Item 1. Business.
The Company, organized in 1937 under the laws of New York, is engaged principally in the business of production and/or purchase, transmission, distribution and sale of electricity and the purchase, distribution and sale of gas in New York State. The Company renders electric service to the public in an area of New York State having a total population of about 3,500,000, including, among others, the cities of Buffalo, Syracuse, Albany, Utica, Schenectady, Niagara Falls, Watertown and Troy. The Company distributes natural gas in areas of central, northern and eastern New York having a total population of about 1,700,000, nearly all within the Company's electric service area. A Canadian subsidiary owns an electric company with operations in the Province of Ontario, Canada. A Texas subsidiary has an interest in a uranium mining operation in Live Oak County, Texas which is now in the process of reclamation and restoration. A New York subsidiary owns, develops and operates cogeneration and small power plants. Another New York subsidiary engages in real estate development. Each of these subsidiaries is wholly-owned by the Company.
General. Until recently, the electric and gas utility industry operated in a relatively stable business environment, subject to traditional cost-of-service regulation. The investment community, both shareholders and creditors, considered utility securities to be of low risk and high quality. Regulators tended to protect the utility monopoly in exchange for the utility company's obligation to serve customers in its franchise. Such protection often encouraged regulators and other governmental bodies to use utilities as vehicles to advance social programs and as tax collectors. In general, utilities and regulators were inclined toward establishing a fair rate of return and away from particular price considerations or incentives for aggressive, long-term cost control. Cash flows were relatively more predictable, as was the industry's ability to sustain investment grade dividend payout and interest coverage ratios.
The emergence of competition has recently begun to erode the utility industry's monopoly position and the regulator's ability to wholly assure the industry's financial health. For example, the passage of the National Energy Policy Act of 1992 (NEPA) is resulting in a rapid increase in wholesale (a sale to another entity for resale to an end user) competition. NEPA eases the way for non-utility, unregulated generators to enter the marketplace and allows the Federal Energy Regulatory Commission (FERC) to require the utility owners of electricity transmission systems to transport power for wholesale transactions. The speed and extent of monopoly erosion will be dependent upon a number of company specific characteristics, including geographic location and electric system limitations, cost and price of services in relation to neighboring utilities, opportunity for alternative suppliers and fuels to compete, economic vitality of the service territory, policies of regulators and legislators and electric supply/demand balances.
Competition creates a focus on the price of utility services. As the potential for broad based competition grows, government mandated social programs, burdensome tax structures and other regulatory initiatives become cost elements that a market based pricing system will not necessarily support. For the Company, the most significant of these incumbent burdens is mandated payments to unregulated generators discussed below.
During the past several years, the Company's electric industrial rates have moved from being among the lowest in New York State and the Northeast to above the middle of the range. A key contributor to recent price increases has been the proliferation of unregulated generators, which are aided by federal and state statutes that provide guaranteed markets at rates in excess of the Company's internal cost of production. Such increases in rates are reaching a point where industrial customers have begun to weigh the benefits and costs of self generation against the retention of utility service. More importantly, industrial and commercial customers are also considering moving operations outside the Company's service territory. Loss of industrial and commercial customers places additional cost burdens on remaining customers. In response to this, the Company has begun a program to offer discounts to industrial customers that can demonstrate viable self-generation alternatives. The associated loss of jobs in the Company's service territory would also put further pressure on rates to remaining customers.
Although the timing and impact of competition is impossible to predict, the Company is already experiencing severe competition in the wholesale market, exacerbated by a capacity surplus of electricity in the Northeast region and Canada. The possibility of municipalization, whereby traditional customers form their own government sponsored supply company, may increase as prices increase. The Company is aware of at least one public debate on municipalization involving a city within its service territory.
Rating agencies and others following utility securities have recently observed an increase in business risk as a result of these and other factors. Standard & Poor's Corporation (S&P) revised its electric utility financial ratio benchmarks in late 1993 to reflect the greater business risk provided by accelerating competition. With respect to the Company, it also indicated concern about environmental and nuclear operating cost pressure and slow earnings growth prospects. S&P also segregated electric utility companies into groups based upon competitive position, business prospects and predictability of cash flows to withstand greater financial risks. The Company was included in the "Below Average," or lowest rated, group. Based on these criteria, on February 23, 1994, S&P reduced the Company's credit ratings to BBB- for secured debt and BB+ (below investment grade) for preferred stock, while maintaining a negative ratings outlook pending demonstrated financial improvement.
Moody's Investor's Services has also indicated that it expects utility bond ratings to come under increasing pressure over the next three to five years because of changes in the business environment, although in February 1994 it maintained its ratings of Baa2 on all existing secured debt, baa3 for preferred
stock and P-2 for commercial paper. See also Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations.
The Company is responding to these competitive threats through strategies developed in its Comprehensive Industry Restructuring and Competitiveness Assessment for the 2000's (CIRCA 2000), begun in 1993. Reducing the total cost of doing business and solving problems in the regulatory area as they relate to the Company were identified as critical factors in addressing the Company's business risk.
In early 1993, the Company announced its intent to reduce its workforce by at least 1,400 positions by the end of 1995. While considerable progress was made during 1993, the Company determined that further and faster workforce reductions were needed and announced a layoff, to occur in early 1994, of approximately 900 employees, while increasing total reductions to 1,500. Further reductions may be necessary.
The Company has also proposed a five year electric rate plan, described under "Regulation and Rates, Innovative Rate Plan Proposal," which would begin in 1995. The plan proposes a methodology that would cap rates at approximately the rate of inflation for each of the years 1996 through 1999, while providing greater pricing flexibility for Company pricing decisions within each rate class. The Company could, at its discretion, offer discounts to customers who might be able to leave the system, but would, in turn, be limited as to how much of the discount could be recovered from other customers.
The emphasis on cost control and pricing flexibility is designed to position the Company to meet the challenges of competition. However, the competitive threats within the Company's markets increase the level of risk to be managed, as evidenced by the developments discussed in this document and no assurance can be provided that the financial strength of the Company can be maintained or that its dividends and earnings will be as predictable as in prior years.
The following topics are discussed under the general heading of "Business". Where applicable, the discussions make reference to the various other items of this Form 10-K.
Topic Page
Regulation and Rates 6 Unregulated Generators 10 New York Power Authority 13 Purchased Power 14 Fuel for Electric Generation: Coal 14 Natural Gas 15 Residual Oil 15 Nuclear 16 Gas Supply 18 Industry Segment Data 19 Environmental Matters 19 Nuclear Operations 23 Construction Program 24 Electric Supply Planning 24 Electric Delivery Planning 25 Demand-Side Management Programs 26 Research and Development 27 Employee Relations 28 Liability Insurance 28
REGULATION AND RATES. In recent years the nature of rate regulation in New York State has trended toward negotiated ratemaking as opposed to fully litigated proceedings. Several negotiated agreements between the Company, the PSC Staff and other intervenors have had a positive effect on the Company's financial condition and results of operations. For a discussion of these negotiated agreements, including key rat mechanisms such as the Niagara Mohawk electric adjustment mechanism (NERAM) and the measured equity return incentive term (MERIT), see Item 7 -- Management's Discussion And Analysis Of Financial Condition And Results Of Operations.
Under the terms of its 1994 Rate Agreement, the Company is required to file a "competitiveness" study with the PSC by April 1, 1994. The filing will address, among other things, the breadth of potential competitive forces facing the Company, the economics of the Company's electricity supply, the potential financial effects of increasing competition and possible methods for dealing with the transition costs that would arise from expanding competition.
Rates Responding to Economic Development and Competitive Threats. The Company is experiencing a loss of industrial load through bypass across its system. Several substantial industrial customers, constituting approximately 85 MW of demand, have chosen to purchase generation from other sources, either from newly constructed facilities or under circumstances where they directly use the power they had been generating and selling to the Company under power purchase contracts mandated by PURPA and New York laws and PSC programs.
As a first step in addressing the threat of a loss of industrial load, the PSC in 1993 approved a new rate (referred to as SC-10) under which the Company is allowed to negotiate
individual contracts with some of its largest industrial and commercial customers to provide them with electricity at lower prices. Under the new rate, customers must demonstrate that leaving the Company's system through the use of on-site generation is an economically viable alternative. At March 1, 1994, the Company estimates that as many as 75 of its 235 largest customers may be inclined to bypass the its system by making electricity on their own unless they receive price discounts. These would cost about $20 million per year, while losing those 75 customers would reduce net revenues by an estimated $80 million per year. The amount of estimated discounts to be offered has been reduced from previous estimates due to more detailed information becoming available on specific customer sites. The decreases are also a result of customers entering SC-10 negotiations and then choosing to participate in economic development incentive programs (discussed below) instead of the SC-10 tariff rate. As of March 1, 1994, the Company has offered annual SC-10 discounts totaling $9.7 million, of which $4.6 million have been accepted. The Company estimates that by the end of 1994 there may be as many as 50 customers subscribing to the rate with a lost margin projection in 1994 of $15 million ($3 million shareholder exposure).
In addition to the SC-10 tariff, the Company has four electric rate incentive programs. These programs are designed to make upstate New York more attractive for business relocation and expansion, and to provide assistance to distressed businesses already located there. These incentive programs are:
- Economic Development Rider: discounted electric rates for new or added load;
- Economic Development Zone Rider: discounted electric rates for new or added load in a state designated economically distressed area;
- Economic Revitalization Incentive Rider: discounted electric rates for existing loads, when customer qualifies as economically and financially distressed. As a result of the 1994 Electric Settlement Agreement, this program was expanded and the total cap on annual discounts was raised from $5 million to $15 million. The Agreement calls for the cost of discounts to be shared between ratepayer and shareholder as follows: 1) discounts of up to $5 million will be passed on to ratepayers, 2) between $5 million and $15 million the costs will be shared 80% ratepayer and 20% shareholder and 3) discounts over $15 million will be borne by Company shareholders; and
- Economic Development Power Rider: delivery of low-cost electricity generated by the New York Power Authority for expansion or revitalization purposes.
The Company has also joined with other investor-owned gas and electric and telecommunication companies and New York State in an "Alliance for a New, New York (ANNY)." ANNY has committed $5.0 million a year in this five-year program to attract and
retain jobs on a Statewide basis. This commitment is incremental to the participants' existing economic development efforts.
In March 1993, the PSC began an ongoing investigation to explore fundamental issues about future competition in the electric and gas industries. Most recently, this investigation has focused on the narrow issue of opportunities of large customers to by-pass the electric system and the extent to which flexible rates can prevent such by-pass. The Company's position in this proceeding has been to support the rate flexibility necessary to respond to competitive conditions in the industry.
Innovative rate plan proposal. Although the rate programs and agreements discussed above have had a positive effect on the Company's financial condition and results of operations, the focus of these actions is too limited to address the broader risks of competition. Because of this, the Company determined that a much more flexible regulatory framework is needed to respond to a diversity of competitive threats. On February 4, 1994, the Company made a combined electric and gas rate filing for rates to be effective January 1, 1995. The filing seeks a $250.7 million increase in electric base rates, which would be offset by a regulatory surcharge of $117.0 million, resulting in a net increase in electric revenues of $133.7 million (4.3%). Gas rates would increase $24.8 million (4.1%) and would include an extension of the weather normalization adjustment mechanism. The electric filing includes a proposal to institute a methodology to establish rates beginning in 1996 and running through 1999. The proposal would provide for rate indexing to a quarterly forecast of the consumer price index as adjusted for a productivity factor. The methodology sets a price cap, but the Company may elect not to raise its rates up to the cap. Such a decision would be based on the Company's assessment of the market. NERAM and certain expense deferral mechanisms (but not the amounts already deferred) would be eliminated, while the fuel adjustment clause would be modified to cap the Company's exposure to fuel and purchased power cost variances from forecast at $20 million annually. However, certain items which are not within the Company's control would be outside of the indexing; such items would include legislative, accounting, regulatory and tax law changes as well as environmental and nuclear decommissioning costs. These items and the existing balances of certain other deferral items such as MERIT and demand-side management (DSM), would be recovered using a temporary rate surcharge. The proposal would also establish a minimum return on equity which, if not achieved, would permit the Company to refile and reset base rates subject to indexing or to obtain some other form of rate relief. Conversely, in the event earnings exceed an established maximum allowed return on equity, such excess earnings would be used to accelerate recovery of regulatory or other assets. The proposal would provide the Company with greater flexibility to adjust prices within customer classes to meet competitive pressures from alternative electric suppliers while increasing the risk that the Company will earn less than its allowed rate of return. Gas rate adjustments beyond 1995 would follow traditional regulatory methodology.
The flexibility and responsiveness of the rate proposal to changing business conditions is designed to better position the Company to meet the challenges of increasing competition and
protect shareholder value. However, the Company must be disciplined in its spending based upon its projections of price increases, if any, sales levels and potential discounts during the five-year period.
The financial success of the Company under its price indexing rate proposal will be dependent on the ability of the Company to control its costs. Because price indexing begins with base prices set for 1995, inclusive of such items as fuel, purchased power and taxes, the establishment of an appropriate base is critical to the financial results of the Company during the five-year period.
The Company can provide no assurance that the Company's proposal will be adopted as submitted. The Consumer Protection Board (CPB) filed a motion on March 2, 1994, to dismiss the proposal and consider rates for only 1995 on the grounds that the PSC could not legally set rates for a five-year period, and the Company has not provided sufficient basis for evaluating the effects of years two through five of the proposal. Other intervenors have generally supported the CPB's position on the issue of legality. The PSC Staff, in its response, disagreed with the CPB on the issue of legality, agreed as to the deficiency of support of years two through five and further stated that the support for the requested relief for 1995 was also deficient. The PSC Staff proposed the solution of extending the period in which the rate proposal would be evaluated by fourteen weeks, with a make-whole agreement for the financial effects of the delay for only seven weeks. The Company believes that the entire proposal has been adequately supported and that the PSC can legally adopt the five-year proposal. A prehearing conference with the Administrative Law Judge was held March 28, 1994 during which a date of April 5, 1994, was established for responses to the PSC Staff's motion to dismiss the entire rate filing. The Company cannot predict what rate program may ultimately be implemented or the effect thereof on the Company's financial condition and results of operations.
Other Electric rate initiatives. In March 1994, the Company filed optional tariff rates for the vast majority of its customers. The optional pricing arrangements, which are proposed to become effective January 1, 1995, are designed to meet existing and evolving forms of competition (on-site generation and otherwise). They also provide secondary benefits in the form of reduced energy rates for incremental consumption.
The Company will also be submitting revisions to SC-8, a real time pricing program, which should advance the program from its current pilot status to permanent rate status. The adjustments are being introduced to address the dynamics of each customer's changing business cycle as well as competitive adjustments to react to the alternatives available to contestable customers.
Gas rate initiatives. On July 28, 1993, the Company petitioned the PSC for permission to offer competitively priced natural gas to customers who presently purchase gas from non- utility sources. The new rate is designed to regain a share of the industrial and commercial sales volume the Company lost in the 1980's when large customers were allowed to buy gas from non-
utility sources. In October 1993, the PSC approved the filing generally, but rejected several key features on the grounds that they involved issues that the PSC preferred to consider on a generic basis in the proceeding referred to above. The Company considered the rate unworkable as approved, and withdrew its filing to await completion of the generic proceeding.
On May 5, 1993, the Company's Natural Gas Vehicle Service-SC 11 rate became effective, allowing the Company to make sales of natural gas for natural gas vehicles.
Because of the broad scope of the rate and service issues encompassed by the PSC's ongoing generic investigation of "restructuring of the emerging competitive gas market," the Company does not anticipate pursuing any major gas rate initiatives until the PSC's order in that proceeding has been issued. That order is currently scheduled for issuance on or about July 1, 1994.
State Regulatory Response to FERC Order 636. With the implementation of FERC Order 636, many state regulatory agencies have begun to consider whether, and to what extent, the advent of restructured services on the interstate pipelines will require changes in the way that local gas distribution services are regulated. In New York, the PSC on October 28, 1993 initiated a "generic proceeding" applicable to all gas utilities in the state for the purpose of addressing "issues associated with the restructuring of the emerging competitive natural gas market." Among the issues under consideration are: (1) should utilities be regulated differently in their core (traditional) markets than in their non-core (open to competition) markets; (2) should utilities be permitted to discontinue traditional sales services to customers who have access to alternative suppliers; (3) what service obligation should utilities have toward customers who do not purchase their gas supplies from the utilities; (4) should utilities be permitted to participate in competitive markets and, if so, on what terms; and (5) should utilities be required to unbundle their systems further by making storage and other services available to their customers?
The current schedule for this proceeding calls for the issuance of an order by the PSC on or about July 1, 1994, and for the filing by utilities of tariff changes implementing the order by around November 1, 1994, the beginning of the winter heating season. Because the Company's gas services are already substantially unbundled, with the majority of its non-core customers currently purchasing their gas supplies from independent marketers and brokers, the Company does not believe that the outcome of this proceeding is likely to have a negative impact on revenues from gas services. The possibility does exist, however, that the Company will be required to offer new and different services, or to delete or modify existing services. Such changes could require substantial revisions in the Company's gas rates structure. The Company is, therefore, participating actively in the proceeding.
UNREGULATED GENERATORS. In recent years, a leading factor in the increases in customer bills and the deterioration of the Company's competitive position has been the requirement to
purchase power from unregulated generators at prices in excess of the Company's internal cost of production and in volumes greater than the Company's needs. The Public Utility Regulatory Policies Act of 1978 (PURPA), New York State law and New York State Public Service Commission (PSC) policies and procedures have collectively required that the Company purchase this power from qualified unregulated generators. The price used in negotiating purchased power contracts with unregulated generators (Long Run Avoided Costs) is established periodically by the PSC. Until repeal in 1992, the statute which governed many of these contracts had established the floor on avoided costs at $0.06/kwh (the Six-Cent Law). The Six-Cent Law, in combination with other factors, attracted large numbers of unregulated generator projects to New York State and, in particular, to the Company's service territory.
For the year ended December 31, 1993, unregulated generator purchases were approximately $736 million (11,720,000 MWHrs.) compared to approximately $543 million (8,632,000 MWHrs.) in 1992 and approximately $268 million (4,303,000 MWHrs.) in 1991. In 1993, unregulated generator purchases provided approximately 28% of the Company's power supply while comprising 67% of the Company's fuel and purchased power costs. As of December 31, 1993, 147 of these unregulated generators with a combined capacity of 2,253 MW were on line and selling power to the Company. Another 438 MW are under construction, including 300 MW from the Sithe-Independence 2 project under an energy-only contract. An additional 72 MW are awaiting construction and have not been included in any Company forecasts regarding future capacity. The Company is projecting that, in 1994, payments to unregulated generators will represent 27% of each electric revenue dollar billed, as compared with 22% in 1993.
Without any other action, the Company's installed capacity reserve margin is projected to grow to 40-50% before declining in the late 1990's, as compared to the minimum mandated requirement of 18%. While the Company favors the availability of unregulated generators in satisfying its generating needs, the Company also believes it is paying a premium to unregulated generators for energy it does not currently need. The Company has initiated a series of actions to address this situation but expects that in large part the higher costs will continue.
On August 18, 1992, the Company filed a petition with the PSC which calls for the implementation of "curtailment procedures." Under existing FERC and PSC policy, this petition would allow the Company to limit its purchases from unregulated generators when demand is low. While the Administrative Law Judge has submitted recommendations to the PSC, the Company cannot predict the outcome of this case. Also, the Company has commenced settlement discussions with certain unregulated generators regarding curtailments.
On October 23, 1992, the Company also petitioned the PSC to order unregulated generators to post letters of credit or other firm security to protect ratepayers' interests in advance payments made in prior years to these generators. The PSC dismissed the original petition without prejudice, which the Company believes would permit the Company to reinitiate its request at a later date. The Company is conducting discussions
with unregulated generators representing over 1,600 MW of capacity, addressing the issues contained in its petitions.
On February 4, 1994, the Company notified the owners of nine projects with contracts that provide for front-end loaded payments of the Company's demand for adequate assurance that the owners will perform all of their future repayment obligations, including the obligation to deliver electricity in the future at prices below the Company's avoided cost and the repayments of any advance payment which remains outstanding at the end of the contract. The projects at issue total 426 MW. The Company's demand is based on its assessment of the amount of advance payment to be accumulated under the terms of the contracts, future avoided costs and future operating costs of the projects. As of March 25, 1994, the Company has received the following responses to these notifications:
On March 4, 1994, Encogen Four Partners, L.P. filed a complaint in the United States District Court for the Southern District of New York alleging breach of contract and prima facie tort by the Company. Encogen seeks compensatory damages of approximately $1 million and unspecified punitive damages. In addition, Encogen seeks a declaratory judgment that the Company is not entitled to assurances of future performance from Encogen;
On March 4, 1994, Sterling Power Partners, L.P., Seneca Power Partners, L.P., Power City Partners, L.P. and AG- Energy, L.P. filed a complaint in the Supreme Court of the State of New York, County of New York seeking a declaratory judgment that: (a) the Company does not have any legal right to demand assurances of plaintiffs' future performance; (b) even if such a right existed, the Company lacks reasonable insecurity as to plaintiffs' future performance; (c) the specific forms of assurances sought by the Company are unreasonable; and (d) if the Company is entitled to any form of assurances, plaintiffs have provided adequate assurances; and
On March 7, 1994, NorCon Power Partners, L.P. filed a complaint in the United States District Court for the Southern District of New York seeking to enjoin the Company from terminating a power purchase agreement between the parties and seeking a declaratory judgment that the Company has no right to demand additional security or other assurances of NorCon's future performance under the power purchase agreement. NorCon sought a temporary restraining order against the Company to prevent the Company from taking any action on its February 4 letter. On March 14, 1994, the Court entered the interim relief sought by NorCon.
The Company cannot predict the outcome of these actions or the response otherwise to its February 4, 1994 notifications, but will continue to press for adequate assurance that the owners of these projects will honor their repayment obligations.
Also see Item 3 - -Legal Proceedings, Item 7 - -Management's Discussion and Analysis of Financial Condition and Results of Operations, and Item 8 - -Financial Statements and Supplementary Data, Note 8.
NEW YORK POWER AUTHORITY (NYPA). The Company presently has contractual rights to purchase various types and amounts of electric power and energy from a number of generating facilities owned by the NYPA. In 1993, these purchases amounted to 7,008,000 MWH, or about 17% of the Company's total power supply requirements. Under the agreement for hydroelectric power service, the Company credits to its residential customers, subject to review by the PSC, any savings derived from the purchase of an aggregate of 405 MW of firm and peaking hydro power from NYPA. The following table indicates the types and amounts of NYPA power which the Company was entitled to purchase as of January 1, 1994 and the termination dates of its contracts with NYPA with respect to each generating facility:
Contract NYPA Facility and Type of Expiration Power Purchase Rights Date Niagara Hydroelectric Project on the Niagara River near Niagara Falls, N.Y. (capacity 2,190,000 kw.):
Firm 126,000 kw. 2007
Replacement 445,000 kw. 2006 Expansion 182,000 kw. 2007
Peaking 175,000 kw. 2007 St. Lawrence Hydroelectric Project on the St. Lawrence River near Massena, N.Y. (capacity 912,000 kw.) 104,000 kw. 2007
Blenheim-Gilboa Pumped Storage Generating Station in Schoharie County, N.Y. (capacity 1,000,000 kw.):
Pumped Storage Service 270,000 kw. 2002 FitzPatrick Nuclear Plant near Oswego, N.Y. (capacity 821,000 kw.):
Allocation of available Plant Capacity 40,000 kw. (a) Year-to year basis Total 1,342,000 kw.
(a) 40,000 kw. for summer of 1994; 63,000 kw. for winter of 1994-1995.
The Company also transmits power from NYPA projects to NYPA's preference and other customers and to other public and municipal utilities within New York.
PURCHASED POWER. Total purchased power in 1993 amounted to 20,766,000 MWH, including unregulated generators and NYPA purchases discussed above, representing approximately 50% of the Company's total power supply requirements. The Company purchases electricity from the New York Power Pool (NYPP) and other neighboring utilities on an hour-to-hour basis as needed for economic operation. The price paid for that power is determined at the time of purchase. Changes in the cost of purchased power are included in the Company's fuel adjustment clause (FAC). Physical limitations of existing transmission facilities, as well as competition with other utilities and unavailability of energy, impact the amount of power the Company is able to purchase.
As previously discussed, as more unregulated generator capacity and energy comes on line over the next several years, wholesale power purchases from other utilities may decrease. Wholesale power marketing efforts will also become increasingly important, in a highly competitive environment, in order to utilize the Company's surplus capacity.
FUEL FOR ELECTRIC GENERATION. COAL - The C. R. Huntley and Dunkirk Steam Stations, the Company's only coal fired stations, are expected to burn about 1.6 and 1.0 million tons of coal, respectively, in 1994. The Company has two coal supply contracts, one of which is scheduled to expire at the end of 1994 and the other in 1995.
The annual average cost of coal burned from 1991 through 1993 was $1.59, $1.51 and $1.54, respectively, per million BTU, or $41.40, $39.42 and $39.85, respectively, per ton. Changes in the cost of coal burned, part of which are shipping expenses, are included in the Company's FAC. See also "Regulation and Rates" for a further discussion of the fuel adjustment clause.
As a result of amendments to the Clean Air Act approved in November 1990, the Company will be faced with reducing certain emissions over the next decade. The Dunkirk Steam Station was identified as requiring reductions of certain emissions in Phase I. See "Environmental Matters - Air".
The Company continually examines its competitive situation and future strategic direction. Among other things, it has studied the economics of continued operation of its fossil-fueled generating plants, given current forecasts of excess capacity. Growth in unregulated generator supply sources and compliance requirements of the Clean Air Act are key considerations in evaluating the Company's internal generation needs. While the Company's coal-burning plants continue to be cost advantageous, certain older units and certain gas/oil-burning units are being carefully assessed to evaluate their economic value and estimated remaining useful lives. Due to projected excess capacity, the Company plans to retire or put certain units in long-term cold standby. A total of 850 MWs of oil fired capacity is to be placed in long-term cold standby in 1994 and 340 MWs of aging
coal fired capacity is to be retired by the end of 1999. The Company is also continuing to evaluate under what circumstances the standby plants would be returned to service, but, barring unforeseen circumstances, it is not likely that a return would occur before the end of 1999. This action will permit the reduction of operating costs and capital expenditures for retired and standby plants. The Company believes that the remaining investment in these plants of approximately $300 million at December 31, 1993 will be fully recoverable in rates.
NATURAL GAS - The Albany Steam Station has the capability to use natural gas, as well as residual oil, as a fuel for electric generation. This dual-fuel capability permits the use of lower cost fuel. During 1991, 1992 and 1993, natural gas was the predominant fuel used although generation at this station was curtailed significantly in 1993 for economic reasons because of the requirement to purchase unregulated generator power. The Company contracts with various suppliers for the purchase of natural gas for Albany station. This is an interruptible supply; colder than normal weather and increased demand for capacity on interstate pipelines by other firm gas customers could restrict the amount of gas supplied. Other natural gas used included the operation of two combustion turbines at the Albany Steam Station (two additional Albany turbines were placed in long-term cold standby effective April 1992). During the period 1991 through 1993, the Company, including the Roseton station, burned 22.0, 19.4 and 6.0 million dekatherms (Dt) of natural gas, respectively, at an average cost per million BTU or Dt of $2.48, $2.31 and $2.07, respectively.
RESIDUAL OIL - The Company's total requirements for residual oil in 1994 for its Albany and Oswego Steam Stations are estimated at approximately 1.7 million barrels. Fuel sulfur content standards instituted by New York State require 1.5% sulfur content oil to be burned at Albany and Oswego Unit No. 5. Oswego Unit No. 6 requires low sulfur fuel (0.7%). All oil requirements are met on the spot market. At December 31, 1993, there were approximately 0.7 million barrels, or more than a 45- day supply of oil, at the Oswego Steam Station and approximately 0.2 million barrels of oil, or a 45-day supply, at the Albany Steam Station, based on maximum burn projections. The average price of No.6 oil at January 1, 1994 was approximately $18.30 per barrel for 0.7% sulfur oil. For 1.5% sulfur oil, the average price was approximately $16.40 per barrel at the Oswego Steam Station and $15.20 per barrel at the Albany Steam Station. The fuel oil prices quoted include the $3.1122 per barrel petroleum business tax imposed by New York State. Changes in the cost of oil burned, part of which are shipping expenses, are included in the FAC. See also "Regulation and Rates" for a further discussion of the fuel adjustment clause.
Contract arrangements for residual oil for the Roseton Steam Station, in which the Company has a 25% ownership interest, have been made by Central Hudson Gas and Electric Corporation, co- owner and operator of the plant. Two suppliers, the Sun Oil Trading Company and Global Petroleum Corporation, are supplying 1.5% sulfur residual oil under contract for the fuel requirements of the plant. Both contracts have arrangements that include
certain options regarding contract extensions. The Roseton Steam Station's first unit was modified to dual-fuel capability with natural gas as the alternative fuel in December 1991. The second unit's modification was completed in July 1992 and it now has the ability to burn natural gas as an alternate fuel.
Central Hudson Gas and Electric has in place three term contracts (for 15 years each) for the supply of up to 100,000 mcf of natural gas for use at the Roseton plant as a boiler fuel alternative to residual oil. The natural gas supply is used primarily during off peak months, April through October of each year.
The annual average cost of residual oil burned at the Albany, Oswego and Roseton Steam Stations from 1991 through 1993 was $3.07, $2.98 and $3.11, respectively, per million BTU, or $19.49, $18.93 and $19.84, respectively, per barrel.
NUCLEAR - The supply of fuel for nuclear generating plants involves: (1) the procurement of uranium concentrates (yellowcake) (U3O8), (2) the conversion of uranium concentrates to uranium hexafluoride, (3) the enrichment of the uranium hexafluoride, (4) the fabrication of fuel assemblies and (5) the disposal of spent fuel and radioactive wastes. Agreements for nuclear fuel materials and services for Nine Mile Point Nuclear Station Unit No. 1 (Unit 1) and Nine Mile Point Nuclear Station Unit No. 2 (Unit 2) (in which the Company has a 41% interest), have been made through the following years:
Nine Mile Nine Mile Point Nuclear Point Nuclear Station Unit Station Unit No. 1 No. 2 Uranium Concentrates (a) 2000 (b) 2000 (b)
Conversion 2000 (b) 2000 (b)
Enrichment (c) (c) Fabrication 1994 2003
(a) Includes uranium concentrates transferred from wholly- owned subsidiary, N M Uranium, Inc. (NMU) - see below. (b) Arrangements have been made for procuring a portion of the uranium and conversion requirements through the year 2000, leaving the remaining portion of the requirements uncommitted. (c) An enrichment contract is in place with the Department of Energy (DOE) through the year 2014 or the life of the reactor, whichever is less.
The uncommitted requirements for nuclear fuel materials and services are expected to be obtained through long-term contracts or secondary market purchases. The foregoing table includes uranium concentrates produced by NMU. NMU has a 50% interest in an in-situ uranium mining operation in Live Oak County, Texas, which ceased production in 1987. Site restoration is ongoing and is expected to continue into the late 1990's. At December 31,
1993, the NMU inventory was approximately 31,355 pounds (U3O8), which is expected to be transferred to the Company in mid-1994.
The Company currently has in place contracts with the DOE for the disposal of spent fuel for both Units 1 and 2. The spent fuel storage facilities at Units 1 and 2 are expected to accommodate spent fuel discharges while also having sufficient space available to accept fuel in the core at that time, through the years 1999 and 2014, respectively.
In January 1983, the Nuclear Waste Policy Act of 1982 (Act) was enacted. The Act established a cost of $.001 per kilowatt- hour of net generation to fund disposal of nuclear fuel irradiated after 1982 and provided for a determination of the Company's liability to the DOE for the disposal of nuclear fuel irradiated prior to 1983. The Act also provides three payment options for liquidating such liability (approximately $93.5 million at December 31, 1993) and the Company has, for Unit 1, elected to delay payment, with interest, until 1998, the year in which the Company had initially planned to ship irradiated fuel to an approved DOE disposal facility. The Company has no such retroactive liability for Unit 2. Progress in developing the permanent DOE repository has been slow and it is unlikely that the DOE's latest projection for opening this facility in 2010 can be met. In the interim, DOE is proposing to begin acceptance of some spent fuel from the electric utility industry as early as 1998 at a proposed Monitored Retrievable Storage (MRS) facility. However, in view of the very limited progress made to date, it is unlikely that this facility will begin operation in 1998. A more probable date for operation of the MRS facility cannot be accurately forecast at this time. Further, the projected capacity for this MRS facility is such that any interim relief provided to Unit 1 before the permanent repository opens is likely to be small.
The Company has been studying spent fuel storage alternatives and has in place a contract to rerack the Unit 1 spent fuel pool. Half of the pool will be reracked in 1998, thereby providing significant core offload space until the year 2004. Some of the alternatives will require Nuclear Regulatory Commission (NRC) review and/or approval and related state approval. The present licensed storage capacity for Unit 2 will meet the needs of the Unit sufficiently far into the future that storage alternatives are not believed to be needed at this time. Thus, the Company does not believe that the possible unavailability of a DOE facility in 1998 will inhibit operation of either Unit.
The cost of fuel utilized at Unit 1 for 1993, 1992 and 1991 was $.56, $.55 and $.68 per million BTU, respectively. The cost of fuel utilized at Unit 2 for 1993, 1992 and 1991 was $.54, $.53 and $.62 per million BTU, respectively.
For the recovery of nuclear fuel costs through rates and for further information concerning costs relating to decommissioning of the Company's nuclear generating plants, see Item 8 -- Financial Statements and Supplementary Data, Note 1 - Depreciation, Amortization and Nuclear Generating Plant Decommissioning Costs and Note 7 - Nuclear Plant Decommissioning.
GAS SUPPLY. The Company distributes natural gas to a geographic territory that extends from Syracuse to Albany. The northern reaches of the system extend to Watertown and Glens Falls. Not all of the Company's distribution areas are physically interconnected with one another by Company-owned facilities. Presently, nine separate distribution areas are connected directly with CNG Transmission Corporation (CNG), an interstate natural gas pipeline regulated by the FERC, via seventeen delivery stations. The majority of the Company's gas sales are for residential and commercial space and water heating. Consequently, the demand for natural gas by the Company's customers is seasonal and influenced by weather factors.
Under a twenty-year contract, the primary term of which ended in March 1990, CNG was obligated, within broad limits, to meet the full requirements of the Company as they would change from time to time. Since 1986, the Company has exercised its right, obtained in negotiation, to purchase part of its supply from other sources and has aggressively pursued access to alternative supplies of gas that are less expensive than pipeline supply.
FERC Order No. 636, issued in April 1992, changed the structure of interstate natural gas pipeline services and completed the "evolution of competition, in the natural gas industry." During 1992 and 1993, the Company actively pursued, through the negotiation process established by the FERC, pipeline services which would provide the Company with an appropriate combination of firm transportation on several upstream pipelines, CNG transportation and substantial storage rights. Negotiations to implement Order No. 636, with CNG and the major upstream pipelines, were essentially completed in November 1993 when the last of the pipelines placed its revised service plans in effect. Order No. 636 also helped complete the Company's primary objective of replacing dependence on CNG sales service with independently contracted gas supplies delivered through a combination of firm transportation and storage.
The Company revised its post-Order No. 636 services to meet peak load requirements on its system through a portfolio of firm contracts capable of delivering approximately 903,000 dekatherms per day to its service area. This portfolio includes firm transportation totaling approximately 356,000 dekatherms on the CNG system as well as five upstream pipelines, with firm supplies purchased under 24 different contracts from a variety of producers and marketers in the Gulf of Mexico, the Southwest and Canada. An additional 434,000 dekatherms of peak day requirement capacity is provided by firm storage withdrawal rights coupled with firm winter season transportation service on CNG. Finally, approximately 113,000 dekatherms is available to the Company under peak shaving contracts with cogenerators on the Company's system.
Transition Costs Under FERC Order 636. As a result of structural changes under Order 636, pipelines face "transition" costs from implementation of the Order. The principal costs are: unrecovered gas cost that would otherwise have been billable to pipeline customers under previously existing rules, costs related to restructuring existing gas supply contracts and costs of
assets needed to implement the Order (such as meters, valves, etc.). Under the Order, pipelines are allowed to recover 100% of eligible and prudently incurred costs from customers. Eligibility and prudence will be determined by FERC review.
The amount of restructuring costs ultimately billed to the Company will be determined in accordance with a number of proceedings currently underway before the FERC. There are four pipelines to which the Company has some liability. The Company is actively participating in FERC proceedings on these matters to ensure an equitable allocation of costs. The restructuring costs will be primarily reflected in demand charges paid to reserve space on the various interstate pipelines and will be billed over a period of approximately 7 years, with billings more heavily weighted to the first 3 years.
Based upon information presently available to the Company from the petitions filed by the pipelines, the Company's participation in settlement negotiations and the three settlements to which it is a party, its liability for the pipelines' unrecovered gas costs is expected to be as much as $31 million and its liability for pipeline restructuring costs could be as much as $38 million. The Company has recorded a liability of $31 million at December 31, 1993, representing the low end of the range of such transition costs. The Company is unable to predict the final outcome of current pipeline restructuring settlements, the ultimate amounts for which it will be liable or the period over which this liability will be billed.
Based upon Management's assessment that transition costs will be recovered from ratepayers, a regulatory asset has been recorded representing the future recovery of transition costs accrued to date. Currently, such costs billed to the Company are treated as a cost of purchased gas and recoverable through the operation of the purchased gas adjustment clause mechanism.
INDUSTRY SEGMENT DATA. The percentages of the total revenues and operating income before income taxes, exclusive of an Allowance for Funds Used During Construction (AFC), derived from electric and gas operations for the past three years were as follows:
Operating Income Before Income Taxes Total Revenues (Excluding AFC) Year Electric Gas Electric Gas
1993 85% 15% 91% 9%
1992 85% 15% 91% 9% 1991 86% 14% 94% 6%
See also "Item 8 - -Financial Statements and Supplementary Data," Note 10.
ENVIRONMENTAL MATTERS. General - The protection and restoration of the environment remains a strategic concern of the
Company. In response to the issues facing the Company, management has taken a number of actions specifically designed to mobilize Company resources. The operations of the Company are regulated by Federal and state governmental agencies and, to some extent, by local governments in New York, with respect to air and water quality and other environmental matters.
In compliance with environmental statutes and consistent with its strategic philosophy, the Company performs environmental investigations and analyses and installs, as required, pollution control equipment, effluent monitoring instrumentation and materials storage/handling facilities designed to prevent or minimize releases of potentially harmful substances. Expenditures for environmental matters for 1993 totaled approximately $66 million, of which approximately $29 million was capitalized as pollution control equipment or new plant environmental surveillance and approximately $37 million was charged to operating expense for operation of environmental monitoring and waste disposal programs. Expenditures for 1994 are estimated to total $95 million, of which $58 million is expected to be capitalized and $37 million charged to operating expense. Similar expenditures for 1995 are estimated to total $58 million, of which $14 million is expected to be capitalized and $44 million charged to operating expense. The expenditures for 1994 and 1995 include the estimated costs for the Company's proportionate share of site investigation and cleanup of waste sites discussed under "Solid/Hazardous Waste" below.
There are growing concerns about the effects of electric and magnetic fields (EMFs), including those produced by distribution, transmission and substation installations, as well as household wiring and appliances. Numerous studies on the effects of EMFs have been done and are continuing throughout the world, with results that are often hard to interpret and sometimes conflicting. On February 26, 1993, the Environmental Protection Agency (EPA) called for significant additional research on EMFs. The Company is taking a proactive approach and has worked with school officials to identify magnetic field levels at school buildings near its transmission lines. The Company is taking steps to mitigate magnetic fields at these locations. It is impossible to predict what further effect, if any, continued research and epidemiological studies on EMFs could have on the Company and the electric utility industry. The role of the utility industry in addressing these environmental matters will be prominent and could be costly.
Air - The Company is required to comply with applicable Federal and State air quality requirements pertaining to emissions into the atmosphere from its fossil-fuel generating stations and other potential air pollution sources. The Company's four fossil-fired generating stations (Albany, Huntley, Oswego and Dunkirk) are operated in accordance with the provisions of Certificates of Operation issued by the New York State Department of Environmental Conservation (DEC).
On November 15, 1990, then President Bush signed into law the Clean Air Act. The provisions of the Clean Air Act address attainment and maintenance of ambient air quality standards, mobile sources of air pollution, hazardous air pollutants, acid rain, permits, enforcement, clean air research and other
miscellaneous items. The Clean Air Act will have a substantial impact upon the operation of electric utility fossil-fired power plants.
The acid rain provisions of the Clean Air Act require that sulfur dioxide (SO2) emissions be reduced nationwide by 10 million tons from their 1980 levels and that NOx emissions be reduced by two million tons from 1980 levels. Emission reductions will be achieved in two phases - Phase I by January 1, 1995 and Phase II by January 1, 2000.
The Company filed its Phase I acid rain permit application and compliance plan with the Environmental Protection Agency on February 15, 1993. The Company has two units (Dunkirk 3 and 4) affected in Phase I. Beginning in 1995, SO2 reductions of approximately 10,000-15,000 tons per year must be achieved. Among the options being considered by the Company for compliance with the Phase I SO2 emission reduction requirements are fuel switching, reduced utilization of Phase I affected units, switching to a lower sulfur content coal and the purchase of emission allowances.
With respect to NOx, Title IV of the Clean Air Act will require emission reductions at the Company's Phase I affected coal units. Installation of low NOx burners or equivalent technology will be required to meet the new emission limitations. In addition, Title I of the Clean Air Act (Provisions for the Attainment and Maintenance of National Ambient Air Quality Standards) will require the installation of "Reasonably Available Control Technology" (RACT) on all of the Company's coal, oil and gas-fired units by May 31, 1995. Compliance with Title I RACT requirements at the Company's units will be achieved by installing low NOx burners or other combustion control technology.
The Company spent approximately $19 million in capital expenditures in 1993 on Clean Air Act compliance and has included approximately $46 million in its construction forecast for 1994 through 1997.
Phase II requirements associated with Title I and Title IV of the Clean Air Act (targeted for the year 2000 and beyond) will require the Company to further reduce its sulfur dioxide and nitrogen oxide emissions at all of its fossil generating units. Regulatory uncertainty surrounding these requirements precludes an accurate assessment of compliance options and costs. Possible options for Phase II SO2 compliance beyond those considered for Phase I compliance include additional fuel switching, installation of flue gas desulfurization or clean coal technologies, repowering and the trading of emission allowances. Compliance with Phase II NOx emission limits may require installation of post-combustion NOx control technology such as Selective Catalytic Reduction. States in the Northeast Ozone Transport Region may determine that such controls are required on fossil-fired electric generating units in order to attain Ambient Air Quality Standards for ozone. This determination is expected to be made in late 1994.
The Company's preliminary assessment of Phase II SO2 and NOx compliance costs is that additional capital expenditures on the
order of $124 million (1994 dollars) will be required and incremental annual fuel costs and operating expenses of approximately $21 million will be incurred. However, there are a number of uncertainties that make it difficult to project these costs definitively at this time. See Construction Program below.
With response to all of these costs the Company believes, based on traditional and historical rate treatment, that it is probable that all additional expenditures and costs will be fully recoverable through rates.
Water - The Company is required to comply with applicable Federal and State water quality requirements, including the Federal Clean Water Act, in connection with the discharge of condenser cooling water and other waste waters from its steam- electric generating stations and other facilities. Wastewater discharge permits have been issued by DEC for each of its steam- electric generating stations. These permits are renewed every five years. Conditions of the permits require that studies be performed to determine the effects of station operation on the aquatic environment in the station vicinity and to evaluate various technologies for mitigating losses of aquatic life. Studies are ongoing and the Company believes that any additional expenditures relating to or resulting from these studies will be fully recoverable through rates.
The zebra mussel was identified in the United States in 1986 and has become an increasing concern, as it has rapidly multiplied throughout the Great Lakes and adjoining inland waters. The mussels colonize in large numbers, attaching to almost any underwater surface and causing serious restriction of the flow of water intake structures and plant piping systems. All of the Company's steam electric stations and some of its hydroelectric facilities have experienced infestation of zebra mussels. The Company, in cooperation with other electric utilities and research organizations, is developing short and long-term control strategies to prevent or at least minimize zebra mussels related operational problems at its generating facilities. The Company believes that additional expenditures and costs of operations caused by the zebra mussels problem will be fully recoverable through rates.
Low Level Radioactive Waste - The Federal Low Level Radioactive Waste Policy Act requires states to join compacts or individually develop their own low level radioactive waste disposal site. In response to the Federal law, New York State decided to develop its own site because of the large volume of low level radioactive waste it generates and committed by January 1, 1993 to develop a plan for the management of low level radioactive waste in New York State during the interim period until a disposal facility is available.
New York State is developing disposal methodology and acceptance criteria for a disposal facility. A revised New York State low level radioactive waste site development schedule now assumes two possible siting scenarios, a volunteer approach and a non-volunteer approach, either of which would begin operation in 2001. An extension of access to the Barnwell, South Carolina waste disposal facility was made available to out-of-region low level radioactive waste generators by the state of South Carolina
through June 30, 1994, and New York State has elected to use this option. The Company has a low level radioactive waste management program and contingency plan so that Unit 1 and Unit 2 will be prepared to properly handle interim on-site storage of low level radioactive waste for at least a 10-year period, if required.
Solid/Hazardous Waste - See Item 8 - -Financial Statements and Supplementary Data, Note 8.
NUCLEAR OPERATIONS. The Company is the owner and operator of Unit 1 and the operator and 41% co-owner of Unit 2. Ownership of Unit 2 is shared with Long Island Lighting Company (18%), New York State Electric & Gas Corporation (18%), Rochester Gas and Electric Corporation (14%), and Central Hudson Gas & Electric Corporation (9%). Output of Unit 2, which has a capability of 1,062,000 kw., and the cost of operation and capital improvements are shared in the same proportions as the cotenants' respective ownership interests. For regulatory purposes, April 5, 1988 has been recognized as the commercial operation date for Unit 2. Unit 1 has a design capability of 613,000 kw. and was placed in commercial operation in 1969.
The Company's nuclear operations are within the jurisdiction of numerous federal and state regulatory agencies. The extent of regulation by each agency varies, as does the impact such regulation may have on plant operations. The principal agencies include:
NRC: has primary and preemptive jurisdiction over all health and safety aspects, operations and decommissioning activities related to commercial nuclear power plants.
PSC: has jurisdiction over the economic, regulatory and rate aspects of nuclear power generation.
EPA: has jurisdiction over the discharge of airborne effluents from generating power plants.
DEC: regulates the handling, disposition and concentrations of "by-product" nuclear material at and from the Unit sites, as ceded to it by the NRC.
DOE: has ultimate custody and control over all U.S. origin spent nuclear fuel.
Federal Emergency Management Agency: has some jurisdiction over emergency planning.
There are other agencies that have limited jurisdiction over various aspects of nuclear plant operations.
The Company also participates in the Nuclear Management & Resources Council (a trade association) and the Institute for Nuclear Power Operations (an industry-formed group which promulgates and monitors voluntary operating, maintenance and performance standards).
Unit 1 Economic Study. See Item 8 - -Financial Statements and Supplementary Data, Note 7.
Unit 1 Status. On February 20, 1993, Unit 1 was taken out of service for a planned 55-day refueling and maintenance outage. Unit 1 returned to service after a 55 day outage on April 15, 1993. The next refueling outage is scheduled to begin in February 1995. Unit 1's capacity factor for 1993 was approximately 81%. Using NRC guidelines, Unit 1's capacity factor was approximately 88% (see below).
Unit 2 Status. On October 2, 1993, Unit 2 was taken out of service for a planned 60-day refueling and maintenance outage. On November 29, 1993 Unit 2 returned to service after a 59 day outage. The next refueling outage is scheduled to begin in the Spring of 1995. Unit 2's capacity factor for 1993 was approximately 78%. Using NRC guidelines, Unit 2's capacity factor was approximately 83% (see below).
There are various methods of measuring capacity factors. The Company has traditionally used a methodology recognizing net maximum dependable capacity of its nuclear units under optimum conditions. In order to report operating indicators on a consistent basis with other nuclear plants and in accordance with NRC guidelines, the Company now plans to reflect capacity factors with net maximum dependable capacity during the most restrictive seasonal conditions. This will generally result in higher capacity factors being disclosed than under the prior criteria based on equivalent performance.
Unit 2 Operating Agreement. The Company and cotenant companies executed an operating agreement (Agreement) in August 1989 which established the legal relationship between the Company (as operator and 41% owner of Unit 2) and the other cotenants. The Agreement outlines the responsibilities and participation of the cotenants in the overall management of Unit 2, while the Company remains responsible for day-to-day operations. The Agreement has continued to be amended to extend the term of the Agreement, with the latest amendment stating that the Agreement will lapse on December 31, 1994, but provides for automatic extensions unless terminated by at least one of the cotenants after appropriate notice.
CONSTRUCTION PROGRAM. The purpose of the Company's ongoing construction program is to assure reliable delivery of its electric and gas services. The Company presently estimates that its construction program for the years 1994 through 1998 will require approximately $1.57 billion, excluding AFC, certain overheads capitalized and nuclear fuel. For the years 1994 through 1998, the estimates are $408 million, $295 million, $287 million, $291 million and $285 million, respectively. The estimate of construction additions for the period 1994 to 1998 is reviewed by management as circumstances dictate.
The Company has also included amounts in the construction forecast for hydro relicensing, as well as for gas system expansion for the cogeneration market and greater customer penetration.
ELECTRIC SUPPLY PLANNING. New York State passed energy legislation in 1992 establishing a four-year cycle for updating
the State Energy Plan (SEP). The first SEP in this cycle is due to be finalized in May 1994. In order to consider the recommendations and policy direction of the 1994 SEP, the Company has decided to prepare its next full Integrated Electric Resource Plan (IERP) report during 1994, for completion by early 1995. The timing will be further coordinated with the filing requirements expected to be issued by the PSC in Case 92-E-0886, Proceedings on the Motion of the Commission to Examine the Integrated Resource Plans of Electric Utilities.
In June 1993, the Company produced an IERP Update to bridge the gap between its previous IERP (September 1991) and the next edition. The 1993 Update re-examined the timing requirements for new resource commitments and found that the Company's current owned and contracted generating capacity should enable it to meet reserve requirements until approximately 2003-2004. Extension of contracts with unregulated generators should postpone this date until 2007-2008. Thus, from an installed capacity perspective, there is no need to commit to new generation resources for several years. This lack of need indicates that the Company's resource bidding process will not be exercised for large scale procurements in the near future, except for economy purchases.
In a pending PSC proceeding, the Company has agreed to a settlement which includes the possible implementation of renewable resource projects. If the settlement is approved, the Company will pursue a 6.0 MW wind energy project and will jointly participate with the other member systems of the NYPP in considering additional renewable resources. The exact timing, amount and ownership of these projects is not known at this time. It is intended that only cost-effective renewable resources will be acquired in implementing this agreement.
ELECTRIC DELIVERY PLANNING. As of January 1, 1994, the Company had approximately 9,200 circuit miles of electric delivery facilities. Evaluation of these facilities relative to NYPP and Northeast Power Coordinating Council (NPCC) planning criteria and anticipated Company internal and external demands is an ongoing process intended to minimize the capital requirements for expansion of these facilities. The Company is evaluating new planning tools and methods to determine the adequacy and reliability of its electric delivery facilities. As the expansion of the unregulated generator market progresses, these new generators impose technical, economic and construction burdens on the Company. The Company is typically able to recover the cost of interconnections constructed for unregulated generator access to the Company's system, as well as costs incurred by the Company to enhance its existing system due to the unregulated generator tie-ins.
NEPA provides the FERC with broad authority to mandate wholesale transmission access, which could potentially open the interstate transmission system to new wholesale power transactions. Under the Act, any electric utility or wholesale power producer may apply to FERC for an order requiring a utility to transmit such energy including enlargement of transmission facilities. FERC is prohibited from ordering a utility to transmit power to an end user (retail wheeling). FERC also cannot order a utility to transmit power if to do so would impair
the utility's ability to recover all costs of providing these services.
The Company has reviewed the adequacy of its electric delivery facilities in the context of the IERP and has determined, on a regional basis, which delivery facilities are capable of supporting new unregulated generator resources. The Company has also entered into wheeling agreements with several unregulated generation project developers for sales to other utilities. The projected annual value of this wheeling activity is $63 million in 1994, increasing to $77 million in 1997. Under current ratemaking practices, revenues from wheeling are generally for the benefit of ratepayers.
The Company is committed to a policy of providing transmission service upon request, provided that the revenue derived from such services protects the economic well-being of the Company's customers.
DEMAND-SIDE MANAGEMENT PROGRAMS. Traditionally, the Company served customer loads by building and operating the supply resources needed to meet growing demand. More recently, the PSC has encouraged the Company and other state utilities to market energy efficient programs as an alternative, lower cost method of meeting customer energy service needs.
The Company's DSM programs are an important part of the Company's IERP (see "Electric Supply Planning"), which calls for DSM to contribute as much as 500 MW, or up to 26% of projected new capacity resources required for the years 2000-2005. The IERP is supplemented by a more detailed, long-range DSM plan, which in turn drives the selection of programs for implementation. Actual energy reductions for the calendar year 1992 amounted to 312,849 MWH, compared with a goal of 231,257 MWH. The coincident winter peak was reduced by 41 MW compared with a goal of 38 MW.
Ongoing DSM program implementation in 1993 accounted for an estimated annual energy reduction of 270,000 MWH. Coincident winter peak reductions from 1993 program activity are estimated to be 50 MW. These estimates are subject to adjustment after actual evaluation results become available in July 1994.
In 1993, the Company invested approximately $40 million in DSM programs, including $7.6 million procured through the all- source bidding process. Company sponsored programs addressed residential electric water and space heating, lighting and new construction. Commercial and industrial programs addressed lighting, motors, adjustable speed drives and other custom conservation measures. Programs directed toward farm customers addressed water heating, lighting and ventilation. Bidder sponsored programs for residential customers included refrigerator recycling and conservation measures for multi-family dwellings. A third program sponsored by a commercial/industrial bidder offered a multi-measure program integrated with financing options. Two additional bid programs were sponsored by an industrial customer for lighting and other measures installed at a specific plant site.
In 1994, the Company expects to invest an additional $41.5 million for demand-side investments.
Individual DSM programs are subject to PSC approval prior to implementation and the Commission has established a two-year filing cycle for DSM programs. The Company filed its current programs for an integrated 1993-1994 DSM Plan in October 1992.
The PSC allows the Company to collect DSM programs costs, lost net revenue ("lost margin") and a financial incentive for cost-effective program implementation. Prior to 1993, these costs were all recovered through the Demand Side Investment and Revenue Adjustment Mechanism (DIRAM), and reconciled annually. Starting in 1993, each of these will be recovered in a different manner. Program costs and development support program costs will be recovered on a current basis in base rates, distributed among the classes through accepted cost of service allocations. The 1995 price caps rate proposal would eliminate NERAM and move lost margin recovery back into DIRAM.
Total electric prices will increase in the near term with DSM programs in place due to recovery of lost margin, program costs, and earnings incentive. However, customers who participate in the programs should see a net benefit due to reduced consumption and average customer bills should be lower than without the programs. The allocation of electric price impacts from DSM programs remains an issue of concern in the industry and is being addressed through discussions among the Company, PSC staff, and other intervenors.
As part of the Company's 1993 rate settlement, the Company has developed an innovative "DSM Subscription Service" in which its largest commercial and industrial customers will be given the opportunity to choose between two types of demand-side management service: 1) the Company's traditional subsidized DSM programs, or 2) a non-subsidized "shared savings program" in which each participating customer pays the full cost associated with their individual DSM projects. Customers selecting the non-subsidized service would not be required to contribute to the cost of providing DSM subsidies (rebates).
RESEARCH AND DEVELOPMENT. The Company maintains a substantial research and development program aimed at supporting the Company and its customers in the delivery and use of energy products. The focus of the Company's research effort is and will be to explore practical applications for new and existing technologies in the energy business. These efforts are aimed at (1) improving the efficiency of energy use and delivery; (2) minimizing environmental impacts of energy production, delivery and use; (3) minimizing facility maintenance costs; (4) improving facility availability; and (5) developing renewable energy technologies. The research effort is also directed towards earning a return on products developed from research, by encouraging commercialized applications of research products and promoting their acceptance by other utilities and industry.
Research and development expenditures are charged to operating expenses through the Company's research and development revenue and expenditures matching plan authorized by the PSC.
Research and development expenditures in 1993, 1992 and 1991 were approximately $39.0, $35.2 and $29.9 million, respectively. The increased expenditures reflect an increase in Electric Power Research Institute dues which had been previously reduced due to financial problems experienced by the Company.
In addition to an active internal R&D program, these amounts also include research support to the Electric Power Research Institute, the Empire State Electric Energy Research Corporation, the New York State Energy Research and Development Authority and the Gas Research Institute.
EMPLOYEE RELATIONS. All of the Company's non-supervisory production and clerical workers subject to collective bargaining are represented by the International Brotherhood of Electrical Workers (AFL-CIO). A two-year-nine-month agreement between the Company and the union, which became effective June 1, 1993, provides for annual wage increases of 4% through 1995 and includes modifications to employee pension and health plans and changes in various work practices. It is estimated that approximately 75% of the Company's total labor costs are applicable to operation and maintenance and approximately 25% are applicable to construction (and accordingly are capitalized).
The Company's work force at December 31, 1993 numbered approximately 11,500 of whom approximately 8,000 are union members.
LIABILITY INSURANCE. As of January 31, 1994, the Company's Directors & Officers liability insurance was renewed. This coverage includes nuclear operations and insures the Directors and officers against obligations incurred as a result of their indemnification by the Company. The coverage also insures the officers and directors against liabilities for which they may not be indemnified by the Company, except for a dishonest act or breach of trust.
Item 2.
Item 2. Properties.
ELECTRIC SERVICE. As of January 1, 1994, the Company owned and operated four fossil fuel steam plants (as well as having a 25% interest in the Roseton Steam Station and its output), two nuclear fuel steam plants, various combustion turbine and diesel generating units and 71 hydroelectric plants. The Company also leases small hydroelectric plants and purchases substantially all of the output of 71 others. The Company's Canadian subsidiary, Opinac Energy Corporation, owns Canadian Niagara Power Company, Limited (owner and operator of the 76.8 MW Rankine hydroelectric plant) which distributes electric power within the Province of Ontario. In addition, the Company has contracts to purchase electric energy from NYPA and other sources. See Item 1 -- Business. - "Unregulated Generators", "New York State Power Authority (NYPA)" and "Other Purchased Power" and Item 8 -- Financial Statements and Supplementary Data, Electric and Gas Statistics.
The following is a list of the Company's major generating stations at February 1, 1994:
Company's Share of Net Capability Station, Location and Percent Energy in Ownership Source Megawatts Huntley, Niagara River (100%) Coal 715
Dunkirk, Lake Erie (100%) Coal 570
Albany, Hudson River (100%) Oil/Natural Gas 400 Oswego, Lake Ontario (100%) (Unit 5) Oil 850
Oswego, Lake Ontario (76%) (Unit 6) Oil 646 Roseton, Hudson River (25%) Oil/Natural Gas 300
Nine Mile Point, Lake Ontario (100%) Nuclear 613 (Unit 1)
Nine Mile Point, Lake Ontario (41%) Nuclear 435 (Unit 2)
Central Hudson Gas and Electric Corporation, the operator of the Roseton plant, has agreed to acquire the Company's 25% interest in that plant in ten equal installments of 2.5% (30 MW) starting on December 31, 1994 and on each December 31 thereafter through and including December 31, 2003 at depreciated book value on each purchase date. As part of the agreement, the Company has the option to purchase up to a 25% (300 MW) interest in the Roseton plant in December 2004 at depreciated book value on such date. The agreement is subject to PSC approval.
As of December 31, 1993, the Company's electric transmission and distribution systems were comprised of 960 substations with a
rated transformer capacity of approximately 28,500,000 kva., about 9,200 circuit miles of overhead transmission lines, about 1,200 cable miles of underground transmission lines, about 110,900 conductor miles of overhead distribution lines and about 8,500 cable miles of underground distribution cables, only a part of such transmission and distribution lines being located on property owned by the Company. The electric system of the Company and Canadian Niagara Power Company, Limited is directly interconnected with other electric utility systems in Ontario, Quebec, New York, Massachusetts, Vermont and Pennsylvania, and indirectly interconnected with most of the electric utility systems in the United States.
Seasonal variation in electric customer load has been consistent. Over the last five years, the Company's maximum hourly demand has occurred in the winter months; however, on occasion summer peaks have approached the level of the winter peaks. The maximum simultaneous hourly demand (excluding economy and emergency sales to other utilities) on the electric system of the Company for the twelve months ended December 31, 1993 occurred on February 1, 1993 and was 6,191,000 kw., of which 527,000 kw. was generated in hydroelectric plants, 3,274,000 kw. was generated in thermal electric plants and 2,894,000 kw. (of which 1,120,000 kw. was firm) was purchased. Economy and emergency sales to other utilities on such date were 504,000 kw. The Company set an all-time electric peak load on January 19, 1994 of 6,458,000 kw.
The results of recent litigation in other jurisdictions indicate that a potentially substantial title problem may exist with respect to the Company's title and legal rights to gas and electric facilities on native American reservations across the Company's system. A longstanding Federal statute was interpreted to require Federal approval of all conveyances from native Americans in New York State. The issue is now being raised by certain native American tribes within the Company's service territory. The Company is unable to estimate any potential costs associated with this issue, although it believes any such cost would be recoverable in rates, based on traditional ratemaking principles.
NEW YORK POWER POOL. The Company, six other New York utilities and NYPA comprise the New York Power Pool, through which they coordinate the planning and operation of their interconnected electric production and transmission facilities in order to improve reliability of service and efficiency for the benefit of customers of their respective electric systems.
NUCLEAR PROPERTY INSURANCE. The Nine Mile Point Nuclear Site has $500 million primary nuclear property insurance with the Nuclear Insurance Pools (ANI/MRP). In addition, there is $800 million in excess of the $500 million primary nuclear insurance with the Nuclear Insurance Pools (ANI/MRP) and $1.4 billion, which is also in excess of the $500 million primary and the $800 million excess nuclear insurance, with Nuclear Electric Insurance Limited (NEIL). The total nuclear property insurance is $2.7 billion.
NEIL is a utility industry-owned mutual insurance company chartered in Bermuda. NEIL also provides insurance coverage against the extra expense incurred in purchasing replacement power during prolonged accidental outages. As summarized below, the insurance provides coverage for outages for 156 weeks after a 21-week waiting period.
Nine Mile Point Unit No. 1 Unit No. 2
Weekly indemnity for 52 weeks after 21 week waiting period $ 894,220 $ 773,582
Weekly indemnity for next 52 weeks 599,127 518,300 Weekly indemnity for next 52 weeks 599,127 518,300
Total aggregate payment available 108,808,648 94,129,464
NEIL insurance is subject to retrospective premium adjustment for which the Company could be assessed up to approximately $11.3 million per loss.
NUCLEAR LIABILITY INSURANCE. The Atomic Energy Act of 1954, as amended, requires the purchase of nuclear liability insurance from the Nuclear Insurance Pools in amounts as determined by the NRC. Presently, the Company maintains the required $200 million of nuclear liability insurance.
In August 1993, the statutory liability limits for the protection of the public under the Price-Anderson Amendments Act of 1988 (the Act) were further increased. With respect to a nuclear incident at a licensed reactor, the statutory limit, which is excess over the $200 million of nuclear liability insurance, was increased to approximately $8.8 billion. This limit would be funded by assessments of up to $75.5 million for each of the 116 presently licensed nuclear reactors in the United States, payable at a rate not to exceed $10 million per reactor per year. Such assessments are subject to periodic inflation indexing and to a 5% surcharge if funds prove insufficient to pay claims.
The Company's interest in Units 1 and 2 could expose it to a potential loss, for each accident, of $106.5 million through assessments of $14.1 million per year in the event of a serious nuclear accident at its own or another licensed U.S. commercial nuclear reactor. The amendments also provide, among other things, that insurance and indemnity will cover precautionary evacuations whether or not a nuclear incident actually occurs.
GAS SERVICE. The Company distributes gas purchased from suppliers and transports gas owned by others. As of December 31, 1993, the Company's natural gas system was comprised of approximately 7,400 miles of pipelines and mains, only a part of which is located on property owned by the Company. The maximum 24-hour coincidental send-out of natural gas by the Company for the twelve-months ended December 31, 1993 was 929,285 dekatherms
and occurred on February 6, 1993. A new maximum day gas send-out of 995,801 dekatherms was set on January 26, 1994.
SUBSIDIARIES. One of the Company's subsidiaries, Opinac Energy Corporation, a Canadian-based company, owns Canadian Niagara Power Company, Limited (CNP). CNP generates electricity at its Niagara Falls, Ontario hydro plant for the wholesale market and for its distribution system in Fort Erie, Ontario.
On June 30, 1993, the Company sold its interest in its Canadian oil and gas company, Opinac Exploration Limited, in order to streamline the Company's business and focus on its core electric and gas utility assets. The interest was sold for a cash consideration of $122 million Canadian (approximately $95 million U.S.). The sale did not have a material impact on the Company's results of operations or financial condition.
Another of the Company's subsidiaries, HYDRA-CO Enterprises, Inc., develops, owns and/or operates co-generation and small power plants both within and outside of the Company's service territory generally in conjunction with other parties. HYDRA-CO is involved in projects with total assets of more than $900 million. The Company has invested in HYDRA-CO, out of its retained earnings, approximately $80 million at December 31, 1993.
In January 1993, in a World Bank sponsored bid, a HYDRA-CO partnership was selected to negotiate final contracts on a 60- megawatt diesel power station in Kingston, Jamaica. HYDRA-CO is also working on a project in Canada.
HYDRA-CO now has interests in some 25 plants in operation or under construction, with an owned interest of about 300 megawatts. The plants use a variety of technologies powered by diverse fuels, including water, wood, coal, wind and natural gas. The diversity is by design, reflecting the Company's judgment on what is required to be a long-term developer, investor and operator in the independent power market.
MORTGAGE LIENS. Substantially all of the Company's operating properties are subject to a mortgage lien securing its mortgage debt.
Item 3.
Item 3. Legal Proceedings.
See also Item 8 -- Financial Statements and Supplementary Data, Note 8 and Item 1 -- Unregulated Generators.
The EPA advised the Company by letter that it is one of 833 PRPs under Superfund for the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky. The Company has contributed to a study of this site and estimates that the cost to the Company for its share of investigation and remediation based on its contribution factor of 1.3% would approximate $1 million, which the Company believes is recoverable in the ratesetting process.
On July 21, 1988, the Company received notice of a motion by Reynolds Metals Company to add the Company as a third party defendant in an ongoing Superfund lawsuit in Federal District Court, Northern District of New York. This suit involves PCB oil contamination at the York Oil Site in Moira, New York. Waste oil was transported to the site during the 1960's and 1970's by contractors of Peirce Oil Company (owners/operators of the site) who pick up waste oil at locations throughout Central New York, allegedly including one or more Company facilities.
Settlement negotiations, which had been in progress since 1988 with a group of defendants seeking "de minimis" status, were discontinued near the close of 1991, and the government's proposed settlement with a small group of major contributor defendants has been subject to severe objection from the remaining defendants, including the Company. These negotiations were related to costs associated with remediation of the "source control" operable unit at the York Oil Site.
Separate negotiations have resulted in an agreement to provide for the financing by a group of participating defendants of the "contamination pathways" operable unit, aimed at preventing the further spread of contamination. An Order on Consent in connection with this aspect of the litigation was lodged with the Court on May 15, 1992, and has been entered in settlement of this portion of the litigation.
On May 26, 1992, the Company was formally served in a Federal Court action initiated by the government against 8 additional defendants. Pursuant to the requirements of a case management order issued by the Court on March 13, 1992, the Company has also been served in related third- and fourth-party actions for contribution initiated by other defendants. All suits related to this matter have been consolidated into a single action.
The government issued a final settlement demand upon the Company in February 1994, including a settlement figure which was rejected by the Company. Litigation is now proceeding against the Company and several other PRP defendants which elected not to accept the terms of the government's final settlement demand. The Company will also participate in bringing additional PRP defendants not previously named by the government into the ongoing litigation as a means of assuring a more equitable allocation of remaining liability.
On March 22, 1993, a complaint was filed in the Supreme Court of the State of New York, Albany County against the Company and certain of its officers and employees. The plaintiff, Inter- Power of New York, Inc. ("Inter-Power"), alleges, among other matters, fraud, negligent misrepresentation and breach of contract in connection with the Company's alleged termination of a power purchase agreement in January 1993. The power purchase agreement was entered into in early 1988 in connection with a 200 MW cogeneration project to be developed by Inter-Power in Halfmoon, New York. The plaintiff is seeking enforcement of the original contract or compensatory and punitive damages on fourteen causes of action in an aggregate amount that would not exceed $1 billion, excluding pre-judgement interest.
The Company believes it has done no wrong, and intends to vigorously defend against this action. On May 7, 1993, the Company filed an answer denying liability and raising certain affirmative defenses. Thereafter, the Company and Inter-Power filed cross-motions for summary judgement. The court dismissed two of Inter-Power's fourteen causes of action but otherwise denied the Company's motion. The court also dismissed two of the Company's affirmative defenses and otherwise denied Inter-Power's cross-motion. Both parties have filed Notices of Appeals regarding these dismissals. Discovery is in progress. The ultimate outcome of the litigation cannot presently be determined.
On November 12, 1993, Fourth Branch Associates Mechanicville ("Fourth Branch") filed suit against the Company and several of its officers and employees in the New York Supreme Court, Albany County, seeking compensatory damages of $50 million, punitive damages of $100 million and injunctive and other related relief. The suit grows out of the Company's termination of a contract for Fourth Branch to operate and maintain a hydroelectric plant the Company owns in the Town of Halfmoon, New York. Fourth Branch's complaint also alleges claims based on the inability of Fourth Branch and the Company to agree on terms for the purchase of power from a new facility that Fourth Branch hoped to construct at the Mechanicville site. On January 3, 1994, the defendants filed a joint motion to dismiss Fourth Branch's complaint. This motion has yet to be decided. On March 16, 1994, the Court denied Fourth Branch's motion for preliminary judgment. The Company also notified Fourth Branch by letter dated March 1, 1994, that the Licensing Agreement between Fourth Branch and the Company is terminated. On March 15, 1994, Fourth Branch petitioned the FERC for Extraordinary Relief. The Company intends to oppose this petition before the FERC. The Company believes that it has substantial defenses to Fourth Branch's claims, but is unable to predict the outcome of this litigation.
Accordingly, no provision for liability, if any, that may result from either of these suits has been made in the Company's financial statements. Also see Item 1 -- "Unregulated Generators" for other suits involving unregulated generators.
On June 22, 1993, the Company and twenty other industrial entities and the owner/operator of the Pfohl Brothers Landfill near Buffalo, New York, were sued by a group of residents living in the vicinity of the landfill seeking compensation and damages for economic loss and property damages claimed to have resulted
from contamination emanating from the landfill. To date, no governmental action has been taken against the Company as a potentially responsible party (PRP). The Company has undertaken to establish defenses to the allegations in this lawsuit, and is investigating its alleged connection to the landfill to determine whether participation in an established and ongoing voluntary remedial program by identified PRPs is warranted. The Company is unable to predict the ultimate outcome of this proceeding.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
The Company has nothing to report for this item.
PART II
Item 5.
Item 5.
MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock and certain of its preferred series are listed on the New York Stock Exchange. The common stock is also traded on the Boston, Cincinnati, Midwest, Pacific and Philadelphia stock exchanges. Common stock options are traded on the American Stock Exchange. The ticker symbol is "NMK". Preferred dividends were paid on March 31, June 30, September 30 and December 31. Common stock dividends were paid on February 28, May 31, August 31 and November 30. The Company presently estimates that none of the 1993 common or preferred stock dividends will constitute a return of capital and therefore all of such dividends are subject to Federal tax as ordinary income. The table below shows quoted market prices and dividends per share for the Company's common stock:
Dividends Price Range Paid
1993 Per Share High Low
1st Quarter $.20 $22 3/8 $18 7/8 2nd Quarter .25 24 1/4 21 5/8
3rd Quarter .25 25 1/4 23 3/4 4th Quarter .25 23 7/8 19 1/4
1st Quarter $.16 $19 $17 5/8
2nd Quarter .20 19 1/4 17 1/2 3rd Quarter .20 20 1/2 18 7/8
4th Quarter .20 19 7/8 18 3/8
OTHER STOCKHOLDER MATTERS: The holders of Common Stock are entitled to one vote per share and may not cumulate their votes for the election of Directors. Whenever dividends on Preferred Stock are in default in an amount equivalent to four full quarterly dividends and thereafter until all dividends thereon are paid or declared and set aside for payment, the holders of such stock can elect a majority of the Board of Directors.
Whenever dividends on any Preference Stock are in default in an
amount equivalent to six full quarterly dividends and thereafter until all dividends thereon are paid or declared and set aside for payment, the holders of such stock can elect two members to the Board of Directors. No dividends on Preferred Stock are now in arrears and no Preference Stock is now outstanding. Upon any dissolution, liquidation or winding up of the Company's business, the holders of Common Stock are entitled to receive a pro rata share of all of the Company's assets remaining and available for distribution after the full amounts to which holders of Preferred and Preference Stock are entitled have been satisfied. The indenture securing the Company's mortgage debt provides that surplus shall be reserved and held unavailable for the payment of dividends on Common Stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25% of depreciable property as defined therein. Such provisions have never resulted in a restriction of the Company's surplus. At year end, about 109,000 stockholders owned common shares of the Company and about 5,000 held preferred stock. The chart below summarizes common stockholder ownership by size of holding:
SIZE OF HOLDING (SHARES) TOTAL STOCKHOLDERS TOTAL SHARES HELD
1 to 99 43,269 1,401,921
100 to 999 59,329 16,476,333
1,000 or 6,742 124,548,803 more __________________ __________________
109,340 142,427,057 ================== ==================
Item 6.
Item 6.
SELECTED FINANCIAL DATA
As discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes to Consolidated Financial Statements, certain of the following selected financial data may not be indicative of the Company's future financial condition or results of operations.
Item 7.
Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ----------------------------------------------------------- AND RESULTS OF OPERATIONS ------------------------- Overview of 1993 ---------------- Earnings improved to $240.0 million or $1.71 per share as compared to $219.9 million or $1.61 per share in 1992, principally as a result of rate increases to electric and gas customers. Although earnings improved, the Company's earned return on equity of 10.2% was below the allowed return on utility operations of 11.4%. Expectations for 1994 earnings indicate only a slight improvement without an increase in electric base rates and a modest increase in gas rates. Cost sharing mechanisms for industrial customer discounts and the potential for loss of industrial customers in 1994 will place earnings at additional risk. Even with modest earnings growth, the Company's relatively low payout ratio, as compared to the rest of the electric and gas utility industry, permitted an increase in the common stock dividend to an annual rate of $1.00 from $.80, or 25% in 1993. The Company is increasingly challenged to maintain its financial condition under traditional regulation and in the face of expanding competition. While utilities across the nation must address these concerns to varying degrees, the Company may be more vulnerable than others to competitive threats. The following sections present an assessment of competitive threats and steps being taken to improve the Company's strategic and financial position. Rating agencies, which evaluate the credit-worthiness of various securities, including the Company's, have expressed heightened concern about the future business prospects of the utility industry. Standard & Poors Corporation includes the Company in its "Below Average," or lowest rated group in its assessment of business position and has recently reduced the Company's credit ratings. A more extensive discussion of rating agency views is included under "Liquidity and Capital Resources."
Changing Competitive Environment -------------------------------- In 1993, the Company continued to address concerns relating to increasing competition in the utility industry. The enactment of the 1992 Federal Energy Policy Act (Act) has accelerated the trend toward competition and deregulation in the wholesale market (principally sales to others who will resell power to the retail market), by creating a class of generators, called Exempt Wholesale Generators (EWGs), which are able to sell power without the regulatory constraints placed on generators such as the Company. To further encourage wholesale competition, the Act opens access to utility transmission systems. The rules by which
such access will
be prioritized and priced have not been issued, and the potential impact on the Company, as owner and lessee of significant transmission assets, cannot be determined. Although the Act prohibits direct sales to a utility's retail customer, New York State retains the right to allow retail competition. In view of these developments, the Company undertook a Comprehensive Industry Restructuring and Competitive Assessment for the year 2000 (CIRCA 2000) to evaluate the means by which retail competition may develop and the Company's ability to respond to the associated threats and opportunities. While the future of wholesale and retail markets is uncertain, the Company determined through its CIRCA 2000 study that it must (a) reduce its total cost of doing business and (b) improve its responsiveness to changing business conditions. Under the terms of its 1994 Rate Agreement, the Company is required to file a "competitiveness" study with the New York State Public Service Commission (PSC) by April 1, 1994.
Cost Control ------------
Cost control extends beyond those areas traditionally thought to be under utility control, to all aspects of utility pricing, including unregulated generator purchases, tax burdens and mandated social and environmental programs. As a step towards improving its competitive position, in early 1993 the Company announced its intent to reduce its workforce by at least 1,400 positions by the end of 1995. While considerable progress was made toward this goal in 1993, rapidly changing competitive pressures made it clear that deeper cuts will be necessary. Consequently, in January 1994, the Company decided that further and faster workforce reductions would be necessary and announced a layoff over the next several months of approximately 900 employees, increasing the total reduction to approximately 1,500. Further reductions may be necessary.
Price Responsiveness --------------------
As described in more detail below under "1995 Five-Year Rate Plan Filing," the Company filed a five-year rate plan which would establish prices for 1995 and a method by which prices would be set for 1996 through 1999. The plan would cap the average annual rate at approximately the annual rate of inflation, but would also allow greater flexibility for Company pricing decisions within each rate class (e.g., residential, commercial and industrial) subject to the overall cap. The Company could, at its discretion, offer discounts to customers that might be able to leave the Company's system, but would in turn be limited to how much, if any, of the discounts could be recouped from other
classes. While the focus of pricing innovation has principally been to retain industrial customers, the Company is also evaluating innovative pricing alternatives for residential and commercial customers.
The flexibility and responsiveness of the plan to changing business conditions is designed to better position the Company to meet the challenges of increasing competition to protect shareholder value. However, the Company must be disciplined in its spending based upon its projections of price increases, if any, sales and potential discounts during the five-year period. The financial success of the Company under its price indexing rate proposal is dependent on the ability of the Company to control all of its costs. Because price indexing begins with base prices set for 1995, inclusive of such things as fuel, purchased power and taxes, the establishment of an appropriate base is critical to the financial results of the Company during the five-year period. An ongoing generic investigation is being conducted by the PSC into the issue of how to design rates for customers with competitive electric and gas service alternatives. The Company is developing proposals to further permit the necessary rate flexibility to respond to competitive conditions in the industry.
UNREGULATED GENERATORS
In recent years, a leading factor in the increases in customer bills and deterioration of the Company's competitiveness is the requirement to purchase power from unregulated generators at prices in excess of the Company's internal cost of production and in volumes greater than the Company's needs. The Public Utility Regulatory Policies Act of 1978 (PURPA), New York State Law and PSC policies and procedures have collectively required that the Company purchase this power from qualified unregulated generators. The price used in negotiating purchased power contracts with unregulated generators (Long Run Avoided Costs or LRACs) is established periodically by the PSC. Until repeal in 1992, the statute which governed many of these contracts had established the floor on avoided costs at $0.06/kwh (the Six-Cent Law). The Six-Cent Law, in combination with other factors, attracted large numbers of unregulated generators projects to New York State and, in particular, to the Company's service territory. As of December 31, 1993, 147 of these unregulated generators with a combined capacity of 2,253 MW were on line and selling power to the Company. The following table illustrates the actual and estimated growth in capacity, payments and relative magnitude of unregulated generator purchases compared to Company requirements:
ACTUAL _____________________________
1991 1992 1993 ---- ---- ---- MW's 1,027 1,549 2,253
Percent of Total Capability 13% 19% 25%
Payments $ 268 $ 543 $ 736 (millions) Percent of Total Fuel and Purchased Power Costs 32% 56% 67%
ESTIMATED
_________________________________________ 1994 1995 1996 1997 1998 ---- ---- ---- ---- ----
MW's 2,354 2,391 2,391 2,391 2,391
Percent of Total Capability 27% 27% 27% 28% 28% Payments $ 932 $1,057 $1,111 $1,174 $1,220 (millions)
Percent of Total Fuel and Purchased 70% 76% 77% 77% 77% Power Costs
Most of the additional capacity will be grandfathered under the Six-Cent Law. Without any other actions, the Company's installed capacity reserve margin was projected to grow to 40%- 50% before declining in the late 1990's, as compared to the minimum mandated requirement of 18%. While the Company favors the availability of unregulated generators in satisfying its generating needs, the Company believes it is paying a premium to unregulated generators for energy it does not currently need. The Company has initiated a series of actions to address this situation but expects in large part that the higher costs will continue. On August 18, 1992, the Company filed a petition with the PSC which calls for the implementation of "curtailment procedures." Under existing Federal Energy Regulatory Commission (FERC) and PSC policy, this petition would allow the Company to limit its purchases from unregulated generators when demand is low. While the Administrative Law Judge has submitted recommendations to the PSC, the Company cannot now predict the outcome of this case. Also, the Company has commenced settlement discussions with certain unregulated generators regarding curtailments. On October 23, 1992, the Company also petitioned the PSC to order unregulated generators to post letters of credit or other firm security to protect ratepayers' interests in advance payments made in prior years to these generators. The PSC dismissed the original petition without prejudice, which the Company believes would permit reinstatement of its request at a later date. The Company is conducting discussions with unregulated generators representing over 1,600 MW of capacity, addressing the issues contained in its petitions. On February 4, 1994 the Company notified the owners of nine projects with contracts that provide for advance payments of the Company's demand for adequate assurance that the owners will perform all of their future repayment obligations, including the obligation to deliver electricity in the future at prices below the Company's avoided cost and to repay any advance payment which remains outstanding at the end of the contract. The projects at issue total 426 MW. The Company's demand is based on its assessment of the amount of advance payments to be accumulated under the terms of the contracts, future avoided costs and future operating costs of the projects. The Company cannot predict the outcome of this notification. The Company and certain of its officers and employees have been named in complaints resulting from the alleged termination, among other matters, of purchase power contracts with Inter-Power of New York, Inc. and Fourth Branch Associates Mechanicville. The Company believes it has substantial defenses to both complaints but is unable to predict the outcome of these matters and, accordingly, has not established a provision for liability, if any, in the Company's financial statements.
ASSET MANAGEMENT STUDIES - FOSSIL The Company continually examines its competitive situation and future strategic direction. Among other things, it has studied the economics of continued operation of its fossil-fueled generating plants, given current forecasts of excess capacity. Growth in unregulated generator supply sources and compliance requirements of the Clean Air Act are key considerations in evaluating the Company's internal generation needs. While the Company's coal-burning plants continue to be cost advantageous, certain older units and certain gas/oil-burning units are being carefully assessed to evaluate their economic value and estimated remaining useful lives. Due to projected excess capacity, the Company plans to retire or put certain units in long-term cold standby. A total of 340 MW's of aging coal fired capacity is to be retired by the end of 1999 and 850 MW's of oil fired capacity is to be placed in long-term cold standby in 1994. The Company is also continuing to evaluate under what circumstances the standby plants would be returned to service, but barring unforeseen circumstances it is not likely that a return would occur before the end of 1999. This action will permit the reduction of operating costs and capital expenditures for retired and standby plants. The Company believes that the remaining investment in these plants of approximately $300 million at December 31, 1993, will be fully recoverable in rates.
ASSET MANAGEMENT STUDIES - NINE MILE POINT NUCLEAR STATION UNIT NO.1
Under the terms of an earlier regulatory agreement, the Company agreed to prepare and update studies of the advantages and disadvantages of continued operation of Nine Mile Point Nuclear Station Unit No. 1 (Unit 1). In the November 1992 study, the continued operation of the unit under an "improved performance case" was expected to provide a net present value benefit in excess of $100 million. The unit operated within the parameters of the improved performance case in 1993 and the Company believes that continued operation of the Unit is warranted. The Company's net investment in Unit 1 is approximately $580 million and the estimated cost to decommission the Unit based on the Company's 1989 study is $257 million in 1993 dollars. The next update is due to be submitted to the PSC in late 1994. See Item 8.
Item 8. Financial Statements and Supplementary Data - Electric and Gas Statistics - Gas Sales.) The increase in 1993 includes a 1.8% increase in residential sales, a 6.5% increase in commercial sales, which were strongly influenced by weather, and a 143.6% increase in industrial sales. The Gas SBU has added 19,000 new customers since 1991, primarily in the residential class, an increase of 3.9%, and expects a continued increase in new customers in 1994. During 1993, there also was a shift from the transportation sales class to the industrial sales class resulting from the implementation of a stand-by industrial rate. The increase for 1992 included a 12.0% increase in sales in the residential class and a 10.2% increase in sales in the commercial class, reflecting milder weather factors, offset by a 2.2% decrease in sales in the industrial class reflecting the recession and fuel switching. In 1993, the Company transported 67.8 million dekatherms (a slight increase from 1992) for customers purchasing gas directly from producers but expects a substantial increase in such transportation volumes in 1994 leading to a forecast increase in total gas deliveries in 1994 of 13.2% above 1993 weather-adjusted deliveries. Public sales are expected to decrease almost 1.0%.
Factors affecting these forecasts include the economy, the relative price differences between oil and gas in combination with the relative availability of each fuel, the expanded number of cogeneration projects served by the Company and increased marketing efforts. As authorized by the PSC, the Company accrued $20.9 million of unbilled gas revenues as of December 31, 1993, which have been deferred and are expected to be used to reduce future gas revenue requirements. Changes in gas revenues and dekatherm sales by customer group are detailed in the table below:
The cost of gas purchased increased 13.6% in 1993 and 16.1% in 1992 after having decreased 13.4% in 1991. The cost fluctuations generally correspond to sales volume changes, particularly in 1993, as spot market sales activity increased. The Company sold 13.2 million dekatherms on the spot market in 1993 as compared to 1.1 million in 1992. This activity accounted for two-thirds of the 1993 purchased gas expense increase. The purchase gas cost increase associated with purchases for ultimate consumers in 1993 resulted from a 8.7% increase in dekatherms purchased combined with a 2.1% increase in rates charged by suppliers offset by a $17.8 million decrease in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause. The increase associated with purchases for ultimate consumers for 1992 was the result of a 10.0% increase in dekatherms purchased, a 2.7% increase in rates charged by the Company's suppliers, combined with an increase of $5.2 million in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause. The Company's net cost per dekatherm purchased for sales to ultimate consumers decreased to $3.34 in 1993 from $3.47 in 1992 which was higher than the net cost of $3.31 in 1991. Through the electric and purchased gas adjustment clauses, costs of fuel, purchased power and gas purchased, above or below the levels allowed in approved rate schedules, are billed or credited to customers. The Company's electric fuel adjustment clause provides for partial pass-through of fuel and purchased power cost fluctuations from those forecast in rate proceedings, with the Company absorbing a specific portion of increases or retaining a portion of decreases to a maximum of $15 million per rate year. The amounts absorbed in 1991 through 1993 are not material. OTHER OPERATION expense, including wage increases in each year, increased $73.2 million or 9.8% in 1993 as compared to increases of 5.9% in 1992 and 7.8% in 1991. The 1993 increase is otherwise due to an increase in DSM program expenses, nuclear expenses related to increased production at Unit 1 and Unit 2 and refueling outages, amortization of regulatory assets deferred in prior years, increased recognition of other postretirement benefit costs and inflation. The 1992 increase was also due to increased computer software expenses and higher medical benefits paid. The 1991 increase was also due to increases in bad debt expense, environmental site investigation and remediation costs, DSM program expenses and research and development costs. Bad debts have increased during the recession and increased collection efforts and innovative collection management also contributed to the increased writeoffs. MAINTENANCE EXPENSE increased 4.5% in 1993 principally due to nuclear expenses incurred during the refueling outages at Unit 1 and Unit 2 offset by lower expenses on the fossil stations because of economically driven shutdowns at the Oswego and Albany plants as described above. Maintenance expense decreased
slightly in 1992 as increased costs associated with outages at Unit 1 and refueling
Unit 2 were offset by reduced transmission line maintenance expenses. Maintenance expense decreased 1.8% in 1991 due to lower Unit 2 maintenance partly offset by transmission line ice storm damage. DEPRECIATION AND AMORTIZATION expense for 1993 and 1992 increased 0.9% and 5.9% over 1992 and 1991, respectively. The increase is attributable to normal plant growth. NET FEDERAL AND FOREIGN INCOME TAXES for 1993 decreased due to the tax benefit derived from the Company's Canadian subsidiary upon the sale of its oil and gas investments. Net Federal and foreign income taxes for 1992 and 1991 increased because of increases in book taxable income. The increase in OTHER TAXES in the three-year period is due principally to higher property taxes resulting from property additions combined with increased payroll and revenue-based taxes. OTHER ITEMS, NET, excluding Federal income taxes and allowance for funds used during construction (AFC), increased $23.4 million in 1993 and decreased $2.7 million in 1992. The 1993 increase was the effect of the recording in 1992 of a $45 million reserve against the carrying value of Canadian subsidiary oil and gas reserves, offset in part by the recognition of the Company's share of Unit 2 contractor litigation proceeds and increased earnings by the Company's independent power subsidiary. The 1991 decrease is primarily the result of a similar $22.7 million write-down of oil and gas reserves. Net INTEREST CHARGES decreased $9.3 million in 1993 and $10.9 million in 1992, primarily as the result of the refinancing of debt at lower interest rates. Dividends on preferred stock decreased $4.7 million, $3.9 million and $1.9 million in 1993, 1992 and 1991, respectively, because of reductions in amounts of stock outstanding. The weighted average long-term debt interest rate and preferred dividend rate paid, reflecting the actual cost of variable rate issues, changed to 7.97% and 6.70%, respectively, in 1993, from 8.29% and 7.04%, respectively, in 1992, and from 8.74% and 7.53%, respectively, in 1991.
EFFECTS OF CHANGING PRICES
The Company is especially sensitive to inflation because of the amount of capital it typically needs and because its prices are regulated using a rate base methodology that reflects the historical cost of utility plant. The Company's consolidated financial statements are based on historical events and transactions when the purchasing power of the dollar was substantially different from the present. The effects of inflation on most utilities, including the Company, are most significant in the areas of depreciation and utility plant. The Company could not replace its utility plant and equipment for the historical cost value at which they are
recorded on the Company's books. In addition, the Company would not replace these assets with identical ones due to technological advances and regulatory changes that have occurred. In light of these considerations, the
depreciation charges in operating expenses do not reflect the current cost of providing service. The Company, however, will seek additional revenue or reallocate resources to cover the costs of maintaining service as assets are replaced or retired.
FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES ___________________________________________________
FINANCIAL POSITION
The Company's capital structure at December 31, 1993 was 54.6% long-term debt, 6.5% preferred stock and 38.9% common equity, as compared to 56.4%, 7.4% and 36.2%, respectively, at December 31, 1992. Book value of the common stock was $17.25 per share at December 31, 1993 as compared to $16.33 per share at December 31, 1992. The improvement in the capital structure and book value is attributable primarily to reinvested earnings and sales of common stock, although preferred stock redemptions also contributed. The 1993 ratio of earnings to fixed charges was 2.31 as compared to an average ratio nationally of approximately 3.0 for electric and gas utilities. The ratios of earnings to fixed charges for 1992 and 1991 were 2.24 and 2.09, respectively. Firms which publish securities ratings have begun to impute certain items into the Company's interest coverage calculations and capital structure, the most significant of which is the inclusion of a "leverage" factor for unregulated generator contracts. These firms believe that the financial structure of the unregulated generators (which typically have very high debt- to-equity ratios) and the character of their power purchase agreements increase the financial risk of utilities. The Company's reported interest coverage and debt-to-equity ratios have recently been discounted by varying amounts for purposes of establishing credit ratings. Because of growing commitments for unregulated generator purchases, the imputation can have a material negative impact on the Company's financial indicators.
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS -------------------------------------------
The Company's total capital requirements consist of amounts for the Company's construction program, working capital needs, maturing debt issues and sinking fund provisions on preferred stock, and have been affected by the Company's efforts in recent years to lower capital costs through refinancing. Annual expenditures for the years 1991 to 1993 for construction and
nuclear fuel, including related AFC and overheads capitalized, were $522.5 million, $502.2 million and $519.6 million, respectively. The 1994 estimate for construction additions, including overheads capitalized, nuclear fuel and AFC, is approximately $510 million, of which approximately 90% is expected to be funded by cash provided from operations. Mandatory and optional debt and
preferred stock retirements and other requirements are expected to add approximately another $545 million (expected to be refinanced from external sources) to the Company's capital requirements, for a total of $1,055 million. Current estimates of total capital requirements for the years 1995 to 1998 decrease considerably to $442, $474, $401 and $483 million, respectively, of which $363, $405, $351, and $413 million relates to expected construction additions. The reductions are linked to the completion of debt refinancings as well as the reduced construction spending. The estimate of construction additions included in capital requirements for the period 1995 to 1998 will be reviewed by management during 1994 with the objective of further reducing these amounts where possible. The provisions of the Clean Air Act Amendments of 1990 (Clean Air Act) are expected to have an impact on the Company's fossil generation plants during the period through 2000 and beyond. The Company is studying options for compliance with Phase I of the Clean Air Act, which becomes effective January 1, 1995 and continues through 1999. With respect to meeting sulfur dioxide emission limits in Phase I of the Clean Air Act, only Dunkirk units 3 and 4 are affected. Options under evaluation to comply with sulfur dioxide emission limits at these units include switching to a lower sulfur coal, reducing utilization of the units, and the purchase of emission allowances. The Company also must lower its nitrous oxide (NOx) emissions in Phase I. The Company spent approximately $19 million in 1993 and has included $46 million in its construction forecast for 1994 through 1997 to make combustion modifications at its fossil fired plants including the installation of low NOx burners at the Dunkirk and Huntley plants. With respect to Phase II, greater reductions will be required for both sulfur dioxide and NOx emissions. The Company has conducted studies on its fossil fired units to examine compliance options. Preliminary estimates for Phase II compliance anticipate approximately $124 million in capital costs and $21 million in annual expenses. The Company believes that these capital costs, as well as incremental annual operating and maintenance costs and fuel costs, will be recoverable from ratepayers.
LIQUIDITY AND CAPITAL RESOURCES
Cash flows to meet the Company's requirements for operating,
investing and financing activities during the past three years are reported in Item 8. Financial Statements and Supplementary Data in the Consolidated Statements of Cash Flows. During 1993, the Company raised approximately $892 million from external sources, consisting of $635 million of First Mortgage Bonds, $116.7 million of common stock and a net increase of $140.3 million of short and intermediate term debt. The proceeds of the $635 million of First Mortgage Bonds were used to provide for the early redemption of approximately $602 million of higher coupon First Mortgage Bonds. The Company continues to investigate options 35
to reduce its embedded cost of long-term debt by taking advantage of current lower interest rates. External financing of approximately $750 million is expected for 1994, of which approximately $545 million would be used for scheduled and optional refundings. This external financing is projected to consist of $425 million in long-term debt, $200 million from sales of common stock, $200 million of preferred stock and a $75 million decrease in short-term debt. Common stock sales at this amount will require shareholder approval to increase the Company's common shares authorized and are consistent with management's goal to improve the Company's capital structure. External financing plans for 1995 to 1998 are subject to periodic revision as underlying assumptions are changed to reflect developments; still, the Company currently anticipates external financing over this period will diminish in the aggregate to approximately $420 million. Substantially all financing is for refunding, as cash provided by operations is expected to continue to provide funds for the Company's construction program. The ultimate level of financing during this four year period will reflect, among other things, the Company's competitive positioning, uncertain energy demand due to economic conditions and capital expenditures relating to distribution and transmission load reliability projects, as well as expansion of the gas business. Environmental standards compliance costs, the effects of rate regulation and various regulatory initiatives, the level of internally generated funds and dividend payments, the availability and cost of capital and the ability of the Company to meet its interest and preferred stock dividend coverage requirements, to satisfy legal requirements and restrictions in governing instruments and to maintain an adequate credit rating also will impact the amount and type of future external financing. The Company has initiated a ten to fifteen year site investigation and remediation program that seeks a) to identify and remedy environmental contamination hazards in a proactive and cost-effective manner and b) to ensure financial participation by other responsible parties. The program involves sponsorship of investigation, remediation and selected research projects for 42 Company-owned waste sites and, where appropriate, participation in remedial action at 40 waste sites owned by others but where the Company is one of a number of potentially responsible parties (PRP).
The Company has accrued a minimum liability of $240 million at December 31, 1993 for its estimated liability for investigation and remediation of certain Company-owned and Company-associated hazardous waste sites, which represents the low end of a range of estimates developed from the Company's ongoing site investigation and remediation program. Of the $240 million accrued, $210 million relates to Company-owned sites and $30 million represents the Company's estimated cost contribution to sites with which it may be associated. The accrual of the Company's cost contribution for PRP sites is derived by estimating the total cost of clean-up of the sites and then applying a contribution factor to the estimated
total cost. Total costs to investigate and remediate sites with which the Company is associated as a PRP are estimated to be approximately $590 million. The Company believes that costs incurred in the investigation and remediation process are recoverable in the ratesetting process as currently in effect. (See Item 8. Financial Statements and Supplementary Data - Note 8 under "Environmental Contingencies"). Rate agreements since 1991 have included a recovery mechanism and an annual allowance for costs expected to be incurred for waste site investigation and remediation. The recovery mechanism provides that expenditures over or under the allowance be deferred for future rate consideration. The Company does not expect these costs to impact external financing, although any such impact is dependent upon the timing of expenditures and associated recovery. The Company also is undertaking environmental compliance audits at many of its facilities. These audits may result in additional expenditures for investigation and remediation that the Company cannot currently estimate. The Nuclear Regulatory Commission (NRC) issued regulations in 1988 requiring owners of nuclear power plants to place costs associated with decommissioning activities for contaminated portions of nuclear facilities into an external trust. Further, the NRC established guidelines for determining minimum amounts that must be available in the trust for these specified decommissioning activities at the time of decommissioning. Applying the NRC guidelines, the Company has estimated that the minimum requirements for Unit 1 and its share of Unit 2, respectively, will be $372 million and $169 million in 1993 dollars. The Company is seeking an increase in its rate allowance for Unit 1 and Unit 2 decommissioning in 1995 to reflect new NRC minimum requirements. Amounts collected for the NRC minimum are being placed in an external trust. (See Item 8. Financial Statements and Supplementary Data - Note 7 under "Nuclear Plant Decommissioning"). The Company believes that traditionally available sources of financing should be sufficient to satisfy the Company's external financing needs during the period 1994 through 1998. As of December 31, 1993, the Company could issue an additional $1,899 million aggregate principal amount of First Mortgage Bonds. This
includes approximately $921 million from retired bonds without regard to an interest coverage test and approximately $978 million supported by additional property currently certified and available, assuming an 8% interest rate, under the applicable tests set forth in the Company's mortgage trust indenture. The Company also has authorized unissued Preferred Stock totaling approximately $390 million and a total of $200 million of Preference Stock is currently authorized for sale. The Company will continue to explore and use, as appropriate, other methods of raising funds. Ordinarily, construction related short-term borrowings are refunded with long-term securities on a regular basis. This approach generally results in the Company showing a working capital deficit. Working capital deficits also may be temporarily created
because of the seasonal nature of the Company's operations as well as timing differences between the collection of customer receivables and the payment of fuel and purchased power costs. However, the Company has sufficient borrowing capacity to fund such a deficit as necessary. Bank credit arrangements which, at December 31, 1993, totaled $461 million are used by the Company to enhance flexibility as to the type and timing of its long-term security sales. The Company's charter restricts the amount of unsecured indebtedness that may be incurred by the Company to 10% of consolidated capitalization plus $50 million. The Company has not reached this restrictive limit. The Company's securities ratings at February 23, 1994, were:
Secured Preferred Commercial Debt Stock Paper
Standard & Poors Corporation BBB- BB+ A-3 Moody's Investors Service Baa2 baa3 P-2 Duff & Phelps BBB BBB- Not applicable Fitch Investors Service BBB BBB- Not applicable
The security ratings set forth above are subject to revision and/or withdrawal at any time by the respective rating organizations and should not be considered a recommendation to buy, sell or hold securities of the Company. The Company's cost of financing and access to markets could be negatively affected by events outside its control. The Company's securities ratings could be negatively affected by, among other things, the continued growth in and its reliance on unregulated generator purchase power requirements. Rating
agencies have expressed concern about the impact on Company financial indicators and risk that unregulated generator financial leveraging may have. On October 27, 1993, Standard & Poors Corporation (S&P) issued their revised electric utility financial ratio benchmarks. S&P has made its benchmarks more stringent to counter increasing business risk caused by accelerating competition in the electric power industry as well as environmental and nuclear operating cost pressure and slow earnings growth prospects. S&P also observed that because of the more disparate business prospects for electric utilities, it was segregating companies into groups based upon competitive position, business prospects and predictability of cash flows to withstand greater financial risks. The Company was included in the "Below Average," or lowest rated group in S&P's assessment of business position. Based on this criteria, on February 23, 1994, S&P reduced the Company's credit ratings as disclosed above. In addition, S&P announced that although the
Company has taken steps to control operating expenses and limit exposure to unregulated generator costs and to otherwise improve revenues, the ratings outlook for the Company would remain negative pending demonstrated financial improvement. The Company is taking a number of steps to address this matter as stated elsewhere in this report.
Moody's Investors Service also has indicated that it expects utility bond ratings will come under increasing pressure over the next three to five years because of changes in the business environment although it indicated in February 1994 that it would maintain current ratings on all existing debt.
These developments may increase the cost to issue new securities.
Item 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. Financial Statements
Report of Management
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for each of the three years in the period ended December 31, 1993.
Consolidated Balance sheets at December 31, 1993 and 1992.
Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 1993.
Notes to Consolidated Financial Statements.
Financial Statement Schedules -
The following Financial Statement Schedules are submitted as part of Item 14, Exhibits, Financial Statement Schedules, and Reports on Form 8-K, of this Report. (All other Financial Statement Schedules are omitted because they are not applicable, or the required information appears in the Financial Statements or the Notes thereto.)
Schedule V - Utility Plant
Schedule VI - Accumulated Depreciation and Amortization
Schedule VIII - Valuation and Qualifying Accounts and Reserves
Schedules IX - Short-term Borrowings
Schedule X - Supplementary Income Statement Information
REPORT OF MANAGEMENT ____________________
The consolidated financial statements of Niagara Mohawk Power Corporation and its subsidiaries were prepared by and are the responsibility of management. Financial information contained elsewhere in this Annual Report is consistent with that in the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls, which is designed to provide reasonable assurance, on a cost effective basis, as to the integrity, objectivity and reliability of the financial records and protection of assets. This system includes communication through written policies and procedures, an organizational structure that provides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program. In addition, the Company has a Corporate Policy Register and a Code of Business Conduct which supply employees with a framework describing and defining the Company's overall approach to business and requires all employees to maintain the highest level of ethical standards as well as requiring all management employees to formally affirm their compliance with the Code. The financial statements have been audited by Price
Waterhouse, the Company's independent accountants, in accordance with generally accepted auditing standards. In planning and performing their audit, Price Waterhouse considered the Company's internal control structure in order to determine auditing procedures for the purpose of expressing an opinion on the financial statements, and not to provide assurance on the internal control structure. The independent accountants' audit does not limit in any way management's responsibility for the fair presentation of the financial statements and all other information, whether audited or unaudited, in this Annual Report. The Audit Committee of the Board of Directors, consisting of five outside directors who are not employees, meets regularly with management, internal auditors and Price Waterhouse to review and discuss internal accounting controls, audit examinations and
financial reporting matters. Price Waterhouse and the Company's internal auditors have free access to meet individually with the Audit Committee at any time, without management being present.
REPORT OF INDEPENDENT ACCOUNTANTS -------------------------------- To the Stockholders and Board of Directors of Niagara Mohawk Power Corporation
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income and retained earnings and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes 1 and 5 to the financial statements, the Company adopted the provisions of Statements of Financial Accounting Standards No. 109, Accounting for Income Taxes, and No. 106, Accounting for Postretirement Benefits Other Than Pensions, respectively, in 1993. As discussed in Note 8, the Company is a defendant in lawsuits relating to its actions with respect to certain purchased power contracts. Management is unable to predict whether the resolution of these matters will have a material effect on its financial position or results of operations. Accordingly, no provision for any liability that may result upon resolution of this uncertainty has been made in the accompanying 1993 financial statements.
/s/ PRICE WATERHOUSE --------------------
Syracuse, New York January 27, 1994
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES ---------------------------------------------------------
Consolidated Statements of Income and Retained Earnings -------------------------------------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ------------------------------------------
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is subject to regulation by the PSC and FERC with respect to its rates for service under a methodology which establishes prices based on the Company's cost. The Company maintains its accounting records on the basis of such regulation, which it believes complies with generally accepted accounting principles. The Company's accounting policies conform to generally accepted accounting principles, as applied to regulated public utilities, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Principles of Consolidation: The consolidated financial statements include the Company and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated. Assets and liabilities of its Canadian energy subsidiary, Opinac Energy Corporation, are translated into U.S. dollars at the exchange rate in effect at the balance sheet date. Revenue and expense accounts are translated at the average exchange rate in effect during the year. Currency translation adjustments are recorded as a component of equity and do not have a significant impact on financial condition. The results of operations of the Company's oil and gas subsidiary are included in other income and deductions on the Consolidated Statements of Income and Retained Earnings. Subsidiary oil and gas properties: During 1993, the Company sold its interest in its Canadian oil and gas company, Opinac Exploration Limited. This was done to streamline the Company's business and focus on its core electric and gas utility assets. The sale did not have a material impact on the Company's results of operations or financial condition. The Company retained its ownership of Opinac Energy Corporation and the Company's subsidiary, Canadian Niagara Power Limited, an Ontario electric utility company. The net book value of oil and gas properties and equipment, less related deferred income taxes, was limited to the sum of the after tax present value of net revenues from proved oil and gas reserves and the lower of cost or fair value of unproved properties. The calculation of future net revenues was based upon prices and costs in effect at the end of the year. Based upon the calculation of this "ceiling test" at December 31, 1991 and March 31, 1992, the Company recorded reserves of approximately $23 million and $21 million, or an after tax effect of $.07 and $.09 per share, respectively. At December 31, 1992, the Company recorded a valuation reserve of $24 million, or an after tax effect of $.09 per share, in light of a significant decline in previous estimates of proved reserves as indicated by lower than expected production volumes. The net investment in such properties was approximately $101 million at December 31, 1992. Utility Plant: The cost of additions to utility plant and of
replacements of retirement units of property is capitalized. Cost includes direct material, labor, overhead and AFC. Replacement of minor items of utility plant and the cost of current repairs and maintenance is charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Allowance for Funds Used During Construction: The Company capitalizes AFC in amounts equivalent to the cost of funds devoted to plant under construction. AFC rates are determined in accordance with FERC and PSC regulations. The AFC rate in effect at December 31, 1993 was 6.5%. AFC is segregated into its two components, borrowed funds and other funds, and is reflected in the Interest Charges section and the Other Income and Deductions section, respectively, of the Consolidated Statements of Income. In 1985, pursuant to PSC authorization, the Company discontinued accruing AFC on construction work in progress (CWIP) for which a cash return was being allowed through inclusion in rate base of that portion of the investment in Unit 2. Amounts equal to Unit 2's AFC which was no longer accrued have been accumulated in deferred debit and credit accounts up to the commercial operation date of Unit 2, (each amounting to $239.9 million at December 31, 1993 and 1992), and await future ratemaking disposition by the PSC. A portion of the deferred credit could be utilized to reduce future revenue requirements over a period shorter than the life of Unit 2, with a like amount of deferred debit amortized and recovered in rates over the remaining life of Unit 2. Depreciation, Amortization and Nuclear Generating Plant Decommissioning Costs: For accounting and regulatory purposes, depreciation is computed on the straight-line basis using the average or remaining service lives by classes of depreciable property. The total provision for depreciation and amortization, including amounts charged to clearing accounts, was $277.9 million for 1993, $275.3 million for 1992, and $260.2 million for 1991. The percentage relationship between the total provision for depreciation and average depreciable property was 3.2% for 1993, 3.3% for 1992 and 3.2% for 1991. The Company performs depreciation studies on a continuing basis and, upon approval by the PSC, periodically adjusts the rates of its various classes of depreciable property. Estimated decommissioning costs (costs to remove a nuclear plant from service in the future) for the Company's Unit 1 and its share of decommissioning costs of Unit 2 are being accrued over the service life of the Unit, recovered in rates through an annual allowance and charged to operations through depreciation (See Note 7. "Nuclear Plant Decommissioning"). The Company expects to commence decommissioning shortly after cessation of operations using a method which removes or decontaminates Unit components promptly. Amortization of the cost of nuclear fuel is determined on the basis of the quantity of heat produced for the generation of electric energy. The cost of disposal of nuclear fuel, which presently is $.001 per kilowatt-hour of net generation available
for sale, is based upon a contract with the U.S. Department of Energy. These costs are charged to operating expense and recovered from customers through base rates or through the fuel adjustment clause. Revenues: Revenues are based on cycle billings rendered to certain customers monthly and others bi-monthly. Although the Company commenced the practice in 1988 of accruing electric revenues for energy consumed and not billed at the end of the fiscal year, the impact of such accruals has not yet been fully recognized in the Company's results of operations. At December 31, 1993 and 1992, approximately $95.0 million and $77.8 million, respectively, of unbilled revenues remained unrecognized in results of operations and are included in Deferred Credits, and may be used to reduce future revenue requirements. The amount of the remaining deferred credit balance fluctuates as the amount of accrued electric unbilled revenues is recalculated each year end. At December 31, 1993, pursuant to PSC authorization the Company accrued $20.9 million of unbilled gas revenues which will similarly be used to reduce future gas revenue requirements, with a portion to be used in 1994. The Company's tariffs include electric and gas adjustment clauses under which energy and purchased gas costs, respectively, above or below the levels allowed in approved rate schedules, are billed or credited to customers. The Company, as authorized by the PSC, charges operations for energy and purchased gas cost increases in the period of recovery. The PSC has periodically authorized the Company to make changes in the level of allowed energy and purchased gas costs included in approved rate schedules. As a result of such periodic changes, a portion of energy costs deferred at the time of change would not be recovered or may be overrecovered under the normal operation of the electric and gas adjustment clauses. However, the Company has been permitted to defer and bill or credit such portions to customers, through the electric and gas adjustment clauses, over a specified period of time from the effective date of each change. The Company's electric fuel adjustment clause provides for partial pass-through of fuel and purchased power cost fluctuations from amounts forecast, with the Company absorbing a specific portion of increases or retaining a portion of decreases up to a maximum of $15 million per rate year. Thereafter, 100% of the fluctuation is to be passed on to ratepayers. The Company also shares with ratepayers fluctuations from amounts forecast for net resale margin and transmission benefits, with the Company retaining/absorbing 20% and passing 80% through to ratepayers. The amounts absorbed in 1991 through 1993 are not material. Beginning in 1991, the Company's rate agreements provide for NERAM, which requires the Company to reconcile actual results to forecast electric public sales gross margin as defined and utilized in establishing rates. Depending on the level of actual sales, a liability to customers is created if sales exceed the forecast and an asset is recorded for a sales shortfall, thereby generally holding recorded electric gross margin to the level forecast in establishing rates. The 1994 rate settlement
provides for the operation of the NERAM through December 31, 1994. Recovery or refund of accruals pursuant to the NERAM is accomplished by a surcharge (either plus or minus) to customers over a twelve month period, to begin when cumulative amounts reach certain specified levels. Rate agreements since 1991 also include MERIT, under which the Company has the opportunity to achieve earnings above its allowed return on equity based on attainment of specified goals associated with its self-assessment process. The MERIT program provides for specific measurement periods and reporting for PSC approval of MERIT earnings. Approved MERIT awards are billed to customers over a period not greater than twelve months. The Company records MERIT earnings when attainment of goals is approved by the PSC or when objectively measured criteria are achieved. Federal Income Taxes: In accordance with PSC requirements, the tax effect of book and tax timing differences is flowed through except as required by the Internal Revenue Code or unless authorized by the PSC to be deferred. As directed by the PSC, the Company defers any amounts payable pursuant to the alternative minimum tax rules. The Company has claimed investment tax credits and deferred the benefits of such credits as realized in accordance with PSC directives. Deferred investment credits are amortized to Other Income and Deductions over the useful life of the underlying property. For purposes of computing capital cost recovery deductions and normalization, the asset basis has been reduced by all or a portion of the credit claimed consistent with then current tax laws. Since it is the Company's intention to reinvest the undistributed earnings of its foreign subsidiaries, no provision is made for federal income taxes on these earnings. At December 31, 1993, the cumulative amount of undistributed earnings of foreign subsidiaries on which the Company has not provided deferred taxes was approximately $109 million. It is expected that the federal income taxes associated with these undistributed earnings would be substantially reduced by foreign tax credits. On January 1, 1993, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. The adoption of SFAS 109 changes the Company's method of accounting for income taxes from the deferred method to an asset and liability approach. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the recorded book bases and the tax bases of assets and liabilities. The adoption of SFAS 109 did not have a significant impact on the Company's 1993 results of operations, and accordingly the effect of adoption has been included in federal and foreign income taxes. Amortization of Debt Issue Costs: The premium or discount and debt expenses on long-term debt issues and on certain debt retirements prior to maturity are amortized ratably over the lives of the related issues and included in interest on long-term debt in accordance with PSC directives. Statement of Cash Flows: The Company considers all highly liquid
investments, purchased with a remaining maturity of three months or less, to be cash equivalents. Reclassifications: Certain amounts from prior years have been reclassified on the accompanying Consolidated Financial Statements to conform with the 1993 presentation.
NOTE 2. BANK CREDIT ARRANGEMENTS ---------------------------------
At December 31, 1993, the Company had $461 million of bank credit arrangements with 19 banks. These credit arrangements consisted of $220 million in commitments under Revolving Credit Agreements (including a Revolving Credit Agreement for HYDRA-CO Enterprises, Inc., a wholly-owned subsidiary of the Company), $140 million in one-year commitments under Credit Agreements, $1 million in lines of credit and $100 million under a Bankers Acceptance Facility Agreement. The Revolving Credit Agreements which extend into 1994 are renewed annually, and the interest rate applicable to borrowing is based on certain rate options available under the Agreements. All of the other bank credit arrangements are subject to review on an ongoing basis with interest rates negotiated at the time of use. The Company also issues commercial paper. Unused bank credit facilities are held available to support the amount of commercial paper outstanding. In addition to these credit arrangements, the Company obtained $100 million in bank loans which will expire in 1994. The Company pays fees for substantially all of its bank credit arrangements. The Bankers Acceptance Facility Agreement, which is used to finance the fuel inventory for the Company's generating stations, provides for the payment of fees only at the time of issuance of each acceptance. The following table summarizes additional information applicable to short-term debt:
NOTE 3. JOINTLY-OWNED GENERATING FACILITIES
The following table reflects the Company's share of jointly- owned generating facilities at December 31, 1993. The Company is required to provide its respective share of financing for any additions to the facilities. Power output and related expenses are shared based on proportionate ownership. The Company's share of expenses associated with these facilities is included in the appropriate operating expenses in the Consolidated Statements of Income.
NOTE 4. CAPITALIZATION
CAPITAL STOCK
The Company is authorized to issue 150,000,000 shares of common stock, $1 par value; 3,400,000 shares of preferred stock, $100 par value; 19,600,000 shares of preferred stock, $25 par value; and 8,000,000 shares of preference stock, $25 par value. The table below summarizes changes in the capital stock issued and outstanding and the related capital accounts for 1991, 1992 and 1993:
These series require mandatory sinking funds for annual redemption and provide optional sinking funds through which the Company may redeem, at par, a like amount of additional shares (limited to 120,000 shares of the 7.45% series and 300,000 shares of the 9.75% series). The option to redeem additional amounts is not cumulative.
The Company's five year mandatory sinking fund redemption requirements for preferred stock, in thousands, for 1994 through 1998 are as follows: $27,200; $12,200; $14,150; $10,120; and $10,120, respectively.
Several series of First Mortgage Bonds and Notes were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (NYSERDA). Approximately $414 million of such notes bear interest at a daily adjustable interest rate (with a Company option to convert to other rates including a fixed interest rate which would require the Company to issue First Mortgage Bonds to secure the debt) which averaged 2.14% for 1993 and 2.43% for 1992 and are supported by bank direct pay letters of credit. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company's generating facilities or refund outstanding tax-exempt bonds and notes. The $115.7 million of tax-exempt bonds due 2014 will be refinanced at 7.2% during 1994 pursuant to a forward refunding agreement entered into in 1992. Notes Payable include a Swiss franc bond issue maturing in 1995 equivalent to $50 million in U.S. funds. Simultaneously with the sale of these bonds, the Company entered into a currency exchange agreement to fully hedge against currency exchange rate fluctuations. Other long-term debt in 1993 consists of obligations under capital leases of approximately $45.3 million, a liability to the U.S. Department of Energy for nuclear fuel disposal of approximately $93.5 million (See Note 7. "Nuclear Fuel Disposal Costs") and liabilities for unregulated generator contract termination of approximately $38.1 million. Certain of the Company's debt securities provide for a mandatory sinking fund for annual redemption. The aggregate maturities of long-term debt for the five years subsequent to December 31, 1993, excluding capital leases, are approximately $211 million, $73 million, $61 million, $46 million and $66 million, respectively.
NOTE 5. PENSION AND OTHER RETIREMENT PLANS -------------------------------------------
The Company and certain of its subsidiaries have non- contributory, defined-benefit pension plans covering substantially all their employees. Benefits are based on the employee's years of service and compensation level. The pension cost was $16.9 million for 1993, $23.2 million for 1992 and $23.9 million for 1991 ($5.6 million for 1993, $6.2 million for 1992 and $6.0 million for 1991 was related to construction labor and, accordingly, was charged to construction projects). The Company's general policy is to fund the pension costs accrued with consideration given to the maximum amount that can be deducted for Federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.
In 1993 and 1992, the discount rate and rate of increase in future compensation levels used in determining the actuarial present value of the projected benefit obligations were 7.3% and 8.25% and 3.25% and 4.25% (plus merit increases), respectively. The expected long-term rate of return on plan assets was 9.00% in 1993 and 1992. In addition to providing pension benefits, the Company and its subsidiaries provide certain health care and life insurance benefits for active and retired employees and dependents. Under current policies, substantially all of the Company's employees may be eligible for continuation of some of these benefits upon normal or early retirement. These benefits are provided through insurance companies whose charges and premiums are based on the claims paid during the year. On January 1, 1993, the Company adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (OPEB). This Statement requires accrual accounting by employers for postretirement benefits other than pensions reflecting currently earned benefits. During 1993 the Company established various trust funds to begin the funding of the OPEB obligation. The Company made an initial contribution, equal to the amount received in 1993 rates, of approximately $12 million and anticipates contributing approximately $23 million in 1994.
Net postretirement benefit cost for 1993 included the following components:
In thousands of dollars
Service cost - benefits attributed to service during the period $12,300 Interest cost on accumulated benefit obligation 32,800
Amortization of the transition obligation over 20 years 20,400 Net postretirement benefit cost $65,500
The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated Balance Sheet:
In thousands of dollars
At December 31, 1993
Actuarial present value of accumulated benefit obligation:
Retired and surviving spouses $224,936
Active eligible 73,474 Active ineligible 220,420
Accumulated benefit obligation 518,830
Plan assets at fair value, consisting primarily of cash equivalents 11,967 Accumulated postretirement benefit obligation in excess of plan assets 506,863
Unrecognized net loss from past experience different from that assumed and effects of changes 82,756 in assumptions
Unrecognized transition obligation to be amortized over 20 years 388,600
Accrued postretirement benefit liability included $35,507 in the consolidated balance sheet
At December 31, 1993, a pre-65 and post-65 health care cost trend rate of 10.05% and 7.05%, respectively, was assumed, trending down to 4.8% by 1999. If the health care cost trend rate was increased by one percent, the accumulated postretirement benefit obligation as of December 31, 1993 would increase by approximately 8.7% and the aggregate of the service and interest cost component of net periodic postretirement benefit cost for the year would increase by approximately 7.8%. The discount rate used in determining the accumulated postretirement benefit obligation was 7.3%. During 1993, the PSC issued a Statement of Policy (SOP) regarding the accounting for pension and postretirement costs. With respect to postretirement benefits, the PSC mandated a transition to full accrual accounting in rates over a period not to exceed five years, with recovery of any resultant deferrals over a period not to exceed twenty years from the year of adoption. In accordance with its rate agreement and the SOP, the Company has a $30.7 million
regulatory asset at December 31, 1993 relating to the rate transition for postretirement costs. The SOP requires deferral of the difference between actual costs and rate allowances and ten year amortization of actuarial gains and losses for both pensions and postretirement costs effective January 1, 1993. The 1993 pension cost was reduced by approximately $8 million to reflect the effect of the change in the amortization period of an actuarial gain of $90.6 million as of January 1, 1993. The Company does not expect the true-up requirements or the change to amortization of actuarial gains and losses to have a material impact on its periodic benefit costs or results of operations. In November 1992, the FASB issued SFAS No. 112 "Employees' Accounting for Postemployment Benefits" which is effective for fiscal years beginning after December 15, 1993. This Statement, which the Company will adopt for 1994, requires employers to recognize the obligation to provide postemployment benefits if the obligation is attributable to employees' past services, rights to those benefits are vested, payment is probable and the amount of the benefits can be reasonably estimated. The Company typically accounts for such costs on a cash basis. The Company estimates the postemployment benefit obligation to be approximately $11.4 million at January 1, 1994. In its 1994 rates, the Company has included approximately $2.9 million, including capital, representing the pay-as-you-go portion of the postemployment benefit. The difference between the postemployment benefit obligation and the rate allowance will be deferred, with the proposed recovery occurring equally over three years beginning in 1995. The Company believes that these costs will be recovered based on current ratemaking principles.
NOTE 6. FEDERAL AND FOREIGN INCOME TAXES
Components of United States and foreign income before income taxes: In thousands of dollars
1993 1992 1991 United States $438,914 $410,283 $394,596
Foreign (24,845) 18,394 (6,252)
Consolidating eliminations 4,837 (16,741) (11,080)
Income before income taxes $418,906 $411,936 $377,264 Following is a summary of the components of Federal and foreign income tax and a reconciliation between the amount of Federal income tax expense reported in the Consolidated Statements of Income and the computed amount at the statutory tax rate:
Summary Analysis: In thousands of dollars
COMPONENTS OF FEDERAL AND FOREIGN INCOME TAXES: 1993 1992 1991
Current tax expense:
Federal $118,918 $119,929 $ 75,452 Foreign 8,445 915 597
127,363 120,844 76,049 Deferred tax expense:
Federal 35,152 54,858 74,983
Foreign - 7,531 7,105 35,152 62,389 82,088
Income taxes included in Operating Expenses: 162,515 183,233 158,137 Current Federal and foreign income tax credits included in Other Income and Deductions (16,061) (31,787) (24,734)
Deferred Federal and foreign income tax expense (credits) included in Other Income and Deductions 621 4,058 492
Total $147,075 $155,504 $133,895
COMPONENTS OF DEFERRED FEDERAL AND FOREIGN INCOME TAXES (NOTE 1):
Depreciation related $ 78,467 $ 90,897
Investment tax credit (8,067) (8,137) Alternative minimum tax (1,197) (27,276)
Recoverable energy and purchased gas costs (1,926) 8,066 Deferred operating expenses 10,867 (2,179)
Nuclear settlement disallowance 20,099 12,865
MERIT recovery (4,263) 9,935 Opinac reserve for oil and (19,706) (13,083) gas properties
Bond reacquisition premium 7,379 - Other (15,206) 11,492
Deferred Federal income taxes (net) $ 66,447 $ 82,580
RECONCILIATION BETWEEN FEDERAL AND FOREIGN INCOME TAXES AND THE TAX COMPUTED AT PREVAILING U.S. STATUTORY RATE ON INCOME BEFORE INCOME TAXES: Computed tax $146,617 $140,058 $128,270
Reduction (increase) attributable to flow-through of certain tax adjustments: Depreciation (35,153) (37,543) (36,440)
Allowance for funds used during construction 2,951 11,205 7,540
Cost of removal 7,822 6,845 5,781 Deferred investment tax credit amortization 8,018 8,024 7,891
Other 15,904 (3,977) 9,603 (458) (15,446) (5,625)
Federal and foreign income taxes $147,075 $155,504 $133,895
The Omnibus Budget Reconciliation Act of 1993 (OBRA of 1993) was signed into law in August 1993. One of the provisions of the OBRA of 1993 raises the federal corporate statutory tax rate from 34% to 35%, retroactive to January 1, 1993. A provision of the 1993 Settlement provides for the deferral of the effects of tax law changes. SFAS 109 increased the accumulated deferred income tax liability at January 1, 1993 by approximately $507 million, represented substantially by tax benefits flowed-through to rate payers in prior years (in the form of lower rates) upon which deferred taxes had not been provided. At December 31, 1993, the deferred tax liabilities (assets) were comprised of the following: In thousands of dollars
Alternative minimum tax $ (95,071) Other (208,217)
Total deferred tax assets (303,288)
Depreciation related 1,318,600 Investment tax credit related 108,140
Other 190,031 Total deferred tax liabilities 1,616,771
Accumulated deferred income taxes $1,313,483
The Company believes that the more significant effects of adopting this pronouncement are (i) providing deferred taxes for tax benefits flowed through to ratepayers, (ii) adjustment of deferred tax assets and liabilities for enacted changes in tax law or rates and (iii) prohibition of net-of- tax accounting. The Company routinely collects the increased tax liability from previously flowed-through tax benefits. In addition, the PSC issued effective January 15, 1993 a Statement of Interim Policy on Accounting and Ratemaking Procedures to implement SFAS 109. The statement required adoption of SFAS 109 on a revenue-neutral basis, recognizing the PSC's policy of rate recovery when prior flow-through items reverse. The Company has recorded income taxes recoverable, a regulatory asset, in the amount of approximately $528 million, which is comprised of previously flowed-through tax benefits, and offset by temporary differences associated with deferred investment tax credits and excess deferred taxes established at tax rates greater than 35%. Substantially all of the excess deferred taxes relate to property and are not subject to immediate refund to customers in accordance with federal law.
NOTE 7. NUCLEAR OPERATIONS
The Company is the owner and operator of the 613 MW Unit 1 and the operator and a 41% co-owner of the 1,062 MW Unit 2. Unit 1 was placed in commercial operation in 1969 and Unit 2 in 1988. Unit 1 Economic Study: Under the terms of a previous regulatory agreement, the Company agreed to prepare and update studies of the advantages and disadvantages of continued operation of Unit 1 prior to the start of the next two refueling outages. The first report, which recommended continued operation of Unit 1 over the remaining term of its license (2009), was filed with the PSC in March 1990. On November 20, 1992 the Company submitted to the PSC an updated economic analysis which indicated that Unit 1 can be expected to provide value to customers and shareholders through its next fuel cycle, which will end in early 1995. The study also indicated that the Unit could continue to provide benefits for the full term of its license if operating costs can be reduced and generating output improved above its historical average. The study analyzed a number of scenarios resulting in break-even capacity factors, ranging from 44% to 122%. The "base case" assumes a capacity factor of 61%, consistent with the target reflected in the Unit 1 operating incentive mechanism, and also assumes future operating and capital costs slightly lower than historical performance. While a marginal benefit would be realized from operating the Unit for at least the next two years (one fuel cycle) under the "base case," there would be a negative net present value in excess of $100 million if the Unit were to be operated over its remaining 17-year license period. Under an "improved performance case", the Unit is assumed to operate at a 70% capacity factor with future operating and capital costs consistent with average industry performance. The Company believes these goals are achievable for Unit 1, as indicated by Unit 1 operating and financial performance in 1993 that was better than the improved performance case. The "improved performance case" results in positive net present value in excess of $100 million if the Unit is operated over its remaining life. Such results demonstrate the volatility of the assumptions and uncertainties involved in developing the Unit's economic forecast. These assumptions include various levels of the Unit's capacity factor, operating and capital costs, demand for electricity, supply of electricity including unregulated generator power, implementation and compliance costs of the Clean Air Act and other federal and state environmental requirements and fuel availability and prices, especially natural gas. Given the potential for rapid and substantial change in any or all of these assumptions, the Company has developed operational and external criteria, other than refueling, which would initiate a prompt reassessment of the economic viability of the Unit.
An agreement with the PSC allows recovery of all reasonable and prudently-incurred sunk costs and costs of retirement, should a prudent decision be made to retire Unit 1 before early 1995. All parties to the 1991 Agreement reserve the right to petition the PSC to institute a formal investigation to review the prudence of any Company decision to retire Unit 1. Any such decision by the Company will be made in consultation with governmental and regulatory authorities. The Company's net investment in Unit 1 is approximately $580 million, exclusive of decommissioning costs. See Nuclear Plant Decommissioning. Unit 1 Status: On February 20, 1993, Unit 1 was taken out of service for a planned 55 day refueling and maintenance outage. On April 15, 1993, Unit 1 returned to service ahead of schedule. The next refueling outage is scheduled to begin in February 1995. Unit 1's capacity factor for 1993 was approximately 81%. Unit 2 Status: On October 2, 1993, Unit 2 was taken out of service for a planned 60 day refueling and maintenance outage. On November 29, 1993, Unit 2 returned to service ahead of schedule. The next refueling outage is scheduled to begin in the spring of 1995. Unit 2's capacity factor for 1993 was approximately 78%. Nuclear Plant Decommissioning: Based on a 1989 study, the cost of decommissioning Unit 1, which is expected to begin in the year 2009, is estimated by the Company to be approximately $416 million at that time ($257 million in 1993 dollars). The Company's 41% share of the total cost to decommission Unit 2, expected to begin in 2027, is estimated by the Company to be approximately $316 million ($109 million in 1993 dollars). The annual decommissioning allowance reflected in ratemaking is based upon these estimates, which include amounts for both radioactive and non-radioactive dismantlement costs. The non-radioactive dismantlement costs are estimated in the 1989 study to be $24 million for Unit 1 and $18 million for its share of Unit 2, in 1993 dollars. Decommissioning costs recovered in rates are reflected in Accumulated Depreciation and Amortization on the Balance Sheet and amount to $113.9 million and $90.5 million at December 31, 1993 and 1992, respectively. The annual allowance for Unit 1 and the Company's share of Unit 2 for the years ended December 31, 1993, 1992 and 1991 was approximately $18.7, $23.1 and $23.0 million, respectively. The Company will update its Unit 1 decommissioning study in 1994 in support of the update of the Unit 1 economic study. The Unit 2 decommissioning study is also expected to be updated in 1994. Rate allowance adjustments will be sought when appropriate. There is no assurance that the decommissioning allowance recovered in rates will ultimately aggregate a sufficient amount to decommission the units. However, the Company believes that if decommissioning costs are higher than currently estimated they would ultimately be recovered in the rate process. The NRC issued regulations in 1988 requiring owners of
nuclear power plants to place funds into an external trust to provide for the cost of decommissioning contaminated portions of nuclear facilities as well as establishing minimum amounts that must be available in such a trust for these specified decommissioning activities at the time of decommissioning. As of December 31, 1993, the Company has accumulated in an external trust $63.1 million for Unit 1 and $15.4 million for its share of Unit 2, which are included in Other Property and Investments. Earnings on such investments aggregated $8.6 million through December 31, 1993 and, because they are available to fund decommissioning, have also been included in Accumulated Depreciation and Amortization. Amounts recovered for non-radioactive dismantlement are accumulated in an internal reserve fund which has an accumulated balance of $35.4 million at December 31, 1993. Based upon studies applying the 1988 NRC regulations, the Company had estimated that the minimum funding requirements for Unit 1 and its share of Unit 2, respectively, would be $191 million and $87 million in 1993 dollars. In May 1993, the NRC established new labor, energy and burial cost factors for determining the NRC minimum funding requirements. A substantial increase in burial costs, partly offset by reduced estimates in the volumes of waste to be disposed, increased the NRC minimum requirement for Unit 1 to $372 million in 1993 dollars and the Company's share of Unit 2 to $169 million in 1993 dollars. The Company has requested an annual aggregate increase of approximately $10 million in the Unit 1 and Unit 2 decommissioning allowances as part of its 1995 rate request, to reflect the increased NRC minimum requirements. Nuclear Liability Insurance: The Atomic Energy Act of 1954, as amended, requires the purchase of nuclear liability insurance from the Nuclear Insurance Pools in amounts as determined by the NRC. At the present time, the Company maintains the required $200 million of nuclear liability insurance. In August 1993, the statutory liability limits for the protection of the public under the Price-Anderson Amendments Act of 1988 (the Act) were further increased. With respect to a nuclear incident at a licensed reactor, the statutory limit, which is in excess of the $200 million of nuclear liability insurance, was increased to approximately $8.8 billion. This limit would be funded by assessments of up to $75.5 million for each of the 116 presently licensed nuclear reactors in the United States, payable at a rate not to exceed $10 million per reactor per year. Such assessments are subject to periodic inflation indexing and to a 5% surcharge if funds prove insufficient to pay claims. The Company's interest in Units 1 and 2 could expose it to a potential loss, for each accident, of $106.5 million through assessments of $14.1 million per year in the event of a serious nuclear accident at its own or another licensed U.S. commercial nuclear reactor. The amendments also provide, among other things, that insurance and indemnity
will cover precautionary evacuations whether or not a nuclear incident actually occurs. Nuclear Property Insurance: The Nine Mile Point Nuclear Site has $500 million primary nuclear property insurance with the Nuclear Insurance Pools (ANI/MRP). In addition, there is $800 million in excess of the $500 million primary nuclear insurance with the Nuclear Insurance Pools (ANI/MRP) and $1.4 billion, which is also in excess of the $500 million primary and the $800 million excess nuclear insurance, with Nuclear Electric Insurance Limited (NEIL). NEIL is a utility industry-owned mutual insurance company chartered in Bermuda. The total nuclear property insurance is $2.7 billion. NEIL also provides insurance coverage against the extra expense incurred in purchasing replacement power during prolonged accidental outages. The insurance provides coverage for outages for 156 weeks after a 21 week waiting period. NEIL insurance is subject to retrospective premium adjustment under which the Company could be assessed up to approximately $11.3 million per loss. Low Level Radioactive Waste: The Federal Low Level Radioactive Waste Policy Act requires states to join compacts or individually develop their own low level radioactive waste disposal site. In response to the Federal law, New York State decided to develop its own site because of the large volume of low level radioactive waste it generates and committed by January 1, 1993 to develop a plan for the management of low level radioactive waste in New York State during the interim period until a disposal facility is available. New York State is developing disposal methodology and acceptance criteria for a disposal facility. A revised New York State low level radioactive waste site development schedule now assumes two possible siting scenarios, a volunteer approach and a non-volunteer approach, either of which would begin operation in 2001. An extension of access to the Barnwell, South Carolina waste disposal facility was made available to out-of-region low level radioactive waste generators by the state of South Carolina through June 30, 1994, and New York State has elected to use this option. The Company has a low level radioactive waste management program and contingency plan so that Unit 1 and Unit 2 will be prepared to properly handle interim on-site storage of low level radioactive waste for at least a 10 year period, if required. Nuclear Fuel Disposal Cost: In January 1983, the Nuclear Waste Policy Act of 1982 (the Nuclear Waste Act) established a cost of $.001 per kilowatt-hour of net generation for current disposal of nuclear fuel and provides for a determination of the Company's liability to the Department of Energy (DOE) for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until 1998, the year in which the Company had initially planned to
ship irradiated fuel to an approved DOE disposal facility. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010. The Company does not anticipate that the DOE will accept all of its spent fuel immediately upon opening of the facility, but rather expects a transfer period of as long as 20 years. With Unit 1 expected to be retired in 2009, the Company must consider some form of storage if it intends to begin immediate dismantlement. The Company has several alternatives under consideration to provide additional storage facilities, as necessary. Each alternative will likely require NRC approval, may require other regulatory approvals and would likely require the incurrance of additional costs. The Company does not believe that the possible unavailability of the DOE disposal facility until 2006 will inhibit operation of either Unit. The Energy Policy Act provides for the establishment of a federal decontamination and decommissioning fund to provide for the environmentally safe closure of DOE uranium processing facilities, funded in part by nuclear utilities. The Company has recorded its estimated liability to this fund based on prior DOE nuclear fuel processing services it received and its initial assessment during 1993. The liability is expected to be recovered as a fuel expense as provided by the Act and is payable over 14 years ending in 2007, with annual assessments indexed for inflation.
NOTE 8. COMMITMENTS AND CONTINGENCIES --------------------------------------
Construction Program: The Company is committed to an ongoing construction program to assure reliable delivery of its electric and gas services. The Company presently estimates that the construction program for the years 1994 through 1998 will require approximately $1.57 billion, excluding AFC, nuclear fuel and certain overheads capitalized. For the years 1994 through 1998, the estimates are $408 million, $295 million, $287 million, $291 million and $285 million, respectively. These amounts are reviewed by management as circumstances dictate. Long-term Contracts for the Purchase of Electric Power: At January 1, 1994,the Company had long-term contracts to purchase electric power from the following generating facilities owned by the New York Power Authority (NYPA):
The purchase capacities shown above are based on the contracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges. The total cost of purchases under these contracts was approximately $72.2 million, $64.4 million and $61.2 million for the years 1993, 1992 and 1991, respectively. Under the requirements of the Federal Public Utility Regulatory Policies Act of 1978, the Company is required to purchase power generated by unregulated generators, as defined therein. Of the 147 facilities providing energy to the Company at December 31, 1993, five require the Company to make capacity payments, including payments when a production plant is not operating, and are subject to price escalation. Each facility must meet certain availability and performance obligations prior to receiving capacity payments. The terms of these five contracts allow the Company to schedule energy deliveries from the facilities and then pay for the energy that is delivered. These five facilities account for approximately 380,000 kw of capacity with contract lengths ranging from 20 to 35 years. The total cost of purchases under these five contracts in 1993 was $56.6 million and the 1994 estimated annual capacity and energy payments are estimated to be approximately $105.5 million and $50 million, respectively, subject to scheduling, the availability and tested capacity of these facilities, and price escalation. Capacity payments under these five contracts for 1995 to 1998 would be $109 million, $120 million, $127 million and $130 million, respectively and would aggregate to approximately $3.5 billion over the terms of the contracts. Contracts relating to the remaining facilities in service at December 31, 1993, require the Company to pay only when energy is delivered. The Company paid approximately $736 million (including the amount discussed above), $543 million and $268 million in 1993, 1992 and 1991 for 11,720,000 mwhrs, 8,632,000 mwhrs and 4,303,000 mwhrs, respectively, of energy under all unregulated generator contracts. Through December 31, 1993, the Company had entered into agreements with current and prospective unregulated generators for approximately 2,400 MW of capacity. The ultimate amount of the commitment and the available capacity are dependent upon the completion of these projects. Based upon these contracts as of December 31, 1993, the Company estimates that it will be obligated to make payments to unregulated generators of (in millions): $932 in 1994, $1,057 in 1995, $1,111 in 1996, $1,174 in 1997 and $1,220 in 1998. The Company recovers all payments to unregulated generators through base rates or through the FAC. Sale of Customer Receivables: The Company has an agreement whereby it can sell an undivided interest in a designated pool of customer receivables, including accrued unbilled
electric revenues, up to a maximum of $200 million. At December 31, 1993 and 1992, respectively, $200 million of receivables had been sold under this agreement. The undivided interest in the designated pool of receivables was sold with limited recourse. The agreement provides for a loss reserve pursuant to which additional customer receivables are assigned to the purchaser to protect against bad debts. To the extent actual loss experience of the pool receivables exceeds the loss reserve, the purchaser absorbs the excess. For receivables sold, the Company has retained collection and administrative responsibilities as agent for the purchaser. As collections reduce previously sold undivided interests, new receivables are customarily sold. Tax assessments: The Internal Revenue Service (IRS) has conducted an examination of the Company's Federal income tax returns for the years 1987 and 1988 and has submitted a Revenue Agents' Report to the Company. The IRS has proposed various adjustments to the Company's federal income tax liability for these years which could increase the Federal income tax liability by approximately $80 million before assessment of penalties and interest. Included in these proposed adjustments are several significant issues involving Unit 2. The Company is vigorously defending its position on each of the issues, and submitted a protest to the IRS in 1993. Pursuant to the Unit 2 settlement entered into in 1990, to the extent the IRS is able to sustain disallowances, the Company will be required to absorb a portion of any disallowance. The Company believes any such disallowance will not have a material impact on its financial position or results of operations. Litigation: On March 22, 1993, a complaint was filed in the Supreme Court of the State of New York, Albany County, against the Company and certain of its officers and employees. The plaintiff, Inter-Power of New York, Inc. (Inter-Power), alleges, among other matters, fraud, negligent misrepresentation and breach of contract in connection with the Company's alleged termination of a power purchase agreement in January 1993. The power purchase agreement was entered into in early 1988 in connection with a 200 MW cogeneration project to be developed by Inter-Power in Halfmoon, New York. The plaintiff is seeking enforcement of the original contract or compensatory and punitive damages on fourteen causes of action in an aggregate amount that would not exceed $1 billion, excluding pre-judgment interest. The Company believes it has done no wrong, and intends to vigorously defend against this action. On May 7, 1993, the Company filed an answer denying liability and raising certain affirmative defenses. Thereafter, the Company and Inter- Power filed cross-motions for summary judgement. The court dismissed two of Inter-Power's fourteen causes of action but otherwise denied the Company's motion. The court also dismissed two of the Company's affirmative defenses and otherwise denied Inter-Power's cross-motion. Both parties have filed Notices of Appeals regarding these dismissals.
Discovery is in progress. The ultimate outcome of the litigation cannot presently be determined. On November 12, 1993, Fourth Branch Associates Mechanicville ("Fourth Branch"), filed suit against the Company and several of its officers and employees in the New York Supreme Court, Albany County, seeking compensatory damages of $50 million, punitive damages of $100 million and injunctive and other related relief. The suit grows out of the Company's termination of a contract for Fourth Branch to operate and maintain a hydroelectric plant the Company owns in the Town of Halfmoon, New York. Fourth Branch's complaint also alleges claims based on the inability of Fourth Branch and the Company to agree on terms for the purchase of power from a new facility that Fourth Branch hoped to construct at the Mechanicville site. On January 3, 1994, the defendants filed a joint motion to dismiss Fourth Branch's complaint. The Company believes that it has substantial defenses to Fourth Branch's claims, but is unable to predict the outcome of this litigation. Accordingly, no provision for liability, if any, that may result from either of these suits has been made in the Company's financial statements. Environmental Contingencies: The public utility industry typically utilizes and/or generates in its operations a broad range of potentially hazardous wastes and by-products. These wastes or by- products may not have previously been considered hazardous, and may not be considered hazardous currently, but may be identified as such by Federal, state or local authorities in the future. The Company believes it is handling identified wastes and by-products in a manner consistent with Federal, state and local requirements and has implemented an environmental audit program to identify any potential areas of concern and assure compliance with such requirements. The Company is also currently conducting a program to investigate and restore, as necessary to meet current environmental standards, certain properties associated with its former gas manufacturing process and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company contributed. The Company has been advised that various Federal, state or local agencies believe that certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if determined to be necessary. The Company is currently aware of 82 sites with which it has been or may be associated, including 42 which are Company-owned. The Company-owned sites include 23 former coal gasification (MGP) sites, 14 industrial waste sites and 5 operating property sites where corrective actions may be deemed necessary to prevent, contain and/or remediate contamination of soil and/or water in the vicinity. Of these Company-owned sites, Saratoga Springs is on the Federal National Priorities List for Uncontrolled Hazardous Waste
Sites (NPL) as published by the Environmental Protection Agency in the Federal Register. The 40 non-owned sites with which the Company has been or may be associated are generally industrial waste sites where the Company is alleged to be a PRP and may be required to contribute some proportionate share towards investigation and clean-up. Not included in the 82 sites are seven sites where the Company has reached settlement agreements with other PRP's and three sites where remediation activities have been completed. There also exist approximately 20 formerly-owned MGP sites with which the Company has been or may be associated that may require future investigation and remediation. To date, the Company has not been made aware of any claims. Also, approximately 22 fire training sites owned or used by the Company have been identified but not investigated. Presently, the Company is unable to determine its potential involvement with such sites and has made no provision for liability, if any, at this time. Investigations at each of the Company-owned sites are designed to (1) determine if environmental contamination problems exist, (2) determine the extent, rate of movement and concentration of pollutants, (3) if necessary, determine the appropriate remedial actions required for site restoration and (4) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties, if necessary, will be initiated. After site investigations have been completed, the Company expects to determine site-specific remedial actions necessary and to estimate the attendant costs for restoration. However, since technologies are still developing and the Company has not yet undertaken any full- scale remedial actions following regulatory requirements at any identified sites, nor have any detailed remedial designs been prepared or submitted to appropriate regulatory agencies, the ultimate cost of remedial actions may change substantially as investigation and remediation progresses. The Company has estimated that it is probable that 36 of the 42 owned sites will require some degree of investigation, remediation and monitoring. This conclusion is based upon a number of factors, including the nature of the identified or potential contaminants, the location and size of the site, the proximity of the site to sensitive resources, the status of regulatory investigation and knowledge of activities at similarly situated sites. Although the Company has not extensively investigated many of those sites, it believes it has sufficient information to estimate a range of cost of investigation and remediation. As a consequence of site characterizations and assessments completed to date, the Company has accrued a liability of $210 million for these owned sites, representing the low end of the range of the estimated cost for investigation and remediation. The high end of the range is presently estimated at approximately $520 million. The majority of these cost estimates relate to the MGP
sites. Of the 23 MGP sites, Harbor Point (Utica, NY) and Saratoga Springs are subject to regulatory enforcement actions and to date have remedial investigation and/or feasibility study work in progress. The remaining 21 MGP sites are the subject of an Order on Consent executed with the New York State Department of Environmental Conservation (DEC) providing for an investigation and remediation program over approximately ten years. Preliminary site assessments have been conducted or are in process at five of these 21 sites, with remedial investigations either currently in process or scheduled for 1994. Remedial investigations were also conducted for two industrial waste sites and for three operating properties where corrective actions were considered necessary. The Company does not currently believe that a clean-up will be required at the 6 remaining Company-owned sites, although some degree of investigation of these sites is included in its investigation and remediation program. With respect to the 40 sites with which the Company has been or may be associated as a PRP, 9 are on the NPL. Total costs to investigate and remediate the sites with which the Company is associated as a PRP are estimated to be approximately $590 million; however, the Company estimates its share of this total at approximately $30 million and this amount has been accrued at December 31, 1993. The seven settlement agreements reached with other PRP's were settled in an amount not material to the Company. Two of these (Ludlow Landfill and Wide Beach) are on the NPL and have been settled by the Company in an aggregate amount of less than $300,000. For the 9 sites included on the NPL, the Company's potential contribution factor varies for each site. The estimated aggregate liability for these sites is not material and is included in the determination of the amounts accrued. Estimates of the Company's potential liability for PRP sites are derived by estimating the total cost of site clean- up and then applying the related Company contribution factor to that estimate. Estimates of the total clean-up costs are determined by using the Company's investigation to date, if any, discussions with other PRPs and, where no information is known at the time of estimate, the Environmental Protection Agency (EPA) estimates based on average costs disclosed in the Federal Register of June 23, 1993. The contribution factor is calculated using either the Company's percentage share based upon the total number of PRPs named or otherwise identified, which assumes all PRPs will contribute equally, or the percentage agreed upon with other PRPs through steering committee negotiations or by other means. Actual Company expenditures for these sites are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company's share of responsibility for such costs as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several. The Company has denied any responsibility
in certain of these PRP sites and is contesting liability accordingly. The EPA advised the Company by letter that it is one of 833 PRPs under Superfund for the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky. The Company has contributed to a study of this site and estimates that the cost to the Company for its share of investigation and remediation based on its contribution factor of 1.3% would approximate $1 million, which the Company believes will be recoverable in the ratesetting process. On July 21, 1988, the Company received notice of a motion by Reynolds Metals Company to add the Company as a third party defendant in an ongoing Superfund lawsuit in Federal District Court, Northern District of New York. This suit involves PCB oil contamination at the York Oil Site in Moira, New York. Waste oil was transported to the site during the 1960's and 1970's by contractors of Peirce Oil Company (owners/operators of the site) who picked up waste oil at locations throughout Central New York, allegedly including one or more Company facilities. On May 26, 1992, the Company was formally served in a Federal Court action initiated by the government against 8 additional defendants. Pursuant to the requirements of a case management order issued by the Court on March 13, 1992, the Company has also been served in related third and fourth-party actions for contribution initiated by other defendants. Discovery is now in progress. The goal of this effort is to provide adequate information to form a basis for achieving a voluntary allocation of liability among the parties. The Company believes that costs incurred in the investigation and restoration process for both Company-owned sites and sites with which it is associated will be recoverable in the ratesetting process. Rate agreements in effect since 1991 provide for recovery of anticipated investigation and remediation expenditures, although the PSC Staff reserves the right to review the appropriateness of the costs incurred. While the PSC Staff has not challenged any remediation costs to date, the PSC Staff asserted in the recently-decided gas rate proceeding that the Company must, in future rate proceedings, justify why it is appropriate that remediation costs associated with non-utility property owned by the Company be recovered from ratepayers. The Company's 1994 rate settlement includes $21.7 million for site investigation and remediation. Based upon management's assessment that remediation costs will be recovered from ratepayers, a regulatory asset has been recorded representing the future recovery of remediation obligations accrued to date. The Company also agreed in rate agreements to a cost sharing arrangement with respect to one industrial waste site. The Company does not believe that this cost sharing agreement, as it relates to this particular industrial waste site, will have a material effect on the Company's financial
position or results of operations. The Company is also in the process of providing notices of insurance claims to carriers with respect to the investigation and remediation costs for manufactured gas plant and industrial waste sites. The Company is unable to predict whether such insurance claims will be successful. Federal Energy Regulatory Commission Order 636: In 1992, the FERC issued Order 636, which requires interstate pipelines to unbundle pipeline sales services from pipeline transportation service. These changes enable the Company to arrange for its gas supply directly with producers, gas marketers or pipelines, at its discretion, as well as arrange for transportation and gas storage services. As a result of these structural changes, pipelines face "transition" costs from implementation of the Order. The principal costs are: unrecovered gas cost that would otherwise have been billable to pipeline customers under previously existing rules, costs related to restructuring existing gas supply contracts and costs of assets needed to implement the order (such as meters, valves, etc.). Under the Order, pipelines are allowed to recover 100% of prudently incurred costs from customers. Prudence will be determined by FERC review. The amount of restructuring costs ultimately billed to the Company will be determined in accordance with pipeline restructuring plans which have been submitted to the FERC for approval. There are four pipelines to which the Company has some liability. The Company is actively participating in FERC hearings on these matters to ensure an equitable allocation of costs. The restructuring costs will be primarily reflected in demand charges paid to reserve space on the various interstate pipelines and will be billed over a period of approximately 7 years, with billings more heavily weighted to the first 3 years. Based upon information presently available to the Company from the petitions filed by the pipelines, the Company's participation in settlement negotiations, and the three settlements to which it is a party, its liability for the pipelines' unrecovered gas costs is expected to be as much as $31 million and its liability for pipeline restructuring costs could be as much as $38 million. The Company has recorded a liability of $31 million at December 31, 1993, representing the low end of the range of such transition costs. The Company is unable to predict the final outcome of current pipeline restructuring settlements and the ultimate amounts for which it will be liable or the period over which this liability will be billed. Based upon Management's assessment that transition costs will be recovered from ratepayers, a regulatory asset has been recorded representing the future recovery of transition costs accrued to date. Currently, such costs billed to the Company are treated as a cost of purchased gas and recoverable through the operation of the gas adjustment clause mechanism.
NOTE 9 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS ------------------------------------------------ ------------
The following methods and assumptions were used to estimate the fair value of each class of financial instruments: Cash and short-term investments: The carrying amount approximates fair value because of the short maturity of the financial instruments. Long-term investments: The carrying value and market value are not material to the financial statements. Mandatorily redeemable preferred stock: Fair value of the mandatorily redeemable preferred stock has been determined by one of the Company's brokers or estimated by management based on discounted cash flows. Long-term debt: The fair value of the Company's long-term debt has been estimated by one of the Company's brokers. The carrying value of NYSERDA bonds, the Oswego Facilities Trust and other long-term debt are considered to approximate fair value. The estimated fair values of the Company's financial instruments are as follows:
NOTE 10. INFORMATION REGARDING THE ELECTRIC AND GAS BUSINESSES The Company is engaged in the electric and natural gas utility businesses. Certain information regarding these segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation of such common property have been allocated to the segments in accordance with practice established for regulatory purposes. Identifiable assets include net utility plant, materials and supplies, deferred finance charges, deferred recoverable energy costs and certain other deferred debits. Corporate assets consist of other property and investments, cash, accounts receivable, prepayments, unamortized debt expense and other deferred debits.
In the second quarter of 1992 and the third quarter of 1993 and 1991, the Company recorded $22.8 million ($.11 per common share), $10.3 million ($.05 per common share) and $30 million ($.14 per common share), respectively, for MERIT earned in accordance with the 1991 Agreement. In the first quarter of 1992 and the fourth quarter of 1992 and 1991, the Company recorded $21 million ($.09 per common share), $24 million ($.09 per common share) and $23 million ($.07 per common share), respectively, to write-down its subsidiary investment in oil and gas properties.
GAS STATISTICS
1993 1992 1991
Gas Sales (Thousands of dekatherms):
Residential . . . . . . . . . . . . . . . . 54,908 53,945 48,172 Commercial . . . . . . . . . . . . . . . . 23,743 22,289 20,226
Industrial . . . . . . . . . . . . . . . . 4,316 1,772 1,812 Other gas systems . . . . . . . . . . . . . 234 1,190 1,519
Total sales . . . . . . . . . . . . . 83,201 79,196 71,729
Spot market . . . . . . . . - . . . . . . . . 13,223 1,146
Transportation of customer- 50,631 owned gas . . . 67,741 65,845 Total gas delivered . . . . . . . . . 164,165 146,187 122,360
Gas Revenues (Thousands of dollars):
Residential . . . . . . . . . . . . . . . . $370,565 $354,429 $302,900 Commercial . . . . . . . . . . . . . . . . 144,834 132,609 113,727
Industrial . . . . . . . . . . . . . . . . 18,482 10,001 8,430
Other gas systems . . . . . . . . . . . . . 1,066 4,737 6,964 Spot market . . . . . . . . - . . . . . . . . 29,782 2,576
Transportation of customer- 36,455 owned gas . . . 34,843 42,726
Miscellaneous . . . . . . . . . . . . . . . 1,395 6,773 6,749
$600,967 $553,851 $475,225 Gas Customers (Average):
Residential . . . . . . . . . . . . . . . . 455,629 446,571 438,581
Commercial . . . . . . . . . . . . . . . . 39,662 38,675 37,727 Industrial . . . . . . . . . . . . . . . . 233 234 260
Other . . . . . . . . . . . . . . . . . . . 1 1 2 Transportation . . . . . . . . . . . . . . 673 673 625
496,198 486,154 477,195
Residential (Average): Annual dekatherm use per customer . . . . . 120.5 120.8 109.8
Cost to customer per dekatherm . . . . . . $6.75 $6.57 $6.29
Annual revenue per customer . . . . . . . . $813.30 $793.67 $690.64 Maximum day gas sendout (dekatherms) . . . 929,285 905,872 852,404
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
The Company has nothing to report for this item.
PART III
The information required by Part III of this Form 10-K, Item
10
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Certain documents filed as part of the Form 10-K.
(1) INDEX OF FINANCIAL STATEMENTS
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for each of the three years in the period ended December 31, Consolidated Balance Sheets at December 31, 1993 and 1992 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1993 Notes to Consolidated Financial Statements
Separate financial statements of the Company have been omitted since it is primarily an operating company and all consolidated subsidiaries are totally held directly or through subsidiaries.
(2) The following financial statement schedules of the Company for the years ended December 31, 1993, 1992 and 1991 are included:
Report of Independent Accountants on Financial Statement Schedules
Consolidated Financial Statement Schedules:
V--Utility Plant VI--Accumulated Depreciation and Amortization of Utility Plant VIII--Valuation and Qualifying Accounts and Reserves IX--Short Term Borrowings X--Supplementary Income Statement Information
The Financial Statement Schedules above should be read in conjunction with the Consolidated Financial Statements in the 1993 Annual Report to Stockholders.
Schedules other than those mentioned above are omitted because the conditions requiring their filing do not exist or because the required information is given in the financial statements, including the notes thereto.
(b) Reports on Form 8-K:
Form 8-K Reporting Date - February 18, 1994. Items Reported - Item 5. Other Events.
Registrant filed certain financial information substantially constituting a portion of its 1993 Annual Report to Stockholders including financial statements for the fiscal year ended December 31, 1993
Form 8-K Reporting Date - February 24, 1994 Items Reported - Item 5. Other Events.
Registrant filed information concerning the Standard & Poors lowering of the credit rating of the Company's securities.
(c) Exhibits.
See List of Exhibits.
(d) Financial Statement Schedules.
See (a)(2) above.
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
To the Board of Directors Niagara Mohawk Power Corporation
Our audits of the consolidated financial statements of Niagara Mohawk Power Corporation referred to in our report dated January 27, 1994 of this Form 10-K also included an audit of the Financial Statement Schedules listed in Item 14(a) of this Form 10-K. In our opinion, these Financial Statement Schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PRICE WATERHOUSE
Syracuse, New York January 27, 1994
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Nos. 33-36189, 33-42720, 33- 42721 and 33-42771) and to the incorporation by reference in the Prospectus constituting part of the Registration Statement on Form S-3 (Nos. 33-45898, 33-50703, 33-51073, 33-55546 and 33- 59594) of Niagara Mohawk Power Corporation of our report dated January 27, 1994 included in the Company's Form 10-K dated March 24, 1994. We also consent to the incorporation by reference of our report on the financial statement schedules of this Form 10-K.
PRICE WATERHOUSE
Syracuse, New York March 24, 1994
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
(In Thousands of Dollars)
Column A Column B
Item Charged to Costs and Expenses 1993 1992 1991
Taxes, other than payroll and income taxes:
Land and improvement, $241,421 $240,242 $220,586 including special franchise State and Municipal 169,966 135,262 tax on gross revenues 170,310
New York State 31,252 28,549 27,509 franchise Other 24,263 22,013 19,601
Taxes charged to (10,969) (9,632) (10,331) construction
Total taxes, other 456,277 451,138 392,627 than payroll and income taxes Payroll taxes 44,866 42,916 37,256
Payroll taxes charged to (9,780) (9,221) (9,305) construction Total taxes charged to $491,363 $484,833 $420,578 costs and expenses
Taxes, charged to other $ 627 $ 812 $ 1,159 income accounts
Note: Charges for maintenance expenditures, other than those set forth in the Consolidated Statements of Income, are charged to clearing accounts which are subsequently distributed to various asset and expense accounts on the basis of usage.
NIAGARA MOHAWK POWER CORPORATION List of Exhibits
In the following exhibit list, NMPC refers to the Company and CNYP refers to Central New York Power Corporation. Each document referred to below is incorporated by reference to the files of the Commission, unless the reference to the document in the list is preceded by an asterisk. Previous filings with the Commission are indicated as follows:
A--NMPC Registration Statement No. 2-8214; C--NMPC Registration Statement No. 2-8634; F--CNYP Registration Statement No. 2-3414; G--CNYP Registration Statement No. 2-5490; U--NMPC Registration Statement No. 2-10023; V--NMPC Registration Statement No. 2-10501; W--NMPC Registration Statement No. 2-10875; X--NMPC Registration Statement No. 2-12443; Y--NMPC Registration Statement No. 2-12973; Z--NMPC Registration Statement No. 2-13285; AA--NMPC Registration Statement No. 2-13573; BB--NMPC Registration Statement No. 2-14114; CC--NMPC Registration Statement No. 2-16193; DD--NMPC Registration Statement No. 2-18995; EE--NMPC Registration Statement No. 2-22904; GG--NMPC Registration Statement No. 2-25526; HH--NMPC Registration Statement No. 2-26918; II--NMPC Registration Statement No. 2-29575; JJ--NMPC Registration Statement No. 2-35112; KK--NMPC Registration Statement No. 2-38083; LL--NMPC Registration Statement No. 2-42811; MM--NMPC Registration Statement No. 2-45017; NN--NMPC Registration Statement No. 2-47044; OO--NMPC Registration Statement No. 2-49570; PP--NMPC Registration Statement No. 2-51084; QQ--NMPC Registration Statement No. 2-51934; SS--NMPC Registration Statement No. 2-52852; TT--NMPC Registration Statement No. 2-54017; UU--NMPC Registration Statement No. 2-54291; VV--NMPC Registration Statement No. 2-59500; YY--NMPC Registration Statement No. 2-61598; ZZ--NMPC Registration Statement No. 2-62927; AAA--NMPC Registration Statement No. 2-65219; BBB--NMPC Registration Statement No. 2-67914; CCC--NMPC Registration Statement No. 2-70860; DDD--NMPC Registration Statement No. 2-74165; EEE--NMPC Registration Statement No. 2-79921; FFF--NMPC Registration Statement No. 2-81708; GGG--NMPC Registration Statement No. 2-85366; HHH--NMPC Registration Statement No. 2-91527; III--NMPC Registration Statement No. 2-90568; JJJ--NMPC Registration Statement No. 33-10743; KKK--NMPC Registration Statement No. 33-20847; MMM--NMPC Registration Statement No. 33-24755; NNN--NMPC Registration Statement No. 33-27401; OOO--NMPC Registration Statement No. 33-32475; PPP--NMPC Registration Statement No. 33-38093; QQQ--NMPC Registration Statement No. 33-47241; RRR--NMPC Registration Statement No. 33-59594;
SSS--NMPC Registration Statement No. 33-51073;
a--NMPC Annual Report on Form 10-K for year ended December 31, 1989; b--NMPC Annual Report on Form 10-K for year ended December 31, 1990; and c--NMPC Annual Report on Form 10-K for year ended December 31, 1992.
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.
NIAGARA MOHAWK POWER CORPORATION (Registrant)
Date March 24, 1994 By/s/ Steven W. Tasker Steven W. Tasker Vice President-Controller and Principal 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.
Signature Title Date
/s/ William F. Allyn Director March 24, 1994 William F. Allyn
/s/Lawrence Burkhardt,III Director March 24, 1994 Lawrence Burkhardt, III
/s/ Douglas M. Costle Director March 24, 1994 Douglas M. Costle
/s/ Edmund M. Davis Director March 24, 1994
Edmund M. Davis
Chairman of the Board of Directors and Chief Executive /s/ William E. Davis Officer March 24, 1994 William E. Davis
/s/ William J. Donlon Director March 24, 1994 William J. Donlon
/s/ Edward W. Duffy Director March 24, 1994 Edward W. Duffy
Signature Title Date
/s/ John M. Endries Director and President March 24, 1994 John M. Endries
/s/ Bonnie Guiton Hill Director March 24, 1994 Dr. Bonnie Guiton Hill
/s/ John G. Haehl, Jr. Director March 24, 1994 John G. Haehl, Jr.
/s/ Henry A. Panasci,Jr. Director March 24, 1994 Henry A. Panasci, Jr.
/s/ Patti McGill Peterson Director March 24, 1994 Dr. Patti McGill Peterson
/s/ Donald B. Riefler Director March 24, 1994 Donald B. Riefler
Director March 24, 1994 Stephen B. Schwartz
/s/ John G. Wick Director March 24, 1994 John G. Wick
Senior Vice President and Principal Financial /s/ John W. Powers Officer March 24, 1994 John W. Powers
Vice President-Controller and Principal Accounting
/s/ Steven W. Tasker Officer March 24, 1994 Steven W. Tasker