21, 1983. * 10-15 -- Amendment No. 1 dated as of October 1, 1985. * 10-16 -- Amendment No. 2 dated as of August 28, 1986.
* * * * * * * * * *
* 10-17 -- Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2. * 10-18 -- Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-19 -- Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation. (A)* 10-20 -- Retirement Plan for Directors. (A) 10-21 -- Retirement Plan for Directors Amendment No. 1 (A)* 10-22 -- Form of Deferred Compensation Plan for Directors. (A) 10-23 -- Deferred Compensation Plan for Directors Amendment No. 1. (A)* 10-24 -- Supplemental Executive Retirement Plan (A)* 10-25 -- Supplemental Executive Retirement Plan Amendment No. 1. (A)* 10-26 -- Supplemental Executive Retirement Plan Amendment No. 2. (A)* 10-27 -- Supplemental Executive Retirement Plan Amendment No. 3. (A)* 10-28 -- Supplemental Executive Retirement Plan Amendment No. 4. (A)* 10-29 -- Supplemental Executive Retirement Plan Amendment No. 5. (A)* 10-30 -- Supplemental Executive Retirement Plan Amendment No. 6. (A)* 10-31 -- Supplemental Executive Retirement Plan Amendment No. 7. (A) 10-32 -- Supplemental Executive Retirement Plan Amendment No. 8. (A) 10-33 -- Supplemental Executive Retirement Plan Amendment No. 9. (A)* 10-34 -- Annual Executive Incentive Compensation Plan. (A) 10-35 -- Annual Executive Incentive Compensation Plan Amendment No. 1. (A) 10-36 -- Annual Executive Incentive Compensation Plan Amendment No. 2. (A)* 10-37 -- Performance Share Plan. (A)* 10-38 -- Performance Share Plan Amendment No. 1. (A)* 10-39 -- Performance Share Plan Amendment No. 2. (A)* 10-40 -- Performance Share Plan Amendment No. 3 (A) 10-41 -- Performance Share Plan Amendment No. 4 (A)* 10-42 -- Performance Share Deferred Compensation Plan. (A) 10-43 -- Performance Share Deferred Compensation Plan Amendment No. 1 (A)* 10-44 -- Employment Contract for A. E. Kintigh. (A)* 10-45 -- Agreement with R. Fleming, Jr. (A) 10-46 -- Employment Agreement for J. A. Carrigg. (A) 10-47 -- Form of Severance Agreement for Senior Vice Presidents. (A) 10-48 -- Form of Severance Agreement for Vice Presidents.
___________________________________ (A) Management contract or compenstory plan or arrangement. * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
12 -- Computation of Ratio of Earnings to Fixed Charges. 21 -- Subsidiaries. 23 -- Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 99-1 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.