ITEM 1. BUSINESS
The following are discussed under the general heading of "Business". Reference is made to the various other Items as applicable.
GENERAL
Incorporated in 1904 in the State of New York, the Company supplies electric and gas service wholly within that State. It produces and distributes electricity and distributes gas in parts of nine counties centering about the City of Rochester. At December 31, 1993 the Company had 2,536 employees.
The Company's service area has a population of approximately one million and is well diversified among residential, commercial and industrial consumers. In addition to the City of Rochester, which is the third largest city and a major industrial center in New York State, it includes a substantial suburban area with commercial growth and a large and prosperous farming area. A majority of the industrial firms in the Company's service area manufacture consumer goods. Many of the Company's industrial customers are nationally known, such as Xerox Corporation, Eastman Kodak Company, General Motors Corporation, Mobil Corporation and Bausch & Lomb Incorporated.
Energyline Corporation, a wholly owned subsidiary, was formed by the Company as a gas pipeline corporation to fund the Company's investment in the Empire State Pipeline. The Company has invested a net amount of approximately $10 million in Energyline as of December 31, 1993.
The business of the Company is seasonal. With respect to electricity, winter peak loads are attained due to spaceheating sales and shorter daylight hours and summer peak loads are reached due to the use of air-conditioning and other cooling equipment. With respect to gas, the greatest sales occur in the winter months due to spaceheating usage.
In each of the communities in which it renders service, the
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Company, with minor exceptions, holds the necessary municipal franchises, none of which contains burdensome restrictions. The franchises are non-exclusive, and are either unlimited as to time or run for terms of years. The Company anticipates renewing franchises as they expire on a basis substantially the same as at present.
Information concerning revenues, operating profits and identifiable assets for significant industry segments is set forth in Note 4 of the Notes to the Company's financial statements under Item 8. Information relating to the principal classes of service from which electric and gas revenues are derived and other operating data are included herein under "Operating Statistics". A discussion of the causes of significant changes in revenues is presented in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations. Percentages of the Company's operating revenues derived from electric and gas operations for each of the last three years are as follows:
FINANCING AND CAPITAL REQUIREMENTS PROGRAM
A discussion of the Company's capital requirements and the resources available to meet such requirements may be found in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations. In addition to those issues discussed in Item 7, the sale of additional securities depends on regulatory approval and the Company's ability to meet certain requirements contained in its mortgage and Restated Certificate of Incorporation.
Under the New York State Public Service Law, the Company is required to secure authorization from the Public Service Commission of the State of New York (PSC) prior to issuance of any stock or any debt having a maturity of more than one year.
The Company's First Mortgage Bonds are issued under a General Mortgage dated September 1, 1918, between the Company and Bankers Trust Company, as Trustee, which has been amended and supplemented by thirty-nine supplemental indentures. Before additional First Mortgage Bonds are issued, the following financial requirements must be satisfied:
(a) The First Mortgage prohibits the issuance of additional First Mortgage Bonds unless earnings (as defined) for a period of twelve months ending not earlier than sixty days prior to the issue date of the additional bonds are at least 2.00 times the annual interest charges on First Mortgage Bonds, both those outstanding and those proposed to be outstanding. The ratio under this test for the twelve months ended December 31, 1993 was 4.52.
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(b) The First Mortgage also provides that, if additional First Mortgage Bonds are being issued on the basis of property additions (as defined), the principal amount of the bonds may not exceed 60% of available property additions. As of December 31, 1993 the amount of additional First Mortgage Bonds which could be issued on that basis was approximately $332,408,000. In addition to issuance on the basis of property additions, First Mortgage Bonds may be issued on the basis of 100% of the principal amount of other First Mortgage Bonds which have been redeemed, paid at maturity, or otherwise reacquired by the Company. As of December 31, 1993, the Company could issue $160,584,000 of Bonds against Bonds that have matured or been redeemed.
The Company's Restated Certificate of Incorporation (Charter) provides that, without consent by two-thirds of the votes entitled to be cast by the preferred stockholders, the Company may not issue additional preferred stock unless in a 12-month period within the preceding 15 months: (a) net earnings applicable to payment of dividends on preferred stock, after taxes, have been at least 2.00 times the annual dividend requirements on preferred stock, including the shares both outstanding and proposed to be issued, and (b) net earnings available for interest on indebtedness, after taxes, have been at least 1.50 times the annual interest requirements on indebtedness and annual dividend requirements on preferred stock, including the shares both outstanding and proposed to be issued. For the twelve months ended December 31, 1993, the coverage ratio under (b) above (the more restrictive provision) was 2.23.
The Company's Charter also provides that, without consent by a majority of the votes entitled to be cast by the preferred stockholders, the Company may not issue or assume any unsecured indebtedness in excess of 15% of the total of its outstanding bonds and any other secured indebtedness plus its capital and surplus. At December 31, 1993, including the $51.3 million of unsecured indebtedness already outstanding, the Company was able to issue $70.5 million of unsecured debt under this provision. The Company also has unsecured short-term credit facilities totaling $70 million. Interim financing is available through short-term borrowings under a $90 million revolving credit agreement which expires December 31, 1996. In order to be able to use its revolving credit agreement, the Company created a subordinate mortgage which secures borrowings under its revolving credit agreement that might otherwise be restricted by this provision of the Company's Charter. The subordinate mortgage provides that the aggregate principal amount of bonds outstanding under the First Mortgage together with all borrowings under the revolving credit agreement will not exceed 70% of available property additions. At December 31, 1993, this provision would not restrict borrowings under the revolving credit agreement. In addition, the Company has a loan and security agreement with a domestic bank providing for up to $20 million of short-term debt. Borrowings under this agreement, which extends to December 31, 1994, are secured by the Company's accounts receivable. At December 31, 1993, the Company had $68 million of short-term debt outstanding consisting of $51 million unsecured short- term debt and $17 million of secured short-term debt.
The Company's Charter does not contain any financial tests for the
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issuance of preference or common stock.
REGULATORY MATTERS
The Company is subject to regulation by the PSC under New York statutes, by the Federal Energy Regulatory Commission (FERC) as a licensee and public utility under the Federal Power Act and by the Nuclear Regulatory Commission (NRC) as a licensee of nuclear facilities.
The National Energy Policy Act (Energy Act), signed into law in 1992 is the most comprehensive energy bill in more than a decade and impacts virtually every sector of the U.S. energy industry. Major provisions of the Energy Act, as they relate to the Company, include energy efficiency, promoting competition in the electric power industry at the wholesale level, streamlining of federal licensing of nuclear power plants, encouraging development and production of coal resources and ensuring that a new class of independent power producers established under the bill as well as qualified facilities and other electric utilities can achieve access to utility-owned transmission lines upon payment of appropriate prices. Under the Energy Act, FERC may order utilities to provide wholesale transmission services for others only if, among other things, the order meets certain requirements as to cost recovery and fairness of rates. This law prohibits FERC from ordering retail wheeling, which is power to be transmitted directly to a customer from a supplier other than the customer's local utility. The law, however, does not prevent state regulatory commissions from allowing or ordering intrastate retail wheeling; and, New York State is currently considering the issue of retail wheeling through various studies and hearings. The Company believes this Act could lead to enhanced competition among the Company and other service providers in the electric industry.
In April 1992 FERC issued Order No. 636 with the intention of fostering competition in the gas supply industry and improving access of customers to gas supply sources. In essence, FERC Order No. 636 requires interstate natural gas companies to offer customers "unbundled", or separate, sales and transportation services. FERC Order 636 offers an opportunity for the Company and other gas utilities to negotiate directly with gas producers for supplies of natural gas. With the unbundling of services, primary responsibility for reliable natural gas supply has shifted from interstate pipeline companies to local distribution companies, such as the Company. Since 1988 the Company has endeavored to diversify both its natural gas supply sources and the pipelines on which that supply is delivered to the Company's distribution system. With the unbundling of services as required under FERC Order 636 and the commencement of Empire State Pipeline operation, the Company has successfully achieved those goals, which should enhance its competitive position.
In 1988 the PSC ordered New York utilities to submit proposals to implement a competitive bidding procedure for new electric generation. In response to this requirement, the Company filed with the PSC (and thereafter amended such filings as required by the PSC) its proposed request for proposals (RFP) for the bidding of capacity additions and certain demand side management (DSM) measures. On September 11, 1990,
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the Company issued an RFP to purchase 70,000 kilowatts (Kw) of capacity or capacity savings. Of this total resource block, 20,000 Kw was set aside for DSM projects implemented within the Company's service territory while the remaining 50,000 Kw could be filled either by some form of generation directly interconnected to the electric system within or outside the Company's service territory or by additional DSM projects. The Company expressed a strong preference for peaking capacity in the RFP. The Company announced the successful bids in October 1991. Contract negotiations have been completed with three successful bidders of DSM projects resulting in contracts to supply 20.6 MW of capacity savings to be phased-in over the 1993-1996 period. Contract negotiations continue with one successful bidder for .125 MW of capacity savings. One successful bidder decided not to go forward with a proposal for 3 MW of capacity savings. A joint New York State utility analysis completed in late August 1991 concluded that capacity reserves on a statewide basis would exceed required levels until after the long-range planning period, or through and beyond the year 2007. Based on this analysis, the Company determined that its remaining needs could be more economically met through spot market purchases of capacity more closely tailored to its year-to-year requirements than by a long-term supply commitment. As a result, no contracts were offered to sponsors of supply-side proposals. On September 1, 1993 the Company issued an RFP for 3 MW of summer peak capacity savings at one of its facilities. Four proposals were received on October 20, 1993. A contract was executed on December 1, 1993. This project is expected to be completed in 1996.
In June 1992, the Company filed with the PSC an Integrated Resource Plan (IRP), which is a long-range plan used to examine future options with regard to generating resources and alternative methods of meeting electric capacity requirements. The plan covers a 15-year period, beginning in 1992, and provides current strategies and alternatives for meeting the Company's customers' energy requirements in a changing business and technological environment. The IRP takes into account anticipated capacity requirements and available resource options, as well as factors such as reliability, price of product, public acceptance, financial integrity, environmental issues, the competitive marketplace, demand side management and potential new technologies.
One result of the IRP was the decision made by the Company in December 1992 to replace the two steam generators at the Ginna nuclear plant in 1996. Like similar plants, the Ginna nuclear plant has experienced degradation in some of the tubes that make up each steam generator. About 30 percent of these tubes have required repair. In addition, a chemical buildup in some of the tubes has reduced their heat transfer capability. Both conditions would continue to erode the plant's performance if the existing steam generators were left in place. Installation of new steam generators was determined by the Company to be the most cost-effective, reliable and environmentally compatible option for the plant. The new steam generators should result in reduced maintenance costs and help sustain a high level of plant availability. Cost of replacement is estimated at $115 million, and preparation to replace these generators began during the plant's routine 1993 fuel outage.
As a part of the on-going IRP process, the Company in mid-1993 made
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a decision to place Unit 1 at Russell Station (47 MW) on cold standby, while modifying Units 2, 3 and 4 to meet Federal Environmental Protection Agency standards. Unit 1 is expected to be in cold standby in early 1994. Modification of Units 3 and 4 is expected to be completed by March 1995 at a cost of approximately $4.6 million. In addition, Unit 12 at Beebee Station and Unit 2 at Russell Station will be adjusted to produce fewer nitrogen oxides (NOx) by converting a third of the burners in each to achieve overfire air capability at a cost of approximately $1.2 million. These actions will allow the Company to comply with Phase I -Title I, NOx controls requirements of the Federal Clean Air Act, to meet projected load demands in its service territory, and to maintain a mix of fuel generation while remaining competitive and retaining wholesale opportunities.
Outlined below are other results of the IRP process to date:
- The plan calls for evaluating the possibility of using either alternative generation or current generating equipment in partnership with certain large industrial customers.
- The Company will continue to use demand side management programs to reduce the need for generating capacity.
- The Company will consider phasing out the coal-fired Beebee Station by the year 2000, unless it is converted to natural gas and operated under a partnership arrangement with a large customer.
The Company is subject to regulation of rates, service, and sale of securities, among other matters, by the PSC. On August 24, 1993 the PSC issued an order approving a settlement agreement (1993 Rate Agreement) among the Company, PSC Staff and other interested parties. This agreement resolves the Company's rate case proceedings initiated in July 1992. Retroactive application of new rates to July 1, 1993 was authorized by the PSC. The 1993 Rate Agreement will determine the Company's rates through June 30, 1996 and includes certain incentive arrangements providing for both rewards and penalties. The 1993 Rate Agreement is discussed below.
A summary of recent PSC rate decisions is presented in the table below. The 1993 Rate Agreement amounts are based on an allowed return on common equity of 11.50% through June 30, 1996. Earnings between 8.50% and 14.50% will be absorbed/retained by the Company. Earnings above 14.50% will be refunded to the customers. If, but not unless, earnings fall below 8.50%, or if cash interest coverage falls below 2.2 times, the Company can seek relief by petitioning the PSC for a review of the 1993 Rate Agreement terms.
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* See below for additional details.
The following measures were incorporated into the 1993 Rate Agreement:
- Incentive mechanisms that have the potential to either increase or reduce earnings from 5 to 70 basis points each, depending on the Company's ability to meet a variety of prescribed targets in the areas of electric fuel costs, demand side management, service quality and integrated resource management (relative electric production efficiency). During the rate year ending July 30, 1994, these incentives have the potential to affect earnings by approximately $12 million.
- Mechanisms for sharing costs between customers and shareholders for operation and maintenance expenses. In general, non-fuel operation and maintenance expense variations are treated in three different ways depending upon the amount of control the Company can exert over them. Those costs that are directly manageable (approximately $172 million in the first rate year) have no sharing and are absorbed by the Company, those costs that are not significantly affected by management action in the short run (approximately $34 million in the first rate year) are trued up 100% and variances resulting from all other such costs (approximately $110 million in the first rate year) are shared 50% by customers and 50% by the Company.
- Mechanisms for sharing 50% of overspending variances between forecasted and actual electric capital expenditures related to production and transmission facilities. The Company will retain the savings for cost of money and depreciation on underspending variances. The settlement also provides for a sharing mechanism regarding the replacement of the Ginna nuclear station steam generators. A graduated sharing percentage is applied for up to $15 million of variances, plus or minus, from the forecasted cost of $115 million. Variances above $130 million or below $100 million are absorbed by the Company.
- An Electric Revenue Adjustment Mechanism designed to stabilize electric revenues by eliminating the impact of variations in electric sales. A gas weather normalization clause previously in place was retained.
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To the extent incentive and sharing mechanisms apply, the negotiated revenue increase shown in the table above may be adjusted up or down in the second and third year of the agreement. As shown in the table below negotiated electric rate increases could be reduced to zero or increased up to an additional 1.5% in year two, 1.6% in year three and 1.8% in the following year. Negotiated gas rate increases could also be reduced to zero or increased up to an additional 0.8% in year two, 0.9% in year three and 1.1% in the following year, exclusive of the impact of the Empire State Pipeline going into service.
In July 1993 the Company requested approval from the PSC for a new flexible pricing tariff for major industrial and commercial electric customers. A settlement in this matter was filed with the PSC on November 19, 1993 and a decision on whether or not to approve the settlement is expected early in 1994. Such a tariff would allow the Company to negotiate competitive electric rates at discount prices to compete with alternative power sources, such as customer-owned generation facilities. Under the terms of the settlement, the Company would absorb 30 percent of any net revenues lost as a result of such discounts through June 1996, while the remainder would be recovered from other customers. The portion recoverable after June 1996 is expected to be determined in a generic proceeding currently being conducted by the PSC.
In September 1993 the PSC instituted a formal proceeding to investigate what the Company believes are undercharges to gas customers for certain gas purchases for the period August 1990 to August 1992. The Company's estimate of these undercharges is approximately $7.5 million, of which $2.3 million had been previously expensed and $5.2 million had been deferred on the Company's balance sheet. The Company wrote off the $2.0 million balance of the undercharges as of December 31, 1993. See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of operations under the subheading "New York State Public Service Commission" and Item 8, Note 10 - Commitments and Other Matters under the subheading "Gas Purchase Undercharges" for a further discussion.
COMPETITION
The Company is operating in an increasingly competitive environment. In its electric business, this environment includes a federal trend toward deregulation and a state trend toward incentive regulation. In addition, excess capacity in the region, new technology and cost pressures on major customers have created incentives for major
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customers to investigate different electric supply options. Initially, those options will include various forms of self generation, but may eventually include customer access to the transmission system in order to purchase electricity from suppliers other than the Company. As discussed under the Regulatory Matters section, the passage of the National Energy Policy Act of 1992 has accelerated these competitive challenges.
The Company accepts these challenges and is working to anticipate the impact of the increased competition. Its Business Plan, both in detail for one year and in summary for five years, focuses on improving service while reducing expenses. The Company is engaged in a continuous process improvement program to find opportunities for improved service and efficiency and has implemented an early retirement program in which 173 people, representing approximately seven percent of its workforce, have retired early and will not be replaced. In addition, the Company has agreed to a three-year rate settlement which includes caps on rate increases that approximate or are less than projected inflation, contains incentive programs that tie performance to earnings and stabilizes revenue through revenue adjustment mechanisms. An agreement has been reached with the PSC Staff and others on the terms of a competitive rate tariff that would allow negotiated rates with larger industrial and commercial customers that have competitive electric supply options. These regulatory changes are discussed in more detail in the Regulatory Matters section.
Competition in the Company's gas business has existed for some time, as the larger customers have had the option of obtaining their own gas supply and transporting it through the Company's distribution system. This process has been accelerated with FERC Order 636, discussed in more detail in the Regulatory Matters section above. In addition, the Company has responded to the changes in the gas business by positioning itself to obtain greater access to both US and Canadian natural gas supplies and storage, so that it can take advantage of the unbundling of services that results from FERC Order 636. A major element of this strategy went into place in 1993 with the start-up of the Empire State Pipeline. The Company is engaged in various aspects of capacity release and is investigating other options available to it to mitigate its cost and increase its revenue in the new gas regulatory environment.
Beyond the Company's efforts to remain competitive in its core business, it is conducting a broad review of its general business strategy to identify opportunities that will exist in this changed environment. This may result in expansion of various elements of the core business or engaging in new, but related, business activity.
ELECTRIC OPERATIONS
The total net generating capacity of the Company's electric system is 1,237,000 Kw. In addition the Company purchases 120,000 Kw of firm power under contract and 35,000 Kw of non-contractual peaking power from the Power Authority, 150,000 Kw of a 1,000,000 Kw pumped storage plant owned by the Power Authority in Schoharie County, New York, 22,000 Kw of firm power from the Power Authority's 821,000 Kw FitzPatrick Nuclear Power Plant near Oswego, New York and 20,000 Kw of firm power from Hydro-
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Quebec purchased through the Power Authority. The Company's net peak load of 1,333,000 Kw occurred on July 8, 1993.
The percentages of electricity generated and purchased for the years 1989-1993 are as follows:
The Company, six other New York utilities and the Power Authority are members of the New York Power Pool. The primary purposes of the Power Pool are to coordinate inter-utility sales of bulk power, long range planning of generation and transmission facilities, and inter- utility operating and emergency procedures in order to better assure reliable, adequate and economic electric service throughout the State. By agreement with the other members of the New York Power Pool, the Company is required to maintain a reserve generating capacity equal to at least 18% of its forecasted peak load. The Company expects to have reserve margins, which include purchased energy under long term firm contractual arrangements, of 25%, 26% and 30%, for the years 1994, 1995 and 1996, respectively.
The Company's five major generating facilities are two nuclear units, the Ginna Nuclear Plant and the Company's 14% share of Nine Mile Point Nuclear Plant Unit No. 2 (Nine Mile Two), and three fossil fuel generating stations, the Russell and Beebee Stations and the Company's 24% share of Oswego Unit Six. These comprise 38%, 12%, 21%, 6% and 16%, respectively, of the Company's current electric system generating capacity.
Nine Mile Two, a nuclear generating unit in Oswego County, New York with a capability of 1,080 megawatts (Mw), was completed and entered commercial service in Spring 1988. Niagara Mohawk Power Corporation (Niagara) is operating the Unit on behalf of all owners pursuant to a full power operating license which the NRC issued on July 2, 1987 for a 40-year term beginning October 31, 1986. Under arrangements dating from September 1975, ownership, output and cost of the project are shared by the Company (14%), Niagara (41%) Long Island Lighting Company (18%), New York State Electric & Gas Corporation (18%) and Central Hudson Gas & Electric Corporation (9%). Under the operating Agreement, Niagara serves as operator of Nine Mile Two, but all five cotenant owners shared certain policy, budget and managerial oversight functions. The base term of the Operating Agreement is 24 months from its effective date, with automatic extension, unless terminated by written notice of one or more of the cotenant owners to the other cotenant owners; such termination becomes effective six months from the receipt of any such notice of termination by all the cotenant owners receiving such notice. The owners petitioned the PSC in March 1993 for approval of the Operating Agreement and
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understand that action by the PSC will be taken thereon early in 1994.
The Company has four licensed hydroelectric generating stations with an aggregate capability of 49 megawatts. Although applications for renewal of those licenses were timely made in 1991, the FERC was unable to complete processing of many such applications by the December 31, 1993 license expiration. The Company and many other hydro project owners are thus operating under FERC annual licenses that essentially extend the terms of the old licenses year-to year until processing of new ones can be completed. The Company understands that renewal licenses for three of its four stations are scheduled to be issued by the second quarter of 1994, but a license for the fourth -- the smallest -- may be delayed or even denied depending on what environmental conditions are determined to apply to its continued operation. That determination, as well as decisions on what environmental conditions FERC will impose in new licenses for the other three stations, depends in part on the content of state water quality certifications issued by the New York State Department of Environmental Conservation (NYSDEC). Certifications NYSDEC issued for the Company's projects in late 1992 are in the process of revisions, owing to a November 1993 decision by the State of New York's highest court which, in a case brought by another utility licensee, held in effect that NYSDEC certifications exceeded the authority of the agency under applicable law. Draft revisions purporting to comply with that decision are currently under review in a NYSDEC administrative proceeding initially brought by the Company to challenge the 1992 certifications. Overly stringent environmental conditions or other governmental requirements could nullify or greatly impair the economic viability of one or more of the Company's hydro stations and could even compel it to abandon efforts to relicense the affected station or stations. If, however, conditions in the renewal licenses for these stations can be limited to those proposed by FERC Staff in its evaluation, the Company believes that it can continue to operate them economically.
The Company's Ginna Nuclear Plant, which has been in commercial operation since July 1, 1970, provides 470 Mw of the Company's electric generating capacity. In August 1991 the NRC approved the Company's application for amendment to extend the Ginna Nuclear Plant facility operating license expiration date from April 25, 2006 to September 18, 2009.
In December 1992, the Company announced that it will replace the two steam generators in the Ginna Nuclear Plant in 1996. Cost of the replacement is estimated at $115 million. The units themselves cost about $40 million, and installation will cost about $60 million. The remainder of the cost is for engineering, radiation protection, site support, interest charges and other services.
During 1993, fixed price contracts were issued for both the steam generators and for the installation. Preparation for the replacement began in 1993 and will continue until the replacement in 1996. Steam generator fabrication is well underway and detailed engineering will begin in 1994. The existing steam generators, once removed, will become low-level radioactive waste. They will be placed in a protective structure which will be built on site, pending as yet undetermined permanent disposal.
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Like similar plants, Ginna has experienced degradation in some of the 3,260 tubes that make up each steam generator. About 30 percent of the tubes have required repair. In addition, a chemical buildup on some of the tubes has reduced their ability to transfer heat, causing a loss in plant output of about 3 percent, or 15 megawatts. Both conditions would continue to erode the plant's performance if the existing steam generators were left in place. A number of design improvements have been incorporated into the new steam generators. These improvements combined with continued aggressive maintenance should result in a higher level of plant availability.
The decision regarding Ginna is one part of the Integrated Resource Plan (IRP) previously discussed. Installation of new steam generators was determined to be the most cost-effective, reliable and environmentally compatible option for the plant.
The gross and net book cost of the Ginna Plant as of December 31, 1993 are $470 million and $263 million, respectively. From time to time the NRC issues directives requiring all or a certain group of reactor licensees to perform analyses as to their ability to meet specified criteria, guidelines or operating objectives and where necessary to modify facilities, systems or procedures to conform thereto. Typically, these directives are premised on the NRC's obligation to protect the public health and safety. The Company is reviewing several such directives and is in the process of implementing a variety of modifications based on these directives and resulting analyses. Additional analyses and modifications can be expected. Expenditures, including AFUDC, at the Ginna Plant (including the cost of these modifications and $17.1 million in 1994, $30.6 million in 1995, and $51.4 million in 1996 for steam generator replacement as discussed above) are estimated to be $43.2 million, $57.0 million and $71.9 million for the years 1994, 1995 and 1996, respectively, and are included in the capital expenditure amounts presented under Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations.
See Item 8, Note 10 - Commitments and Other Matters, "Nuclear- Related Matters", for a discussion relating to nuclear insurance including information on coverages and maximum assessments.
GAS OPERATIONS
The total daily capacity of the Company's gas system, reflecting the maximum demand which the transmission system can accept without a deficiency, is 4,485,000 Therms (one Therm is equivalent to 1,000,000 British Thermal Units). On January 19, 1994, the Company experienced its maximum daily send out of approximately 4,740,000 Therms. If a deficiency exists, the Company is able to manually bypass the regulators in the system to meet a demand of up to 10% in excess of capacity.
As a result of the implementation of FERC Order 636, and the commencement of operation of the Empire State Pipeline (Empire), the Company now purchases all of its required gas supply from numerous producers and marketers under contracts containing varying terms and conditions. The Company anticipates no problem with obtaining reliable,
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competitively priced natural gas in the future. See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under the captions "Energy Costs and Supply - Gas" and "FERC Order 636" for a discussion of those topics and "Capital Requirements and Gas Operations" for a discussion of Empire.
The Company continues to provide new and additional gas service. Of 231,937 residential gas spaceheating customers at December 31, 1993, 3,841 were added during 1993, and 37% of those were conversions from other fuels.
Approximately 23% of the gas delivered to customers by the Company during 1993 was purchased directly by commercial, industrial and municipal customers from brokers, producers and pipelines. The Company provided the transportation of gas on its system to these customers' premises.
FUEL SUPPLY
NUCLEAR
Generally, the nuclear fuel cycle consists of the following: (1) the procurement of uranium concentrate (yellowcake), (2) the conversion of uranium concentrate to uranium hexaflouride, (3) the enrichment of the uranium hexaflouride, (4) the fabrication of fuel assemblies, (5) the utilization of the nuclear fuel in generating station reactors and (6) the appropriate storage or disposition of spent fuel and radioactive wastes. Arrangements for nuclear fuel materials and services for the Ginna Plant and Nine Mile Two have been made to permit operation of the units through the years indicated:
(1) Information was supplied by Niagara Mohawk Power Corporation.
(2) Arrangements have been made for procuring the majority of the uranium and conversion requirements through 2000, leaving the remaining portion of the requirements uncommitted.
(3) Seventy percent of the conversion requirements have been procured through 1997.
(4) Thirty years from 1984 or life of reactor, whichever is less. See the following discussion.
The Company has a contract with United States Enrichment Corporation (USEC) formerly with the federal Department of Energy (DOE)
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for nuclear fuel enrichment services which assures provision of 70% of the Ginna Plant's requirements throughout its service life or 30 years, whichever is less. No payment obligation accrues unless such enrichment services are needed. Annually, the Company is permitted to decline USEC-furnished enrichment for a future year upon giving ten years' notice. Consistent with that provision, the Company has terminated its commitment to USEC for the years 2000, 2001 and 2002. The USEC waived, for an interim period, the obligation to give ten years notice for 2003. The Company has secured the remaining 30% of its Ginna requirements for the reload years 1994 through 1995 under different arrangements with USEC. The Company plans to meet its enrichment requirements for years beyond those already committed by making further arrangements with USEC or by contracting with third parties. The cost of USEC enrichment services utilized for the next seven reload years (priced at the most current rate) range from $4 million to $7 million per year.
The Company is pursuing arrangements for the supply of uranium requirements and related services beyond those years for which arrangements have been made as shown above. The prices and terms of any such arrangements cannot be predicted at this time.
The average annual cost of nuclear fuel per million BTU used for electric generation for the last five years is as follows:
There are presently no facilities in operation in the United States available for the reprocessing of spent nuclear fuel from utility companies. In the Company's determination of nuclear fuel costs it has taken into account that nuclear fuel would not be reprocessed and has provided for disposal costs in accordance with the Nuclear Waste Policy Act discussed below. The Company currently has adequate interim storage capability at the Ginna Plant, including full core discharge capability through the year 1999 based on anticipated fuel usage.
The cost of nuclear fuel and estimated permanent storage costs of spent nuclear fuel are charged to operating expense on the basis of the thermal output of the reactor. These costs are charged to customers through the fuel cost adjustment clause and base rates.
The Nuclear Waste Policy Act (Act) of 1982, as amended, requires the DOE to establish a nuclear waste disposal site and to take title to nuclear waste. A permanent DOE high level nuclear waste repository is not expected to be operational before the year 2010. The DOE is pursuing efforts to establish a monitored retrievable interim storage facility which may allow it to take title to and possession of nuclear waste prior to the establishment of a permanent repository. The Act provides for a determination of the fees collectible by the DOE for the disposal of nuclear fuel irradiated prior to April 7, 1983 and for three payment options. The option of a single payment to be made at any time prior to the first delivery of fuel to the DOE was selected in June 1985. The Company estimates the fees, including accrued interest, owed to the DOE
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to be $68.1 million at December 31, 1993. The Company is allowed by the PSC to recover in rates these costs. The estimated fees are classified as a long term liability and interest is accrued at the three-month Treasury bill rate, adjusted quarterly. The Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of one mill ($.001) per Kwh of nuclear energy generated and sold. This charge is currently being collected from customers and paid to the DOE pursuant to PSC authorization. The Company expects to utilize on-site storage for all spent or retired fuel assemblies until an interim or permanent nuclear disposal facility is operational.
Decommissioning costs (costs to take the plant out of service in the future) for the Ginna Plant are estimated to be approximately $150.7 million, and those for the Company's 14% share of Nine Mile Two are estimated to be approximately $34.3 million (January 1993 dollars). Through December 31, 1993, the Company has accrued and recovered in rates $61.2 million for this purpose and is currently accruing for decommissioning costs at a rate of approximately $8.9 million per year based on the use of a combination of internal and external sinking funds.
See Notes 1 and 10 of the Notes to Financial Statements under Item 8 for additional information regarding nuclear plant decommissioning and DOE uranium enrichment facility decontamination and decommissioning.
COAL
The Company's present annual coal requirement is approximately 570,000 tons. In 1993 approximately 5% of its requirements were purchased under contract and the balance on the open market. The Company is meeting its requirements during early 1994 through contract purchases. Normally, the Company maintains a reserve supply of coal ranging from a 30 to a 60 day supply at maximum burn rates.
The sulfur content of the coal utilized in the Company's existing coal-fired facilities ranges from 1.4 to 1.9 pounds per million BTU. Under existing New York State regulations, the Company's coal-fired facilities may not burn coal which exceeds 2.5 pounds per million BTU, which averages more than 1.9 pounds per million BTU over a three-month period or which averages more than 1.7 pounds per million BTU over a 12-month period.
The average annual delivered cost of coal used for electric generation was as follows:
OIL
The Company's present annual requirement at Company-operated facilities is estimated at 800,000 gallons of #2 fuel oil. The Company currently intends to meet this requirement through competitively bid
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contracts.
ENVIRONMENTAL QUALITY CONTROL
Operations at the Company's facilities are subject to various Federal, state and local environmental standards. To assure the Company's compliance with these requirements, the Company expended approximately $1.0 million on a variety of projects and facility additions during 1993.
The most significant environmental control measures affecting Company operations involve the regulation of the quality of fuel burned in utility boilers, the evaluation to determine ambient air quality standards, the imposition of emission limitations on discharges into the air and effluent limitations and pretreatment standards on liquid discharges, the evaluation to determine water quality objectives for water bodies into which Company facilities discharge, the regulation of toxic substances and the disposal of solid wastes.
The Company is monitoring a public concern tending to associate health effects with electromagnetic fields from power lines. Together with other New York utilities, the Company funded some of the earliest governmentally-directed research on the question and it continues, with other electric utilities nationwide, to underwrite a broad program of industry-sponsored research in this area. The Company also participated with other New York utilities in compiling information on the state's existing high voltage lines in an initiative which served as a basis for PSC adoption of field limits applicable to the construction of new high voltage lines. The Company has no definitive plans to construct new high voltage lines for its system, but, in connection with Clean Air Act compliance and planning of generation resources, it is considering possible transmission reinforcements; at least one option could require such construction. On request, the Company performs surveys of electromagnetic fields on customer premises. None of its lines have been found to exceed the State field limits applicable to new construction.
The Federal Low Level Radioactive Waste Policy Act (Act), as amended in 1985, provides for states to join compacts or individually develop their own low level radioactive waste disposal sites. The portion of the Act that requires a state which fails to provide access to a licensed disposal site by 1996 to take title to such waste was declared unconstitutional by the United States Supreme Court on June 19, 1992, but the court upheld other provisions of the Act enabling sited states to increase charges on shipments from non-sited states and ultimately to refuse such shipments altogether. New York has entered into a contract with the State of South Carolina for the disposal of all low level radioactive waste through June 1994. The Company can provide no assurance as to what disposal arrangements, if any, New York will have in place after that date. The State has not passed legislation that would designate a site for the disposal of low level radioactive waste. In 1990, Governor Cuomo certified a plan that requires all nuclear power plants in New York State to store their low level radioactive waste on site from January 1, 1993, until the end of 1995. The Company has interim storage capacity at the Ginna Plant through December 31, 1995 and
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efforts are being pursued to extend storage capacity to mid-1999, if necessary, at this plant. A low level radioactive waste management and contingency plan is currently ongoing to provide assurance that Nine Mile Two will be properly prepared to handle interim storage of low level radioactive waste for the next ten years.
The Company has wastewater discharge permits from NYSDEC for its Beebee, Russell and Ginna Stations. The Russell Station permit is currently in the renewal process. The Beebee and Ginna Station permits were renewed in December 1993 and July 1992, respectively. While no significant changes are anticipated, modifications to the wastewater treatment systems may be necessary. The Company believes that any costs associated with such modifications would be fully recoverable in rates.
The Company believes that additional expenditures and costs made necessary by environmental regulations will be fully allowable for ratemaking purposes. Expenditures for meeting various Federal, State and local environmental standards are estimated to be $6.7 million for the year 1994, $4.8 million for the year 1995 and $3.9 million for the year 1996. These expenditures are included under Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, in the table entitled "Capital Requirements".
See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8, Note 10 - Commitments and Other Matters, with respect to other environmental matters.
RESEARCH AND DEVELOPMENT
The Company's research activities are designed to improve existing energy technologies and to develop new technologies for the production, distribution, utilization and conservation of energy while preserving environmental quality. Research and development expenditures in 1993, 1992 and 1991 were $8,329,278, $7,416,945, and $6,404,766, respectively. These expenditures represent the Company's contribution to research administered by Electric Power Research Institute and Empire State Electric Energy Research Corporation, the Company's share of research related to Nine Mile Two, an assessment for state government sponsored research by the New York State Energy Research and Development Authority, as well as internal research projects.
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Electric Department Statistics
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*Method for determining daily capacity, based on current network analysis, reflects the maximum demand which the transmission systems can accept without a deficiency.
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ITEM 2.


ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of the Company's electric generating plants in operation as of December 31, 1993, the net generation of each plant for the year ended December 31, 1993, and the year each plant was placed in service are as set forth below:
(1) Represents 24% share of jointly-owned facility. (2) Represents 14% share of jointly-owned facility. (3) Owned and operated by the Power Authority.
The Company owns 146 distribution substations having an aggregate rated transformer capacity of approximately 2,058,579 Kva, of which 137, having an aggregate rated capacity of 1,879,413 Kva, were
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located on lands owned in fee, and 9 of which, having an aggregate rated capacity of 179,166 Kva, were located on land under easements, leases or license agreements. The Company also has 73,950 line transformers with a capacity of 2,894,753 Kva. The Company also owns 24 transmission substations having an aggregate rated capacity of approximately 2,996,017 Kva of which 23, having an aggregate rated capacity of approximately 2,921,350 Kva, were located on land owned in fee and 1, having a rated capacity of 74,667 Kva, was located on land under easements. The Company's transmission system consists of approximately 702 wire miles of overhead lines and 396 wire miles of underground lines. The distribution system consists of approximately 15,987 wire miles of overhead lines, approximately 3,427 wire miles of underground lines and 340,546 installed meters. The electric transmission and distribution system is entirely interconnected and, in the central portion of the City of Rochester, is underground. The electric system of the Company is directly interconnected with other electric utility systems in New York and indirectly interconnected with most of the electric utility systems in the United States and Canada. (See Item 1 - Business, "Electric Operations".)
GAS PROPERTIES
The gas distribution systems consists of 4,175 miles of gas mains and 278,850 installed meters. (See Item 1 - Business, "Gas Operations".)
OTHER PROPERTIES
The Company owns a ten-story office building centrally located in Rochester, an Operations Center south of Rochester, and other structures and property.
The Company has good title in fee, with minor exceptions, to its principal plants and important units, except rights of way and flowage rights, subject to restrictions, reservations, rights of way, leases, easements, covenants, contracts, similar encumbrances and minor defects of a character common to properties of the size and nature of those of the Company. The electric and gas transmission and distribution lines and mains are located in part in or upon public streets and highways and in part on private property, either pursuant to easements granted by the apparent owner containing in some instances removal and relocation provisions and time limitations, or without easements but without objection of the owners. The First Mortgage securing the Company's outstanding bonds is a first lien on substantially all the property owned by the Company (except cash and accounts receivable). A mortgage securing the Company's revolving credit agreement is also a lien on substantially all the property owned by the Company (except cash and accounts receivable) subject and subordinate to the lien of the First Mortgage. The Company has a credit agreement with a domestic bank under which short term borrowings are secured by the Company's accounts receivable.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Note 10 - Commitments and Other Matters.
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ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of the fiscal year ended December 31, 1993.
ITEM 4 - A. EXECUTIVE OFFICERS OF THE REGISTRANT
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The term of office of each officer extends to the meeting of the Board of Directors following the next annual meeting of shareholders and until his or her successor is elected and qualifies.
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PART II
ITEM 5
ITEM 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
COMMON STOCK AND DIVIDENDS
Tax Status of Cash Dividends
Cash dividends paid in 1993, 1992 and 1991 were 100 percent taxable for Federal income tax purposes.
Dividend Policy
The Company has paid cash dividends quarterly on its Common Stock without interruption since it became publicly held in 1949. The level of future cash dividend payments will be dependent upon the Company's future earnings, its financial requirements and other factors. The Company's Certificate of Incorporation provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company.
Quarterly dividends on Common Stock are generally paid on the twenty-fifth day of January, April, July and October. In January 1994, the Company paid a cash dividend of $.44 per share on its Common Stock, up $.01 from the prior quarterly dividend payment of $.43. The January 1994 dividend payment is equivalent to $1.76 on an annual basis.
Common Stock Trading
Shares of the Company's Common Stock are traded on the New York Stock Exchange under the symbol "RGS".
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Item 6.
Item 6. Selected Financial Data
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(a) Includes Company's long term liability to the Department of Energy (DOE) for nuclear waste disposal. Excludes DOE long term liability for uranium enrichment decommissioning and amounts due or redeemable within one year.
(b) Excludes disallowed Nine Mile Two plant costs written off in 1989.
(c) The recognition by the Company in 1991 of a fuel procurement audit approved
by the New York State Public Service Commission (PSC) has been excluded from 1991 coverages. Likewise, recognition by the Company in 1992 of disallowed ice storm costs as approved by the PSC has been excluded from 1992 coverages. Coverages for 1993 exclude the effects of retirement enhancement programs recognized by the Company during the year and certain gas purchase undercharges written off in December 1993.
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ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is Management's assessment of significant factors which affect the Company's financial condition and operating results.
Liquidity and Capital Resources
During 1993 cash flow from operations, together with proceeds from external financing activity (see Consolidated Statement of Cash Flows), provided the funds for construction expenditures and the retirement and refinancing of long-term debt and preferred stock. Capital requirements during 1994, including debt maturity and sinking fund obligations, are anticipated to be satisfied primarily from the use of internally generated funds. Some external financing, mainly in the form of short-term debt, is expected to be incurred. Any refinancing activity would require additional external financing.
Projected Capital and Other Requirements
The Company's capital requirements relate primarily to expenditures for electric generation, transmission and distribution facilities and gas mains and services as well as the repayment of existing debt. Construction programs of the Company focus on the need to serve new customers, to provide for the replacement of obsolete or inefficient utility property and to modify facilities consistent with the most current environmental and safety regulations.
The Company has no current plans to install additional baseload generation. The Company either has contracts or is continuing negotiations for the realization of approximately 24 megawatts of capacity savings being phased- in over the 1993-1996 period under its demand side management program and, beginning in late 1994 or early 1995, expects approximately 55 megawatts of capacity to be supplied by a cogenerator under contract with the Company. The Company has no other obligations with non-utility generating companies at this time.
In June 1992 the Company filed with the New York State Public Service Commission (PSC) an Integrated Resource Plan (IRP)
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which is a long-range plan examining options for the future with regard to generating resources and alternative methods of meeting electric capacity requirements. The plan covers a 15-year period, beginning in 1992, and provides current strategies and alternatives for meeting customer energy requirements in a changing business and technological environment. The IRP takes into account anticipated capacity requirements and available resource options, as well as factors such as reliability, price of product, public acceptance, financial integrity, environmental issues, the competitive marketplace, demand side management and potential new technologies.
One result of the IRP was the decision made by the Company in December 1992 to replace the two steam generators at the Ginna nuclear plant in 1996. Like similar plants, the Ginna nuclear plant has experienced degradation in some of the tubes that make up each steam generator. About 30 percent of these tubes have required repair. In addition, a chemical buildup in some of the tubes has reduced their heat transfer capability. Both conditions would continue to erode the plant's performance if the existing steam generators were left in place. Installation of new steam generators was determined by the Company to be the most cost-effective, reliable and environmentally compatible option for the plant. The new steam generators should result in reduced maintenance costs and help sustain a high level of plant availability. Cost of replacement is estimated at $115 million, and preparation to replace these generators began during the plant's routine 1993 fuel outage.
As a part of the on-going IRP process, the Company in mid-1993 made a decision to place Unit 1 at Russell Station (47 MW) on cold standby, while modifying Units 2, 3 and 4 with new burners to meet Federal Environmental Protection Agency standards. Unit 1 is expected to be in cold standby by early 1994. Modification of Units 3 and 4 is expected to be completed by March 1995 at a cost of approximately $4.6 million. In addition, Unit 12 at Beebee Station and Unit 2 at Russell Station will be adjusted to produce fewer nitrogen oxides (NOx) by converting a third of the burners in each to achieve overfire air capability at a cost of approximately $1.2 million. These actions will allow the Company to comply with Phase I - Title I, NOx controls requirements of the Federal Clean Air Act, to meet projected load demands in its service territory, and to maintain a mix of fuel generation while remaining competitive and retaining wholesale sales opportunities.
Outlined below are other results of the IRP process to date:
- The plan calls for evaluating the possibility of using either alternative generation or current generating equipment in partnership with certain large industrial customers.
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- The Company will continue to use demand side management programs to reduce the need for generating capacity.
- The Company will consider phasing out its coal-fired Beebee Station by the year 2000, unless it is converted to natural gas and operated under a partnership arrangement with a large customer.
The Company's capital expenditures program is under continuous review and will be revised depending upon the progress of construction projects, customer demand for energy, rate relief, government mandates and other factors. In addition to its projected construction requirements, the Company may consider, as conditions warrant, the redemption or refinancing of certain long- term securities.
Capital Requirements and Electric Operations
Electric production plant expenditures in 1993 included $42 million of expenditures made at the Company's Ginna nuclear plant, of which $15 million was incurred for preparation to replace the steam generators. In addition, nuclear fuel expenditures of $11 million were incurred at Ginna during 1993. A refueling outage at Ginna normally occurs annually for a period of approximately 40 to 50 days.
Exclusive of fuel costs, the Company's 14 percent share of electric production plant expenditures at the Nine Mile Two nuclear facility totaled $6 million in 1993. Expenditures of $5 million during 1993 were made for the Company's share of nuclear fuel at Nine Mile Two. On October 2, 1993 Nine Mile Two was taken out of service for a scheduled refueling outage. Refueling was completed and Nine Mile Two resumed full operation on December 3, 1993. The prior refueling outage occurred in 1992 from early March to early July. The next refueling outage for Nine Mile Two is anticipated to begin in May 1995.
Electric transmission and distribution expenditures, as presented in the Capital Requirements table, totaled $29 million in 1993, of which $24 million was for the upgrading of electric distribution facilities to meet the energy requirements of new and existing customers.
Capital Requirements and Gas Operations
Construction began in June 1993 on the Empire State Pipeline (Empire), an intrastate natural gas pipeline subject to PSC regulation between Grand Island and Syracuse, New York. The Company received its first gas deliveries through the pipeline in early November 1993. This pipeline will provide capacity for up to 50 percent of the Company's gas requirements by its second
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year of operation. The Company is participating as an equity owner of Empire, along with subsidiaries of Coastal Corporation and Westcoast Energy Inc. In June 1991 the PSC authorized the Company to invest up to $20 million in Empire subject to certain conditions, notably that the investment not be included in rate base. In 1992 the Company formed a wholly owned subsidiary, Energyline Corporation, to acquire its ownership interest in Empire. The Company's share of ownership in Empire will be dependent upon final project costs and the timing and method of financing selected by the Company. In June 1993 Empire secured a $150 million credit agreement, the proceeds of which are to finance approximately 75 percent of the total construction cost. At December 31, 1993 the Company had invested a net amount of $10.2 million in Energyline ($9.9 million in 1992 and $0.3 million in 1993) and was committed for $9.7 million of the borrowings under the credit agreement. In December 1993 the Company's investment in Energyline was consolidated for accounting and reporting purposes into the accounts of the Company. Such consolidation resulted in a $0.5 million charge to Other Income during 1993.
In addition to the Empire project discussed above, construction expenditures in the Gas Department totaled $20 million and were principally for the replacement of older cast iron mains with longer-lasting and less expensive plastic and coated steel pipe, the relocation of gas mains for highway improvement, and the installation of gas services for new load.
Environmental Issues
The production and delivery of energy are necessarily accompanied by the release of by-products subject to environmental controls. In recognition of the Company's responsibility to preserve the quality of the air, water, and land it shares with the community it serves, the Company has taken a variety of measures (e.g., self-auditing, recycling and waste minimization, training of employees in hazardous waste management) to reduce the potential for adverse environmental effects from its energy operations and, specifically, to manage and appropriately dispose of wastes currently being generated. The Company, nevertheless, has been contacted, along with numerous others, concerning wastes shipped off-site to licensed treatment, storage and disposal sites where authorities have later questioned the handling of such wastes. In such instances, the Company typically seeks to cooperate with those authorities and with other site users to develop cleanup programs and to fairly allocate the associated costs.
As a part of its commitment to environmental excellence, the Company is conducting proactive Site Investigation and Remediation (SIR) efforts at Company-owned sites where past waste handling and disposal may have occurred.
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The Company currently estimates the total costs it could incur for SIR activities at Company-owned sites to be about $20 million. This estimate will vary as better site information is available. The Company anticipates spending $10 million over the next 5 years on SIR initiatives. Approximately $4.5 million has been provided for in rates through June 1996 for recovery of SIR costs. To the extent actual expenditures differ from this amount, they will be deferred for future disposition and recovery as authorized by the PSC. Additional environmental issues are discussed in Note 10 of the Notes to Financial Statements.
The Company is developing strategies responsive to the Federal Clean Air Act Amendments of 1990 (Amendments). The Amendments primarily affect air emissions from the Company's fossil-fueled electric generating facilities (see Note 10 of the Notes to Financial Statements). The Company is in the process of identifying the optimum mix of control measures that will allow the fossil fuel based portion of the generation system to fully comply with applicable regulatory requirements. Although work is continuing, not all compliance control measures have been determined. The Company has adopted control measures for NOx emissions which must be in effect by the federally mandated compliance date of May 31, 1995. These control measures are discussed under Projected Capital and Other Requirements. Capital costs for NOx controls and the installation of continuous emission monitoring systems are not expected to exceed $6.8 million and will be incurred during 1994 and 1995. A range of capital costs between $20 million and $30 million (1993 dollars) has been estimated for the implementation of several potential scenarios which would enable the Company to meet the foreseeable future NOx and sulphur dioxide requirements of the Amendments. These capital costs would be incurred between 1996 and 2000. The Company currently estimates that it could also incur up to $2 million (1993 dollars) of additional annual operating expenses, excluding fuel, to comply with the Amendments. The use of scrubbing equipment is not presently being considered. Likewise, the purchase or sale of "emission allowances", as allowed by the Amendments, is not currently being considered. The Company anticipates that the costs incurred to comply with the Amendments will be recoverable through rates based on previous rate recovery of environmental costs required by governmental authorities.
Competition
The Company is operating in an increasingly competitive environment. In its electric business, this environment includes a federal trend toward deregulation and a state trend toward incentive regulation. In addition, excess capacity in the region, new technology and cost pressures on major customers have created incentives for major customers to investigate different electric supply options. Initially, those options will include various forms of self generation, but may eventually include
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customer access to the transmission system in order to purchase electricity from suppliers other than the Company. As discussed under the Regulatory Matters section, the passage of the National Energy Policy Act of 1992 has accelerated these competitive challenges.
The Company accepts these challenges and is working to anticipate the impact of the increased competition. Its Business Plan, both in detail for one year and in summary for five years, focuses on improving service while reducing expenses. The Company is engaged in a continuous process improvement program to find opportunities for improved service and efficiency and has implemented an early retirement program in which 173 people, representing approximately seven percent of its workforce, have retired early and will not be replaced. In addition, the Company has agreed to a three-year rate settlement which includes caps on rate increases that approximate or are less than projected inflation, contains incentive programs that tie performance to earnings and stabilizes revenue through revenue adjustment mechanisms. An agreement has been reached with the PSC Staff and others on the terms of a competitive rate tariff that would allow negotiated rates with larger industrial and commercial customers that have competitive electric supply options. These regulatory changes are discussed in more detail in the Regulatory Matters section.
Competition in the Company's gas business has existed for some time, as the larger customers have had the option of obtaining their own gas supply and transporting it through the Company's distribution system. This process has been accelerated with FERC Order 636, discussed in more detail in the Regulatory Matters section. In addition to the matters discussed above, the Company has responded to the changes in the gas business by positioning itself to obtain greater access to both U.S. and Canadian natural gas supplies and storage, so that it can take advantage of the unbundling of services that results from FERC Order 636. A major element of this strategy went into place in 1993 with the start-up of the Empire State Pipeline. The Company is engaged in various aspects of capacity release and is investigating other options available to it to mitigate its cost and increase its revenue in the new gas regulatory environment.
Beyond the Company's efforts to remain competitive in its core business, it is conducting a broad review of its general business strategy to identify opportunities that will exist in this changed environment. This may result in expansion of various elements of the core business or engaging in new, but related, business activity.
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Redemption of Securities
Discretionary first mortgage bond redemptions totaled $120 million during 1993. A $75 million first mortgage bond maturity and $17 million of sinking fund obligations were also a part of the Company's capital requirements in 1993.
Capital requirements in 1992 included a $75 million first mortgage bond maturity, and discretionary first mortgage bond redemptions of $79.5 million.
Capital Requirements - Summary
The Company's capital program is designed to maintain reliable and safe electric and natural gas service, to improve the Company's competitive position, and to meet future customer service requirements. Capital requirements for the three-year period 1991 to 1993 and the current estimate of capital requirements through 1996 are summarized in the Capital Requirements table.
*Excludes prospective refinancings.
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For the period 1994 through 1996, the Company anticipates construction requirements to total approximately $493 million. Replacement of the steam generators at the Ginna nuclear plant is scheduled to be completed in 1996. Electric production plant expenditures over the period include $16 million in 1994, $29 million in 1995, and $50 million in 1996 for that replacement. In addition to its construction expenditures, the Company has security maturities and sinking fund obligations totaling $63 million over the three-year period 1994 through 1996. Excluded from the Capital Requirements table are expenditures associated with the Company's obligations to the United States Department of Energy for nuclear waste disposal and the Department of Energy's uranium enrichment facility decommissioning (see Notes 1 and 10 of the Notes to Financial Statements).
Financing and Capital Structure
Capital requirements in 1993 were satisfied by a combination of long- term debt and equity issues, internally generated funds, and short-term borrowings. Common shareholders equity increased during 1993 as the result of a public issue of one and one-half million shares of Common Stock in September. Favorable market conditions allowed the Company to refinance $120 million of its higher-cost long-term debt in 1993. In addition, the Company was able to refinance at a lower interest rate $75 million of its First Mortgage, 8.60% Bonds, Series LL, which matured on August 1. Such refinancing activity over the past three years has helped to reduce the annual cost of long-term debt by approximately $8.8 million and contributed to a drop in the Company's embedded cost of long-term debt from 8.6% at year-end 1990 to 7.4% at the end of 1993.
The Company believes that an average of approximately 85 percent to 90 percent of the funds required per year for its 1994 through 1996 construction program will be generated internally and the balance will be obtained through the issue of securities and short-term borrowings. The Company is utilizing its credit agreements to meet any interim external financing needs prior to issuing any long-term securities. As financial market conditions warrant, the Company may, from time to time, issue securities to permit the early redemption of higher-cost senior securities. The Company's financing program is under continuous review and may be revised depending upon the level of construction, financial market conditions, rate relief, cost of capital and other factors.
- Financing
Interim financing is available from certain domestic banks in the form of short-term borrowings under a $90 million revolving credit agreement which continues until December 31,
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1996 and may be extended annually. Borrowings under this agreement are secured by a subordinate mortgage on substantially all of the Company's property except cash and accounts receivable. In addition, the Company entered into a Loan and Security Agreement with a domestic bank until December 31, 1994 providing for up to $20 million of short-term debt. Borrowings under this agreement, which can be renewed annually, are secured by the Company's accounts receivable. The Company also has unsecured short-term credit facilities totaling $70 million. At December 31, 1993 the Company had short-term borrowings outstanding of $68.1 million, consisting of $51.3 million of unsecured short-term debt and $16.8 million of secured short-term debt.
Under provisions of the Company's Certificate of Incorporation (Charter), the Company may not issue unsecured debt if immediately after such issuance the total amount of unsecured debt outstanding would exceed 15 percent of the Company's total secured indebtedness, capital, and surplus without the approval of at least a majority of the holders of outstanding Preferred Stock. Under this restriction, the Company as of December 31, 1993 was able to issue $19.2 million of additional unsecured debt. Additional interim financing capability remains available with secured borrowings under the Company's credit agreements, as discussed above.
During 1993 the Company sold several issues of First Mortgage Bonds, Designated Secured Medium-Term Notes, Series A aggregating $200 million principal amount. Proceeds from the sale of the medium-term notes were used to redeem prior to maturity, at lower interest rates, $120 million principal amount of first mortgage bonds, to pay at maturity $75 million principal amount of first mortgage bonds and to repay short-term debt of $5 million.
In July 1993 the Company filed a shelf registration on Form S-3 providing for the offering of $250 million of new securities. The Company may use the shelf registration to offer, from time to time, its first mortgage bonds in one or more series, its Preferred Stock in one or more series and/or its Common Stock depending on market conditions and Company requirements. This Registration Statement became effective August 1993 and allows the Company financing flexibility regarding the timing of new issues. The net proceeds from the sale of the securities will be used to finance a portion of the Company's capital requirements, to discharge or refund certain outstanding indebtedness or preferred stock of the Company, to satisfy certain sinking fund obligations, or for general corporate purposes.
In September 1993 the Company sold 1,500,000 shares of new Common Stock in a public offering under the shelf
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registration discussed above. The offering raised $43.1 million in net proceeds, which were used to retire short-term debt incurred in the Company's construction program.
During 1993 approximately 515,000 new shares of Common Stock were sold through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan (ADR Plan), providing approximately $14.1 million to help finance its capital expenditures program. New shares issued in 1992 and 1993 through the ADR Plan were purchased from the Company at a market price above the book value per share at the time of purchase.
- Capital Structure
The public sale of Common Stock in 1992 and 1993 strengthened the Company's common equity. The Company's retained earnings at December 31, 1993 were $75.1 million, an increase of approximately $8.1 million compared with a year earlier. Common equity (including retained earnings) comprised 44.0 percent of the Company's capitalization at December 31, 1993, with the balance being comprised of 6.6 percent preferred equity and 49.4 percent long-term debt. At December 31, 1993 the Company had $21.3 million of long-term debt due within one year and $6.0 million of preferred stock redeemable within one year which, if included in capitalization, would increase the long-term debt component of capitalization at 1993 year-end to 49.8 percent, raise the preferred equity to 6.9 percent and reduce common equity to 43.3 percent of capitalization. As presented, these percentages are based on the Company's capitalization inclusive of its long-term liability to the United States Department of Energy (DOE) for nuclear waste disposal as explained in Note 1 of the Notes to Financial Statements. It is the Company's long-term objective to move to a less leveraged capital structure and to increase the common equity percentage of capitalization toward the 45 percent range. To improve its capital structure, the Company anticipates the issuance of new shares of common stock, primarily through the Company's ADR Plan, and will consider the redemption of higher-cost senior securities.
Regulatory Matters
- New York State Public Service Commission (PSC)
The Company is subject to regulation of rates, service, and sale of securities, among other matters, by the PSC. On August 24, 1993 the PSC issued an order approving a settlement agreement (1993 Rate Agreement) among the Company, PSC Staff and other interested parties. This agreement resolves the Company's rate case proceedings initiated in July 1992. Retroactive application of new rates to July 1, 1993 was authorized by the PSC. The 1993 Rate Agreement will determine the Company's rates through June 30, 1996 and includes certain incentive arrangements
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providing for both rewards and penalties. A summary of recent PSC rate decisions is presented in the table titled "Rate Increases". The 1993 Rate Agreement amounts are based on an allowed return on common equity of 11.50% through June 30, 1996. Earnings between 8.50% and 14.50% will be absorbed/retained by the Company. Earnings above 14.50% will be refunded to the customers. If, but not unless, earnings fall below 8.50%, or cash interest coverage falls below 2.2 times, the Company can seek relief by petitioning the PSC for a review of the 1993 Rate Agreement terms.
*See under heading Regulatory Matters for additional details
The following measures were incorporated into the 1993 Rate Agreement:
- Incentive mechanisms that have the potential to either increase or reduce earnings from 5 to 70 basis points each, depending on the Company's ability to meet a variety of prescribed targets in the areas of electric fuel costs, demand side management, service quality, and integrated resource management (relative electric production efficiency). During the rate year ending June 30, 1994, these incentives have the potential to affect earnings by approximately $12 million.
- Mechanisms for sharing costs between customers and shareholders for operation and maintenance expenses. In general, non-fuel operation and maintenance
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expense variations are treated in three different ways depending upon the amount of control the Company can exert over them. Those costs that are directly manageable (approximately $172 million in the first rate year) have no sharing and are absorbed by the Company, those costs that are not significantly affected by management action in the short run (approximately $34 million in the first rate year) are trued up 100% and variances resulting from all other such costs (approximately $110 million in the first rate year) are shared 50% by customers and 50% by the Company.
- Mechanisms for sharing 50% of overspending variances between forecasted and actual electric capital expenditures related to production and transmission facilities. The Company will retain the savings for cost of money and depreciation on underspending variances. The settlement also provides for a sharing mechanism regarding the replacement of the Ginna nuclear station steam generators. A graduated sharing percentage is applied for up to $15 million of variances, plus or minus, from the forecasted cost of $115 million. Variances above $130 million or below $100 million are absorbed by the Company.
- An Electric Revenue Adjustment Mechanism (ERAM) designed to stabilize electric revenues by eliminating the impact of variations in electric sales. A gas weather normalization clause previously in place was retained.
To the extent incentive and sharing mechanisms apply, the negotiated rate increases shown in the table titled "Rate Increases" may be adjusted up or down in the second and third year of the agreement. Negotiated electric rate increases could be reduced to zero or increased up to an additional 1.5% in year two, 1.6% in year three and 1.8% in the subsequent year. Negotiated gas rate increases could also be reduced to zero or increased up to an additional 0.8% in year two, 0.9% in year three, and 1.1% in the subsequent year, exclusive of the impact of the Empire State Pipeline going into service.
In July 1993 the Company requested approval from the PSC for a new flexible pricing tariff for major industrial and commercial electric customers. A settlement in this matter was filed with the PSC on November 19, 1993 and a decision on whether or not to approve the settlement is expected early in 1994. Such a tariff would allow the Company to negotiate competitive electric rates at discount prices to compete with alternative power sources, such as customer- owned generation facilities. Under the terms of the settlement, the Company would absorb 30
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percent of any net revenues lost as a result of such discounts through June 1996, while the remainder would be recovered from other customers. The portion recoverable after June 1996 is expected to be determined in a generic proceeding currently being conducted by the PSC.
In September 1993 the PSC instituted a formal proceeding to investigate what the Company believes are under-charges to gas customers for certain gas purchases for the period August 1990 to August 1992. The Company's estimate of these undercharges is approximately $7.5 million, of which $2.3 million had been previously expensed and $5.2 million had been deferred on the Company's balance sheet. The PSC has made the Company's current gas rates under the 1993 Rate Agreement temporary solely to consider the impact of these undercharges. On December 30, 1993, a proposed settlement among the Company, PSC Staff and another party was filed with the PSC. It provides for the recovery in rates of $3.2 million over three years, subject to audit and to limitations on rate adjustments established in the August 24 Order. The Company wrote off the $2.0 million balance of the undercharges as of December 31, 1993. That write-off amounts to a reduction in 1993 earnings of approximately $.04 per share, net of tax. Although no party, to the Company's knowledge, opposes the proposed settlement, the Company is unable to predict whether the PSC will approve it. A PSC decision on whether to approve this settlement is not expected before March 1994.
In its June 1992 rate decision, the PSC allowed the Company to defer and recover through rates over a period of ten years approximately $21.3 million of non-capital incremental storm-damage repair costs which the Company had incurred as a result of a March 1991 ice storm. The PSC has permitted the unamortized balance of these allowed costs to be included in rate base. Rate recovery of an additional $8.2 million of non-capital storm-damage costs incurred by the Company was denied by the PSC and the Company accordingly recorded in the second quarter of 1992 a charge to earnings in the amount of $8.2 million, equivalent to approximately $.15 per share, net of tax, after issuance of the two million shares of stock in August 1992.
Pursuant to a November 1991 Order approving a settlement agreement between the PSC Staff and the Company relating to the Staff's audit of the Company's fuel procurement practices, the Company refunded $10 million to its electric customers through adjustments to their energy bills over a twelve-month period beginning in January 1992. The Company recorded a $6.6 million net-of- tax reduction to net income, thereby reducing earnings per share by approximately $.21 for the fourth quarter of 1991.
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- National Energy Policy Act of 1992
The National Energy Policy Act (Energy Act) was signed into law in 1992. Major provisions of the Energy Act, as they relate to the Company, include energy efficiency, promoting competition in the electric power industry at the wholesale level, streamlining of federal licensing of nuclear power plants, encouraging development and production of coal resources, and ensuring that a new class of independent power producers established under the bill, as well as qualified facilities and other electric utilities, can achieve access to utility-owned transmission facilities upon payment of appropriate prices. Under the Energy Act, FERC may order utilities to provide wholesale transmission services for others only if, among other things, the order meets certain requirements as to cost recovery and fairness of rates. FERC is prohibited, however, from ordering retail wheeling, i.e. transmitting power directly to a customer from a supplier other than the customer's local utility. The law, however, does not prevent state regulatory commissions from allowing or ordering intrastate retail wheeling; and, New York State is currently considering the issue of retail wheeling through various studies and hearings. The Company believes this Act could lead to enhanced competition among the Company and other service providers in the electric industry.
- FERC Order 636
In April 1992 FERC issued Order No. 636 with the intention of fostering competition and improving access of customers to gas supply sources. In essence, FERC Order No. 636 requires interstate natural gas companies to offer customers "unbundled", or separate, sales and transportation services. FERC Order 636 enables the Company and other gas utilities to contract directly with gas producers for supplies of natural gas. With the unbundling of services, primary responsibility for reliable natural gas supply has shifted from interstate pipeline companies to local distribution companies, such as the Company. Since 1988 the Company has endeavored to diversify both its natural gas supply sources and the pipelines on which that supply is delivered to the Company's distribution system. The unbundling of services as required under FERC Order 636 and the commencement of Empire State Pipeline operation have enabled the Company to achieve those goals, which should enhance its competitive position. As a result of FERC Order 636, the Company does face certain restructuring transition costs as explained under the heading Energy Costs and Supply-Gas.
Results of Operations
The following financial review identifies the causes of
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significant changes in the amounts of revenues and expenses, comparing 1993 to 1992 and 1992 to 1991. The Notes to Financial Statements contain additional information.
Operating Revenues and Sales
Compared with a year earlier, operating revenues rose six percent in 1993 following a five percent increase in 1992. Gains in retail customer electric and gas revenues offset a decline in electric revenues from the sale of electric energy to other utilities. Customer revenue increases in 1993 resulted primarily from rate relief and the impact of warmer weather on air conditioning usage. Details of the revenue changes are presented in the Operating Revenues table. As presented in this table, the base cost of fuel has been excluded from customer consumption and is included under fuel costs, revenue taxes are included as a part of other revenues, and unbilled revenues are included in each caption as appropriate.
Unbilled revenues are the estimated revenues attributable to energy which has been delivered to customers but for which the metered amount has not been read and recorded on the Company's books. Such revenues do not enhance the Company's cash position. The Company records monthly accruals for unbilled revenues. The Company's Statement of Income reflects net unbilled revenues of $18.7 million in 1993, $(0.8) million in 1992, and $2.6 million in 1991. Primarily as a result of the seasonal nature of gas revenues, unbilled revenues can fluctuate from month to month and will normally be near their maximum around January and at their minimum near the end of June.
Under the ERAM provisions of the 1993 Rate Agreement, as discussed under Regulatory Matters, the Company is comparing, on a monthly basis, actual results to forecast electric gross
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margins as defined (basically, revenues less incremental cost of fuel) and utilized in establishing rates. Variations between these target margins and the Company's actual margins may be deferred and either recovered from or returned to customers. As discussed earlier, the 1993 Rate Agreement "caps", that is limits, the amount of revenue increases that can be obtained each rate year. At the end of each rate year (i.e. June 30) any balance for ERAM will be taken into consideration along with other balances eligible for passback or surcharge to customers (primarily incentive and expense sharing provisions) to determine the final disposition of the balance. As of December 31, 1993 no provisions to accrue or defer revenues associated with any of the ERAM incentive or sharing provisions under the 1993 Rate Agreement had been made, except for fuel adjustment clause revenues.
Changes in fuel and purchased power cost revenues are normally earnings neutral. The Company, however, does have fuel clause provisions which currently provide that customers and shareholders will share, generally on a 50%/50% basis subject to certain incentive limits, the benefits and detriments realized from actual electric fuel costs, generation mix, sales of gas to dual- fuel customers and sales of electricity to other utilities compared with PSC- approved forecast, or base rate, amounts. As a result of these sharing arrangements, discussed further in Note 1 of the Notes to Financial Statements, pretax earnings were increased by $4.4 million in 1992 and in 1993, primarily reflecting actual experience in both electric fuel costs and generation mix compared with rate assumptions. Fuel clause revenues also include the recovery of incremental margins that vary from those provided for in base rates for the implementation of the Company's energy efficiency programs (discussed below in this section). Beginning in October 1993, the Company also began the recovery through its fuel adjustment clause of deferred costs associated with the DOE's assessment for future uranium enrichment decontamination. For the 1992 comparison period, fuel clause revenues were reduced due to a refund to electric customers resulting from a PSC fuel audit settlement as described in the last paragraph under the heading New York State Public Service Commission.
The effect of weather variations on operating revenues is most measurable in the Gas Department, where revenues from space heating customers comprise about 85 to 90 percent of total gas operating revenues. Variation in weather conditions can also have a meaningful impact on the volume of gas delivered and the revenues derived from the transportation of customer-owned gas since a substantial portion of these gas deliveries is ultimately used for space heating. After experiencing unseasonably mild weather during the 1991 heating season, weather in the Company's service area during 1992 and 1993 was colder than normal. Gas sales were enhanced as a result of this cooler weather, while
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unseasonably warm summer weather during 1993 boosted electric energy sales to meet the demand for air conditioning usage, compared with the cool, wet 1992 summer weather conditions. The decoupling, or separation, of sales level fluctuations from revenue through the ERAM provisions, discussed under Regulatory Matters, and a gas normalization weather clause (see following paragraph) may mitigate the effect of abnormal weather conditions on earnings.
As part of the June 1992 rate decision, retail customers who use gas for spaceheating became subject to a weather normalization adjustment to reflect the impact of variations from normal weather on a billing cycle month basis for the months of October through May, inclusive. The weather normalization adjustment for a billing cycle will apply only if the actual heating degree days are lower than 97.5 percent or higher than 102.5 percent of the normal heating degree days. Weather normalization adjustments lowered gas revenues in 1993 by approximately $1.2 million and in 1992 by approximately $1.8 million. The potential for such adjustments continues through June 1996 under the terms of the 1993 Rate Agreement.
Compared with the prior year, kilowatt-hour sales of energy to retail customers in 1993 climbed about one percent after being nearly flat in 1992. Electric demand for air conditioning usage had a significant impact on such sales in 1993 and 1992. During 1993, an increase in sales to both residential and commercial customers more than offset a decline in sales to industrial customers. Kilowatt-hour sales of energy in 1993 reflect the impact of approximately 2,200 new electric customers, which follows the addition of nearly 2,400 customers a year earlier.
Like many other electric utilities, the Company is encouraging energy efficiency through demand side management (DSM) programs. Objectives of the DSM programs include increasing the efficiency with which electricity is used and shifting electric load from peak to non-peak times, thus helping to save energy and delay the need to add new generating capacity. DSM programs include rebates for energy-efficient equipment, audits which focus on potential techniques for saving energy, consumer information and outreach, and design assistance to encourage energy-efficient new construction. In general, the Company is being allowed to amortize major DSM program expenditures over a five-year period. An incentive allowance (award) of approximately $0.6 million was provided for in the Company's rates based on the Company's DSM performance during 1992. Lost margins resulting from DSM activities are estimated and recovered in base rates. Variances between actual results and such estimates are recovered through fuel clause revenue adjustments, subject to certain incentive limitations.
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Fluctuations in revenues from electric sales to other utilities are generally related to the Company's customer energy requirements, New York Power Pool energy market and transmission conditions and the availability of electric generation from Company facilities. Such revenues in 1992 and 1993 reflect the sale of energy at a lower average rate per megawatt hour, a result, in part, of competition and greater availability of energy. With more open access to transmission services as provided for under the Energy Act, the Company is examining alternative markets and procedures to meet what it believes will be increased competition for the sale of electric energy to other utilities.
The transportation of gas for large-volume customers who are able to purchase natural gas from sources other than the Company remains an important component of the Company's marketing mix. Company facilities are used to transport this gas, which amounted to 12.4 million dekatherms in 1993 and 12.6 million dekatherms in 1992. These purchases have caused decreases in customer revenues, with offsetting decreases in purchased gas expenses, but do not adversely affect earnings because transportation customers are billed at rates which, except for the cost of gas, approximate the rates charged the Company's other gas service customers. Gas supplies transported in this manner are not included in Company therm sales, depressing reported gas sales to non- residential customers.
Therms of gas sold and transported, including unbilled sales, were nearly flat in 1993, following an 11.8 percent increase in 1992. These changes reflect, primarily, the effect of weather variations on therm sales to customers with space heating. If adjusted for normal weather conditions, residential gas sales would have decreased about 0.3 percent in 1993 over 1992, while nonresidential sales, including gas transported, would have decreased approximately 2.1 percent in 1993. The average use per residential gas customer, when adjusted for normal weather conditions was slightly down in 1993, following a modest increase in 1992. Total therms of gas transported increased in 1992 primarily as a result of higher sales to certain large industrial and municipal transportation customers. Sales to these customers in 1993 were down compared with 1992 sales.
Fluctuations in "Other" customer revenues shown in the Operating Revenues table for both comparison periods are largely the result of revenue taxes, deferred fuel costs, and miscellaneous revenues.
Operating Expenses
Compared with the prior year, operating expenses were up $40.2 million in 1993 after increasing $33.1 million in 1992. Approximately two-thirds of the increase in 1993 operating
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expenses resulted from higher gas purchased for resale costs. The increase in operating expenses for the 1993 comparison period was mitigated by the Company's continuing efforts to curtail increases in other operation expenses. Operating expenses are summarized in the table titled "Operating Expenses".
- Energy Costs - Electric
An electric generation mix favoring less expensive nuclear fuel, compared with the cost of coal or oil, resulted in fuel expenses not increasing at the same rate as electric generation for the 1993 comparison period. For the 1992 comparison period, fuel expense for electric generation was lower by $16.7 million due, in part, to a refund to electric customers as described in the last paragraph under the heading New York State Public Service Commission. For both comparison periods, the average cost of coal declined.
Average rates for purchased electricity declined in 1993, after increasing in 1992. Such average rates partially offset an increase in kilowatt-hours purchased in 1993. For the 1992 comparison period, the increase in purchased electricity expense was caused by higher average rates during the year.
- Energy Costs and Supply - Gas
As a result of the implementation of FERC Order 636, and the commencement of operation of the Empire State Pipeline, the Company now purchases all of its required gas supply directly
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from numerous producers and marketers under contracts containing varying terms and conditions. The Company holds firm transportation capacity on nine major pipelines, giving the Company access to the major gas-producing regions of North America. In addition to firm pipeline capacity, the Company also has obtained contracts for firm storage capacity on the CNG Transmission Corporation (CNG) system (10.4 billion cubic feet) and on the ANR Pipeline system (6.4 billion cubic feet) which are used to help satisfy its customers' winter demand requirements. With the commencement of operation of the Empire State Pipeline, the Company placed into operation its new Mendon gate station which is capable of supplying up to one-half of the Company's gas supply needs while also maintaining the various gate station interconnections with the CNG system that, prior to Empire, had supplied all of the Company's needs.
The transportation service to be provided by Empire was scheduled to phase in over 12 months, at which point the combined CNG and Empire transportation capacity would have exceeded the Company's current requirements. Therefore, the Company recently entered into a marketing agreement with CNG, pursuant to which CNG will assist the Company in obtaining permanent replacement customers for the transportation capacity the Company will not require. It may renegotiate its arrangements with CNG and/or Empire or it may negotiate assignment, on a permanent or temporary basis, of the transportation capacity that exceeds the requirements of its customers. In addition, under FERC rules, the Company may sell its excess transportation capacity in the market. While CNG has already secured letters of intent for a substantial portion of such capacity, whether and to what extent CNG and/or the Company can successfully negotiate the assignment or sale of the excess capacity, or at what price, cannot be determined at the present time. The retention of some or all of this excess transportation capacity may cause an increase in the Company's gas supply costs. This would be in addition to any increase caused by other aspects of the gas transportation restructuring.
As a result of the restructuring of the gas transportation industry by the FERC, there will be a number of changes in this aspect of the Company's business over the next several years. These changes, which will apply throughout the industry, will affect different companies differently and may result, at least initially, in increases in the gas transportation costs of the Company. The Company will also be required to pay a share of certain transition costs incurred by the pipelines as a result of the FERC restructuring. These include costs related to restructuring existing gas supply contracts, unrecovered gas costs that would otherwise have been billable to pipeline customers under previous regulation and other related costs deemed reasonable by the FERC. Although the final amounts of such transition costs are subject to continuing
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negotiations with several pipelines and ongoing pipeline filings requiring FERC approval, the Company expects such costs to range between $43.5 and $52.0 million. A substantial portion of such costs will be on the CNG system of which approximately $27 million was billed to the Company on December 3, 1993 payable over the following three years. The Company recorded a regulatory asset on its Balance Sheet and concurrently recognized a liability totaling approximately $43.5 million for estimated restructuring transition costs under FERC Order 636. The Company expects these transition costs to be recoverable in its rates.
The volume of gas purchased increased in both comparison periods primarily due to higher combined residential and commercial space heating sales, reflecting colder weather. The effect of higher-volume purchases was partially offset by lower average rates in 1992. In contrast to 1992, however, it was primarily an increase in these rates that pushed up the cost of gas purchased for resale in 1993. These higher rates reflect, in part, increased demand charges and, to a lesser extent, newly assessable gas service restructuring charges as a result of FERC Order 636.
- Operating Expenses, Excluding Fuel
Other operation expenses rose over both comparison periods as shown by the table titled "Operating Expenses". The recording of certain postretirement benefits other than pensions, as required by Statement of Financial Accounting Standards No. 106 (SFAS-106) and discussed in the following paragraph, increased other operation expenses in 1992 by $4.9 million. Compared with a year earlier, other operation expenses in 1992 also reflect an increase of $3.0 million for transmission wheeling charges, $1.9 million due to increased amortization of costs associated with the Company's demand side management programs, and additional expenses of about $1.6 million associated with the Company's share of Nine Mile Two operation expenses. As stated earlier, the growth in other operation expenses was significantly less over the 1993 comparison period, a direct result, in part, of enhanced cost control efforts by the Company's employees. Compared with 1992, operating expenses associated with fire and liability insurance, transportation, materials and supplies, legal expenses, and the Company's share of Nine Mile Two operation expenses declined in 1993. The change in other operation expenses for the 1993 comparison period reflects primarily increased payroll costs and demand side management expenses.
During the first quarter of 1992, the Company adopted the Financial Accounting Standards Board's (FASB) SFAS-106 for financial accounting purposes. Among other things, SFAS-106 requires accrual accounting for postretirement benefits other than pensions. Based on accrual accounting required by SFAS-106,
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the Company's net periodic cost for postretirement benefits other than pension was $7.5 million in 1993 and $7.8 million in 1992. The PSC has allowed the Company revenues in rates based on SFAS-106. In September 1993, the PSC issued a "Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other Than Pensions." The Statement's provisions require, among other things, ten-year amortization of actuarial gains and losses and deferral of differences between actual costs and rate allowances. The Company adopted the Statement in 1993 for regulatory accounting purposes.
In November 1992, the FASB issued SFAS-112 entitled "Employees' Accounting for Postemployment Benefits" which is effective for fiscal years beginning after December 15, 1993. This Statement requires the Company to recognize the obligation to provide postemployment benefits to former or inactive employees after employment but before retirement. Employers must accrue an obligation if the benefits are attributable to service already rendered, the benefits accumulate or vest, payment is probable, and the amounts can be reasonably estimated. The Company must adopt SFAS-112 not later than the first quarter of 1994. The Company is currently evaluating the impact of SFAS- 112; however, based on studies the Company has performed to date, the adoption of SFAS-112 is not expected to have a material effect on the Company's financial condition or results of operations.
Reduced maintenance expense in both comparison periods was largely due to lower maintenance expenses incurred at nuclear production facilities and the effect of increased activity in 1991 associated with electric distribution facilities.
Despite an increase in depreciable plant in both comparison periods, depreciation and amortization of other plant fluctuated only moderately due mainly to a decrease in the depreciation and accrued decommissioning expenses related to the Ginna nuclear plant because of a three-year extension of its operating license and the completion in July 1992 of amortization of the Sterling property previously abandoned.
- Taxes Charged to Operating Expenses
The increase in local, state and other taxes in both comparison periods resulted primarily from an increase in revenues combined with an increase in the revenue tax rate, and increased property tax rates and higher property assessments. The 1993 increase in local, state and other taxes was mitigated by the effect of the relative magnitude of these factors compared with 1992. The increase in these taxes for the 1992 comparison period reflects an adjustment for a one-half percent increase in the New York State gross revenue tax rate accounted for beginning
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in October 1991 retroactive to January 1, 1991.
During the first quarter of 1993, the Company adopted SFAS-109 entitled "Accounting for Income Taxes" issued by the FASB in February 1992. Among other things, SFAS-109 requires that a deferred tax liability be recognized on the balance sheet for tax differences previously flowed through to customers. The Company's adoption of SFAS-109 in the first quarter of 1993 did not have a material effect on the Company's results of operations although since then, reflection of a deferred tax liability, together with a corresponding regulatory asset, caused total assets and liabilities to increase significantly. See Note 2 of the Notes to Financial Statements for further discussion of SFAS- 109 and an analysis of Federal income taxes.
In August 1993, the Revenue Reconciliation Act of 1993 (1993 Tax Act) was signed into law. Among other provisions, the 1993 Tax Act provides for a Federal corporate income tax rate of 35% (previously 34%) retroactive to January 1, 1993. The Company has adjusted its tax reserve balances to reflect this new rate. There was no earnings impact since the effects of the tax change have been deferred. The Company petitioned the PSC in late 1993 for recognition and recovery of this incremental tax liability which was not reflected in the provisions of its 1993 Rate Agreement. The Company's ability to recover this cost is dependent upon the PSC issuing a generic ruling on the treatment of the 1993 Tax Act.
Other Statement of Income Items
AFUDC variances are generally related to the amount of utility plant under construction and not included in rate base. AFUDC levels also reflect decreases in the gross rate to 3.90 percent effective September 1, 1993 from earlier rates of 4.50 percent, 5.50 percent, and 7.10 percent.
Variations in non-operating Federal income tax reflect mainly accounting adjustments related to retirement enhancement programs (see following paragraph), regulatory disallowances, and an employee performance incentive program (discussed below in this section).
Recorded under the caption Other Income and Deductions is the recognition of retirement enhancement programs designed to reduce overall labor costs which were implemented by the Company during the third and fourth quarters of 1993. A total of 173 employees elected to participate under these programs. The Company does not plan to replace any of those employees. Total estimated pretax costs of $8.2 million associated with these programs were recognized by the Company in its 1993 Statement of Income, thereby reducing after-tax earnings by approximately $.15
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per share for the year. The Company estimates that the net pre-tax savings through 1997 resulting from these programs will amount to about $8.9 million.
Recorded under the caption Regulatory Disallowances is the recognition of the 1991 PSC order associated with the Company's fuel procurement practices, the 1992 PSC order related to the March 1991 ice storm, and the 1993 settlement with the PSC regarding certain alleged gas purchase undercharges, each discussed under the heading New York State Public Service Commission.
Other Income in 1992 includes $3.5 million of proceeds received in settlement of lawsuits filed against certain contractors involved in the construction of the Nine Mile Two nuclear plant. Non-cash earnings associated with the amortization of customer prepaid Nine Mile Two financing costs of $4.8 million in 1991, $2.5 million in 1992, and $1.2 million in 1993 are also included in Other Income. The decline in Other-Net Income and Deductions for the 1993 comparison period results mainly from the recognition of an employee performance incentive program for 1993. This program recognizes employees' achievements in meeting corporate goals and reducing expenses. Compared with a year earlier, Other-Net Income and Deductions also reflects lower miscellaneous interest revenues in 1993 and the recognition of Energyline earnings (losses) upon consolidation with the accounts of the Company as discussed under Capital Requirements and Gas Operations.
Both mandatory and optional redemptions of certain higher-cost first mortgage bonds have helped to reduce long-term debt interest expense over the three-year period 1991-1993, despite the issuance of additional long-term debt in 1991 and 1992. In 1992, the effect of lower interest rates on debt expense was partially offset by increased short-term borrowings. The level of short- term debt borrowings decreased in 1993.
EARNINGS/SUMMARY
Presented below is a table which summarizes the Company's Common Stock earnings on a per-share basis. Certain non-recurring items and their effect on earnings per share have been identified in this table. Compared with a year earlier, earnings per share were up in 1993 and 1992 despite the effect of a public issuance of Common Stock in each year. Future earnings will be affected, in part, by the Company's success in achieving demand side management and other incentive goals, as well as controlling operating and capital costs, within levels provided for in rates under the terms of the 1993 Rate Agreement.
In December 1992 the Company announced a quarterly
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dividend increase from $.42 to $.43 per share of Common Stock payable in January 1993. Subsequently, in December 1993 the Company announced a new quarterly dividend rate of $.44 per share payable in January 1994. The Company's Charter provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company. Accordingly, dividend payments are dependent on future earnings, in addition to financial requirements and other factors.
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ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. Financial Statements
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for each of the three years ended December 31, 1993.
Consolidated Balance sheets at December 31, 1993 and 1992.
Consolidated Statement of Cash Flows for each of the three years 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 - Property, Plant and Equipment (Utility Plant)
Schedule VI - Accumulated Depreciation and Amortization (Utility Plant)
Schedule VIII - Valuation and Qualifying Accounts
Schedule IX - Short-term Borrowings
Schedule X - Supplementary Income Statement Information
B. Supplementary Data
Interim Financial Data.
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REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors of Rochester Gas and Electric Corporation
In our opinion, the consolidated financial statements listed under Item 8A in the index appearing on the preceding page present fairly, in all material respects, the financial position of Rochester Gas and Electric 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 Note 1 to the financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" in 1993.
PRICE WATERHOUSE
Rochester, New York January 14, 1994
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Consolidated Statement of Income
Consolidated Statement of Retained Earnings
The accompanying notes are an integral part of the financial statements.
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The accompanying notes are an integral part of the financial statements.
The accompanying notes are an integral part of the financial statements.
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NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF ACCOUNTING PRINCIPLES
General. The Company is subject to regulation by the Public Service Commission of the State of New York (PSC) under New York statutes and by the Federal Energy Regulatory Commission (FERC) as a licensee and public utility under the Federal Power Act. The Company's accounting policies conform to generally accepted accounting principles as applied to New York State public utilities giving effect to the rate-making and accounting practices and policies of the PSC.
In June 1988, the Board of Directors authorized the creation of Utilicom, Inc. as a wholly owned subsidiary. Utilicom develops and markets computer software to assist customers in complying with state and federal environmental and safety regulations. On August 31, 1993, the Company sold the assets of Utilicom and liquidated the subsidiary. The subsidiary activity prior to and including disposition was insignificant to the Company's financial position and results of operation.
In April 1990, the Board of Directors authorized the creation of Energyline Corporation, a wholly owned subsidiary, which was incorporated in July 1992. Energyline was formed as a gas pipeline corporation to fund the Company's investment in the Empire State Pipeline project. On November 1, 1993 Empire commenced service to the Company's gas distribution facilities. The Company has authority to invest up to $20 million in Empire. In June 1993 Empire secured a $150 million credit agreement, the proceeds of which are to finance approximately 75 percent of the total construction cost and initial operating expenses. Energyline is obligated to pay up to 20% of the balance outstanding subject to a commitment of $9.7 million under the credit agreement. Excluding the loan commitment, at December 31, 1993 the Company had invested a net amount of $10.2 million in Energyline.
A description of the Company's principal accounting policies follows.
Rates and Revenue. Revenue is recorded on the basis of meters read. In addition, the Company records an estimate of unbilled revenue for service rendered subsequent to the meter-read date through the end of the accounting period.
Tariffs for electric and gas service include fuel cost adjustment clauses which adjust the rates monthly to reflect changes in the actual average cost of fuels. The electric fuel adjustment provides that ratepayers and the Company will share the effects of any variation from forecast monthly unit fuel costs on a 50%/50% basis up to a $5.6 million cumulative annual gain or loss to the Company. Thereafter, 100 percent of additional fuel clause adjustment amounts are assigned to customers. The electric fuel cost adjustment also provides that any variation from forecast margins below $7.1 million or above $8.5 million on sales to electric utilities be shared with retail customers on a 50%/50% basis.
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In addition, there is a similar 50%/50% sharing process of variances from forecasted margins derived from sales and the transportation of privately owned gas to large customers that can use alternate fuels.
Under the Company's Electric Revenue Assurance Mechanism (ERAM), which was established in the 1993 multi-year rate settlement, any variations between actual margins and the established targets may be recovered from or returned to customers. Other performance incentives or penalties were established in the settlement and under some circumstances could be recognized periodically. However, through December 31, 1993, no amount was recognized as recoverable or payable to customers.
Retail customers who use gas for spaceheating are subject to a weather normalization adjustment to reflect the impact of variations from normal weather on a billing month basis for the months of October through May, inclusive. The weather normalization adjustment for a billing cycle will apply only if the actual heating degree days are lower than 97.5 percent or higher than 102.5 percent of the normal heating degree days. Weather normalization adjustments lowered gas revenues in 1993 and 1992 by approximately $1.2 million and $1.8 million respectively. These adjustments will continue through June 1996 in accordance with the 1993 multi-year rate settlement agreement.
Deferred Fuel Costs. The Company practices fuel cost deferral accounting as described above. A reconciliation of recoverable gas costs with gas revenues is done annually as of August 31, and the excess or deficiency is refunded to or recovered from the customers during a subsequent twelve-month period beginning in December. These deferred fuel costs are included as a component of unbilled revenues.
Utility Plant, Depreciation and Amortization. The cost of additions to utility plant and replacement of retirement units of property is capitalized. Cost includes labor, material, and similar items, as well as indirect charges such as engineering and supervision, and is recorded at original cost. The Company capitalizes an allowance for funds used during construction approximately equivalent to the cost of capital devoted to plant under construction that is not included in its rate base. Replacement of minor items of property is included in maintenance expenses. Costs of depreciable units of plant retired are eliminated from utility plant accounts, and such costs, plus removal expenses, less salvage, are charged to the accumulated depreciation reserve.
Depreciation in the financial statements is provided on a straight- line basis at rates based on the estimated useful lives of property, which have resulted in provisions of 2.9%, 2.9% and 3.3% per annum of average depreciable property in 1993, 1992 and 1991, respectively. The decrease in depreciation provision percentages from 1991 to 1992 is principally the result of a 3 1/2 year extension of the Ginna Nuclear Plant license term and lengthening estimated useful lives at other property.
Nuclear Fuel Disposal Costs. The Nuclear Waste Policy Act (Act) of 1982, as amended, requires the United States Department of Energy (DOE)
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to establish a nuclear waste disposal site and to take title to nuclear waste. A permanent DOE high-level nuclear waste repository is not expected to be operational before the year 2010. The DOE is pursuing efforts to establish a monitored retrievable interim storage facility which may allow it to take title to and possession of nuclear waste prior to the establishment of a permanent repository. The Act provides for a determination of the fees collectible by the DOE for the disposal of nuclear fuel irradiated prior to April 7, 1983 and for three payment options. The option of a single payment to be made at any time prior to the first delivery of fuel to the DOE was selected by the Company in June 1985. The Company estimates the fees, including accrued interest, owed to the DOE to be $68.1 million at December 31, 1993. The Company is allowed by the PSC to recover these costs in rates. The estimated fees are classified as a long-term liability and interest is accrued at the current three-month Treasury bill rate, adjusted quarterly. The Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of one mill ($.001) per KWH of nuclear energy generated and sold. This charge is currently being collected from customers and paid to the DOE pursuant to PSC authorization. The Company expects to utilize on-site storage for all spent or retired nuclear fuel assemblies until an interim or permanent nuclear disposal facility is operational.
Nuclear Decommissioning Costs. Decommissioning costs (costs to take the plant out of service in the future) for the Company's Ginna Nuclear Plant are estimated to be approximately $150.7 million, and those for the Company's 14% share of Nine Mile Two's decommissioning costs are estimated to be approximately $34.3 million (January 1993 dollars). Through December 31, 1993, the Company has accrued and recovered in rates $61.2 million for this purpose and is currently accruing and recovering decommissioning costs at a rate of approximately $8.9 million per year based on the use of a combination of internal and external sinking funds. (See Note 10.)
The decommissioning costs, which form the basis for current accruals, were derived from the record of the Company's prior rate proceeding (PSC Opinion 93-19, issued August 1993) and were estimated principally by reference to a formula prescribed by the NRC for the purpose of providing for adequate funding at the time of the decommissioning.
Uranium Enrichment Decontamination and Decommissioning Fund. As part of the National Energy Act (Act) issued in October 1992, utilities with nuclear generating facilities are assessed an annual fee payable over 15 years to pay for the decommissioning of Federally owned uranium enrichment facilities. The assessments for Ginna and Nine Mile Two are estimated to total $24.1 million, excluding inflation and interest. The first installment of $1.6 million was paid in 1993 and recovered through the fuel adjustment clause. A liability has been recognized on the financial statements along with a corresponding regulatory asset. The Company believes that the full amount of the assessment will be recoverable in rates as described in the Act.
FERC Order 636. Under this order, gas supply and pipeline companies are allowed to pass restructuring and transition costs associated with the
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implementation of the order on to their customers. The Company, as a customer, has estimated a total of $43.5 million which will be paid to its suppliers. A regulatory asset and related deferred credit have been established on the balance sheet to account for these estimated costs. Approximately $2.2 million of these costs were paid during 1993 to various suppliers, and have been included in purchased gas costs (see Note 10).
Allowance for Funds Used During Construction. The Company capitalizes an Allowance for Funds Used During Construction (AFUDC) based upon the cost of borrowed funds for construction purposes, and a reasonable rate upon the Company's other funds when so used. AFUDC is segregated into two components and classified in the Statement of Income as Allowance for Borrowed Funds Used During Construction, an offset to Interest Charges, and Allowance for Other Funds used During Construction, a part of Other Income.
The rates approved by the PSC for purposes of computing AFUDC were: 3.9% from September 1, 1993 through December 31, 1993; 4.5% from September 1, 1992 through August 31, 1993; 5.5% from April 1, 1992 through August 31, 1992; 7.1% from July 1, 1991 through March 31, 1992; 8.6% from February 1, 1991 through June 30, 1991; 9.6% from January 1, 1991 through January 31, 1991.
In 1984, the Company discontinued accruing AFUDC on a portion of its investment in Nine Mile Two for which a cash return was allowed. Amounts were accumulated in deferred debit and credit accounts equal to the amount of AFUDC which was no longer accrued. The balance in the deferred credit account was intended to reduce future cash revenue requirements over a period substantially shorter than the life of Nine Mile Two, and the balance in the deferred debit account would then be collected from customers over a longer period of time. The current balances of $19.2 million are expected to remain on the Company's books for future application by the PSC as a rate moderator.
Federal Income Tax. For income tax purposes, depreciation is generally computed using the most liberal methods permitted. The resulting tax reductions are offset by provisions for deferred income taxes only to the extent ordered or permitted by regulatory authorities.
Statement of Financial Accounting Standards (SFAS) 109, Accounting for Income Taxes, was adopted by the Company during the first quarter of 1993. SFAS-109 requires that a deferred tax liability must be recognized on the balance sheet for tax differences previously flowed through to customers. Substantially all of these flow-through adjustments relate to property plant and equipment and related investment tax credits and will be amortized consistent with the depreciation of these accounts. The net amount of the additional liability at December 31, 1993 was $241 million. In conjunction with the recognition of this liability, a corresponding regulatory asset was also recognized.
SFAS-109 also requires that a deferred tax liability or asset be adjusted in the period of enactment for the effect of changes in tax laws or rates. During the year the statutory income tax rate was
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increased one percent to 35%. This resulted in increases of $.6 million and $1.3 million for current and deferred tax liabilities, respectively. There was no earnings impact since the effects of the tax change have been deferred for future recovery.
The Company uses the separate-period approach in calculating the interim quarterly tax provision.
Retirement Health Care and Life Insurance Benefits. The Company provides certain health care and life insurance benefits for retired employees and health care coverage for surviving spouses of retirees. Substantially all of the Company's employees may become eligible for these benefits if they reach retirement age while working for the Company. These and similar benefits for active employees are provided through insurance policies whose premiums are based upon the experience of benefits actually paid.
In December 1990, the FASB issued SFAS-106 entitled "Accounting for Postretirement Benefits Other than Pensions" effective for fiscal years beginning after December 15, 1992. Among other things, SFAS-106 requires accrual accounting by employers for postretirement benefits other than pensions reflecting currently earned benefits. The Company adopted this accounting practice in 1992.
In September 1993, the PSC issued a "Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other Than Pensions". The Statement's provisions require, among other things, ten-year amortization of actuarial gains and losses and deferral of differences between actual costs and rate allowances. The effects of applying the ten year amortization of actuarial gains were deferred.
Postemployment Benefits. In November 1992, the FASB issued SFAS-112 entitled "Employees' Accounting for Postemployment Benefits" which is effective for fiscal years beginning after December 15, 1993. This Statement requires the Company to recognize the obligation to provide post-employment benefits to former or inactive employees after employment but before retirement. The Company must adopt SFAS-112 not later than the first quarter of 1994. The Company is currently evaluating the impact of SFAS-112; however, based on studies the Company has performed to date, the adoption of SFAS-112 is not expected to have a material effect on the Company's financial condition or results of operations.
Earnings Per Share. Earnings applicable to each share of common stock are based on the weighted average number of shares outstanding during the respective years.
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Note 2. Federal Income Taxes
The provision for Federal income taxes is distributed between operating expense and other income based upon the treatment of the various components of the provision in the rate-making process. The following is a summary of income tax expense for the three most recent years.
The following is a reconciliation of the difference between the amount of Federal income tax expense reported in the Statement of Income and the amount computed by multiplying the income by the statutory tax rate.
A summary of the components of the net deferred tax liability is as follows:
In 1993, the regulatory asset recognized by the Company as a result of adopting SFAS No. 109 is attributed to $222 million in depreciation, $18 million to property taxes, $18 million of deferred finance charges - Nine Mile Two and $4 million of Miscellaneous items offset by $21 million attributed to investment tax credits.
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Note 3. Pension Plan and Other Retirement Benefits
The Company has a defined benefit pension plan covering substantially all of its employees. The benefits are based on years of service and the employee's compensation during the last three years of employment. The Company's funding policy is to contribute annually an amount consistent with the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. These contributions are intended to provide for benefits attributed to service to date and for those expected to be earned in the future.
The plan's funded status and amounts recognized on the Company's balance sheet are as follows:
* Actuarial present value ** Includes $9.2 million pension plan curtailment charge.
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The projected benefit obligation at December 31, 1993 and 1992 assumed discount rates of 7 1/4 percent and 7 3/4 percent, respectively and long-term rate of increase in future compensation levels of 6 percent and 6 1/2 percent, respectively. The assumed long-term rate of return on plan assets for 1993 and 1992 was 8 1/2 percent. The unrecognized net obligation is being amortized over 15 years beginning January 1986.
In September 1993, the PSC issued a "Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other than Pensions" (Statement). The 1993 pension cost reflects adoption of the Statement's provisions which, among other things, requires ten-year amortization of actuarial gains and losses and deferral of differences between actual costs and rate allowances.
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits to retired employees and health care coverage for surviving spouses of retirees. Substantially all of the Company's employees are eligible provided that they retire as employees of the Company. In 1993, the health care benefit consisted of a contribution of up to $175 per month towards the cost of a group health policy provided by the Company. The life insurance benefit consists of a Basic Group Life benefit, covering substantially all employees, providing a death benefit equal to one-half of the retiree's final pay. In addition, certain employees and retirees, employed by the Company at December 31, 1982, are entitled to a Special Group Life benefit providing a death benefit equal to the employee's December 31, 1982 pay.
The Company adopted SFAS-106, "Accounting for Postretirement Benefits Other than Pensions" as of January 1, 1992 for financial accounting purposes. Subsequently, with the issuance of the Statement referenced above, the Company's application of SFAS-106 will extend to ratemaking purposes as well. The Company has elected to amortize the unrecognized, unfunded Accumulated Postretirement Benefit Obligation at January 1, 1992 over twenty years as provided by SFAS-106. The Company intends to continue funding these benefits on a pay-as-you-go basis.
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The plans' funded status reconciled with the Company's balance sheet is as follows:
The Accumulated Postretirement Benefit Obligation at December 31, 1993 and 1992 assumed discount rates of 7 1/4 percent and 7 3/4 percent, respectively and long-term rate of increase in future compensation levels of 6 percent and 6 1/2 percent, respectively.
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Note 4. Departmental Financial Information
The Company's records are maintained by operating departments, in accordance with PSC accounting policies, giving effect to the rate- making process. The following is the operating data for each of the Company's departments, and no interdepartmental adjustments are required to arrive at the operating data included in the Statement of Income.
(a) Excludes cash, unamortized debt expense and other common items.
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NOTE 5. JOINTLY-OWNED FACILITIES
The following table sets forth the jointly-owned electric generating facilities in which the Company is participating. Both Oswego Unit No. 6 and Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are operated by Niagara Mohawk Power Corporation. Each participant must provide its own financing for any additions to the facilities. The Company's share of direct expenses associated with these two units is included in the appropriate operating expenses in the Statement of Income. Various modifications will be made throughout the lives of these plants to increase operating efficiency or reliability, and to satisfy changing environmental and safety regulations.
The Plant in Service and Accumulated Provision for Depreciation balances for Nine Mile Point Nuclear Unit No. 2 shown above have been increased by the disallowed costs of $374.3 million. Such costs, net of income tax effects, were previously written off in 1987 and 1989.
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(a) The Series EE, Series OO, Series RR and Series SS First Mortgage Bonds equal the principal amount of and provide for all payments of principal, premium and interest corresponding to the Pollution Control Revenue Bonds, Series A, Series C, and Pollution Control Refunding Revenue Bonds, Series 1992 A, Series 1992 B (Rochester Gas and Electric Corporation Projects), respectively, issued by the New York State Energy Research and Development Authority through a participation agreement with the Company. Payment of the principal of, and interest on the Series 1992 A and Series 1992 B Bonds are guaranteed under a Bond Insurance Policy by Municipal Bond Investors Assurance Corporation. The Series EE Bonds are subject to a mandatory sinking fund beginning August 1, 2000 and each August 1 thereafter. Nine annual deposits aggregating $3.2 million will be made to the sinking fund, with the balance of $6.8 million principal amount of the bonds becoming due August 1, 2009.
(b) The Series QQ First Mortgage Bonds and 7%, 7.15%, 7.13% and 6.375% medium- term notes described below are generally not redeemable prior to maturity.
(c) In 1993 the Company issued $200 million under a medium-term note program
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entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series A" with maturities that range from seven years to thirty years.
The First Mortgage provides security for the bonds through a first lien on substantially all the property owned by the Company (except cash and accounts receivable).
Sinking and improvement fund requirements aggregate $333,540 per annum under the First Mortgage, excluding mandatory sinking funds of individual series. Such requirements may be met by certification of additional property or by depositing cash with the Trustee. The 1992 and 1993 requirements were met by certification of additional property.
Sinking fund requirements and bond maturities for the next five years are:
(d) The Series FF First Mortgage Bonds are subject to a mandatory sinking fund of $2.75 million annually each February 15.
(e) The Series JJ First Mortgage Bonds are subject to a mandatory sinking fund of $2.5 million annually each June 15.
Promissory Notes
(f) The $51.7 million Promissory Note was issued in connection with NYSERDA's Floating Rate Monthly Demand Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), Series 1984. This obligation is supported by an irrevocable Letter of Credit expiring October 15, 1994. The interest rate on this note for each monthly interest payment period will be based on the evaluation of the yields of short term tax-exempt securities at par having the same credit rating as said Series 1984 Bonds. The average interest rate was 2.19% for 1993, 2.74% for 1992 and 4.32% for 1991. The interest rate will be adjusted monthly unless converted to a fixed rate.
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(g) The $40.2 million Promissory Note was issued in connection with NYSERDA's Adjustable Rate Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), Series 1985. This obligation is supported by an irrevocable Letter of Credit expiring November 30, 1996. The annual interest rate was adjusted to 4.50% effective November 15, 1991, to 3.10% effective November 15, 1992 and to 2.75% effective November 15, 1993. The interest rate will be adjusted annually unless converted to a fixed rate.
The Company is obligated to make payments of principal, premium and interest on each Promissory Note which correspond to the payments of principal, premium, if any, and interest on certain Pollution Control Revenue Bonds issued by the New York State Energy Research and Development Authority (NYSERDA) as described above. These obligations are supported by certain Bank Letters of Credit discussed above. Any amounts advanced under such Letters of Credit must be repaid, with interest, by the Company.
Based on an estimated borrowing rate at year-end 1993 of 6.68% for long term debt with similar terms and average maturities (14 years), the fair value of the Company's long term debt outstanding (including Promissory Notes as described above) is approximately $816 million at December 31, 1993.
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Note 7. Preferred and Preference Stock
*See below for mandatory redemption requirements
No shares of preferred or preference stock are reserved for employees, or for options, warrants, conversions, or other rights.
A. Preferred Stock, not subject to mandatory redemption:
#May be redeemed at any time at the option of the Company on 30 days minimum notice, plus accrued dividends in all cases
B. Preferred Stock, subject to mandatory redemption:
+Thereafter at $100.00 **Excludes $ six million optional redemption effective March 1, 1993
Mandatory Redemption Provisions. - -------------------------------
In the event the Company should be in arrears in the sinking fund requirement, the Company may not redeem or pay dividends on any stock subordinate to the Preferred Stock.
Series R. Mandatory redemption of 60,000 shares per year at $100 per share - -------- commenced on March 1, 1993 for Series R and on each March 1 thereafter, so long as any shares remain outstanding. In addition, the Company has the non- cumulative right to redeem up to an additional 60,000 shares on the same terms and dates applicable to the mandatory sinking fund redemptions. The Company redeemed 120,000 shares on March 1, 1993 and the Company has the right to redeem up to the remaining 180,000 shares on March 1, 1994.
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Series S, Series T, Series U. All of the shares are subject to redemption - ---------------------------- pursuant to mandatory sinking funds on September 1, 1997 in the case of Series S, September 1, 1998 in the case of Series T and September 1, 1999 in the case of Series U; in each case at $100 per share.
Based on an estimated dividend rate at year-end 1993 of 5.25% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (3.25 years), the fair value of the Company's Preferred Stock, subject to mandatory redemption, is approximately $53 million at December 31, 1993.
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Note 8. Common Stock
At December 31, 1993, there were 50,000,000 shares of $5 par value Common Stock authorized, of which 36,911,265 were outstanding. No shares of Common Stock are reserved for options, warrants, conversions, or other rights. There were 1,193,613 shares of Common Stock reserved and unissued for shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan and 253,090 shares reserved and unissued for employees under the RG&E Savings Plus Plan.
Common Stock
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Note 9. Short Term Debt
At December 31, 1993 and December 31, 1992, the Company had short term debt outstanding of $68.1 million and $50.8 million, respectively. The weighted average interest rate on short term debt outstanding at year end 1993 was 3.46% and was 3.48% for borrowings during the year. For 1992, the weighted average interest rate on short term debt outstanding at year end was 3.99% and was 4.28% for borrowings during the year.
On December 1, 1988 the Company renewed its $90 million revolving credit facility for a period of three years and this agreement has been regularly extended. In November of 1993 the Company was granted a one-year extension of the commitment termination date to December 31, 1996. Commitment fees related to this facility amounted to $169,000 in 1993, $169,000 in 1992 and $149,000 in 1991.
The Company's Charter provides that unsecured debt may not exceed 15 percent of the Company's total capitalization (excluding unsecured debt). As of December 31, 1993, the Company would be able to incur $19.2 million of additional unsecured debt under this provision. In order to be able to use its revolving credit agreement, the Company has created a subordinate mortgage which secures borrowings under its revolving credit agreement that might otherwise be restricted by this provision of the Company's Charter.
Since June 1990 the Company has had a credit agreement with a domestic bank providing for up to $20 million of short term debt. Borrowings under this agreement, which has been extended to December 31, 1994, are secured by the Company's accounts receivable.
Also, additional unsecured short term borrowing capacity of up to $70 million is available from domestic banks, at their discretion.
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Note 10. Commitments and Other Matters
CAPITAL EXPENDITURES.
The Company's 1994 construction expenditures program is currently estimated at $138 million, including $16 million related to replacement of the steam generators at the Ginna Nuclear Plant and $2 million of Allowance for Funds Used During Construction. The Company has entered into certain commitments for purchase of materials and equipment in connection with that program.
NUCLEAR-RELATED MATTERS.
DECOMMISSIONING TRUST. Under accounting procedures approved by the PSC, the Company has been collecting in its electric rates amounts for the eventual decommissioning of its Ginna Plant and for its 14% share of the decommissioning of Nine Mile Two. The operating licenses for these plants expire in 2009 and 2026 respectively. The Company has collected approximately $61.2 million through December 31, 1993.
The Nuclear Regulatory Commission (NRC) requires reactor licensees to submit funding plans that establish minimum external funding levels for reactor decommissioning. The Company's plan consists principally of an external decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two share. Since 1990, the Company has contributed some $36.9 million to this fund. In addition, the Company maintains an internal reserve to fund the removal of non-radioactive structures, a feature not covered by the NRC minimum funding.
In connection with the Company's rate settlement completed in August 1993, the PSC approved the collection during the rate year ending June 30, 1994 of an aggregate $8.9 million for decommissioning, covering both nuclear units. The amount allowed in rates is based on estimated ultimate decommissioning costs of $150.7 million for Ginna and $34.3 million for the Company's 14% share of Nine Mile Two (January 1993 dollars). This estimate is based principally on the application of a NRC formula to determine minimum funding. Site specific studies of the anticipated costs of actual decommissioning are required to be submitted to the NRC at least five years prior to the expiration of the license. The Company intends to fund the external decommissioning trust in the amount of the NRC minimum funding requirement. The difference between the amount to be collected and the NRC minimum will be held in an internal reserve.
The Company is aware of recent NRC activities related to upward revisions to the required minimum funding levels. These activities, primarily focused on disposition of low level radioactive waste, may require the Company to increase funding. The Company continues to monitor these activities but cannot predict what regulatory actions the NRC may ultimately take.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. Nuclear reactor licensees in the U.S. are assessed annually for the decontamination and decommissioning of Department of Energy (DOE) enrichment facilities. The Company made the first of 15 annual payments for this purpose in September 1993, remitting approximately $1.6 million ($1.5 million for the Ginna Plant and $0.1 million for its share of the Nine Mile Two plant). For the two facilities the Company recognized liabilities at December 31, 1993 of $23.4 million ($21.7 million as a
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long-term liability and $1.7 million as a current liability). In October 1993, the Company began recovery of this deferral through its fuel adjustment clause.
INSURANCE PROGRAM. The Price-Anderson Act establishes a federal program, providing indemnification and insurance against public liability, applicable in the event of a nuclear accident at a licensed U.S. reactor. As a result of amendments to the Act in 1988, the limit of liability has increased to approximately $9.4 billion. Also in 1988 coverage was expanded to include precautionary evacuations and the Act was extended until the year 2002. Under the program, claims would first be met by insurance which licensees are required to carry in the maximum amount available (currently $200 million). If claims exceed that amount, licensees are subject to a retrospective assessment up to $75.5 million per licensed facility for each nuclear incident, payable at a rate not to exceed $10 million per year. Those assessments are subject to periodic inflation-indexing and to a 5% surcharge if funds prove insufficient to pay claims. In addition, the retrospective assessments would be subject to a three percent charge for premium tax. The Company's interests in two nuclear units could thus expose it to a potential liability for each accident of $86.1 million through retrospective assessments of $11.4 million per year in the event of a sufficiently serious nuclear accident at its own or another U.S. commercial nuclear reactor.
Beginning in 1988, coverage for claims alleging radiation-induced injuries to some workers at nuclear reactor sites was removed from the nuclear liability insurance policies purchased by the Company. Coverage for workers first engaged in nuclear-related employment at a nuclear site prior to 1988 continues to be provided under then-existing nuclear liability insurance policies. Those workers first employed at a nuclear facility in 1988 or later are covered under a separate, industry-wide insurance program. That program contains a retrospective premium assessment feature whereby participants in the program can be assessed to pay incurred losses that exceed the program's reserves. Under the plan as currently established, the Company could be assessed a maximum of $3.1 million over the life of the insurance coverage.
The Company is a member of Nuclear Electric Insurance Limited, which provides insurance coverage for the cost of replacement power during certain prolonged accidental outages of nuclear generating units and coverage for property losses in excess of $500 million at nuclear generating units. As of December 31, 1993, the Company is purchasing a weekly indemnity limit of $3.5 million in the NEIL I replacement power expense program and full policy limits of $1.4 billion in the NEIL II Property Insurance Program for the Ginna Nuclear Power Plant. Coverage under the Property Insurance Program includes the shortfall in the NRC required external trust fund resulting from the premature decommissioning of a nuclear power plant following an accident with property damage in excess of $500 million. The Company currently has designated $166 million as a sublimit for this coverage at the Ginna Nuclear Power Plant. For its share in the generation of Nine Mile Two the Company purchases a weekly indemnity limit of $.5 million in the NEIL I replacement power expense program. The owners at Nine Mile Two purchase the full policy limit of $1.4 billion in the NEIL II Property Insurance Program and the Company pays its proportionate share of those premiums. The owners at Nine Mile Two have selected the maximum available sublimit of $250 million for premature decommissioning. If an insuring program's losses exceeded its other resources available to pay
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claims, the Company could be subject to maximum assessments in any one policy year of approximately $4.9 million and $14.9 million in the event of losses under the replacement power and property damage coverages, respectively.
ENVIRONMENTAL MATTERS.
The production and delivery of energy are necessarily accompanied by the release of by-products subject to environmental controls. In recognition of the Company's responsibility to preserve the quality of the air, water, and land it shares with the community it serves, the Company has taken a variety of measures (e.g., self-auditing, recycling and waste minimization, training of employees in hazardous waste management) to reduce the potential for adverse environmental effects from its energy operations and, specifically, to manage and appropriately dispose of wastes currently being generated. The Company, nevertheless, has been contacted, along with numerous others, concerning wastes shipped off-site to licensed treatment, storage and disposal sites where authorities have later questioned the handling of such wastes. In such instances, the Company typically seeks to cooperate with those authorities and with other site users to develop cleanup programs and to fairly allocate the associated costs.
As part of its commitment to environmental excellence, the Company is conducting proactive Site Investigation and Remediation (SIR) efforts at Company-owned sites where past waste handling and disposal may have occurred. The Company currently estimates the total costs it could incur for SIR activities at Company-owned sites to be about $20 million. This estimate will vary as better site information is available. The Company anticipates spending $10 million over the next 5 years on SIR initiatives. Approximately $4.5 million has been provided for in rates through June 1996 for recovery of SIR costs. To the extent actual expenditures differ from this amount, they will be deferred for future disposition and recovery as authorized by the PSC.
In 1985, the New York State Department of Environmental Conservation (NYSDEC) identified property in the vicinity of the Lower Falls of the Genesee River (the Lower Falls) in Rochester as an inactive hazardous waste disposal site. The Company owns, and was the prior owner or operator of, a number of locations within the Lower Falls. In mid-1991, NYSDEC advised the Company that it had delisted the Lower Falls site, i.e., removed it from its Registry of Inactive Hazardous Waste Disposal Sites. The effect of delisting is to terminate the Company's status as a potentially responsible party for the Lower Falls site, to discontinue the pending NYSDEC review of a joint Company/City of Rochester proposal for a limited further investigation of the Lower Falls, to defer the prospect of remedial action and perhaps to end any Company sharing of the cost thereof. However, NYSDEC also stated its intention to consider listing individual coal gasification sites within the larger, original site once the State of New York adopts new federal hazardous waste criteria. There is at least some material at one of the individual coal gasification sites that could trigger relisting. The Company is unable to predict what further listing action NYSDEC may take, but regards the delisting as a positive development.
The Company and its predecessors formerly owned and operated coal gasification facilities within the Lower Falls. In September 1991 the Company initiated a study of subsurface conditions in the vicinity of retired facilities at its West Station property and has since commenced the removal of soils containing hazardous substances in order
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to minimize any potential long-term exposure risks. Cleanup efforts have been temporarily suspended while the Company investigates more cost effective remedial technologies. Activities are expected to resume within a year.
On a portion of the Company's property in the Lower Falls, and elsewhere in the general area, the County of Monroe has installed and operates sewer lines. During sewer installation, the County constructed over Company property, pursuant to an easement which the Company granted the County, certain retention ponds which reportedly received from the sewer construction area certain fossil-fuel-based materials ("the materials") found there. In July 1989 the Company received a letter from the County asserting that activities of the Company left the County unable to effect a regulatorily-approved closure of the retention pond area. The County's letter takes the position that it intends to seek reimbursement for its additional costs incurred with respect to the materials once the NYSDEC identifies the generator thereof and that any further cleanup action which the NYSDEC may require at the retention pond site is the Company's responsibility. In the course of discussions over this matter, the County has claimed, without offering any evidence, that the Company was the original generator of the materials. It asserts that it will hold the Company liable for all County costs --presently estimated at $1.5 million -- associated both with the materials' excavation, treatment and disposal and with effecting a regulatorily-approved closure of the retention pond area. The Company could incur costs as yet undetermined if it were to be found liable for such closure and materials handling, although provisions of the easement afford the Company rights which may serve to offset all or a portion of any such County claim. To date, the Company has agreed to pay a 20% share of the County's investigation of this area, which commenced in September 1993 and which is estimated to cost no more than $150,000, but no commitment has been made toward any remedial measures which may be recommended by the investigation.
In the letter announcing the delisting of the Lower Falls site, NYSDEC indicated an intention to pursue appropriate closure of the County's former retention pond area, suggesting that it will be evaluated separately to determine whether it meets the criteria of a hazardous waste site. The Company is unable to assess what implications the NYSDEC letter may have for the County's claim against it.
At another location along the River where the Company owns property, a boring taken in Fall 1988 for a sewer system project showed a layer containing a black viscous material. The Company undertook an investigation to determine the extent of the layer. The study found that some of the soil and ground water on- site had been adversely impacted by the hazardous substance constituents of the black viscous material, but evidence was inadequate to determine whether the material or its constituents had migrated off-site. The matter was reported to the NYSDEC and, in September 1990, the Company also provided the agency with a risk assessment for its review. That assessment concluded that the findings warranted no agency action and that site conditions posed no significant threat to the environment. Although NYSDEC could require the Company to undertake further investigation and/or remediation, the agency has taken no action in the nearly three and one-half years since the report's submittal.
In August 1990 the Company was notified of the existence of a federal Superfund site located in Syracuse, NY, known as the Quanta Resources Site. The federal Environmental Protection Agency (EPA) has included the Company in its list of approximately 25 potentially
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responsible parties (PRPs) at the site, but no data has been produced showing that any of its wastes were delivered to the site. In return for its release from liability for that phase, the Company has joined other PRPs in agreeing to divide among them, utilizing a two-tier structure, EPA's cost of a contractor- performed removal action intended to stabilize the site. The Company, in the lower tier of PRPs, paid its $27,500 share of such cost. The NYSDEC has not yet made an assessment for certain response and investigation costs it has incurred at the site, nor is there as yet any information on which to base an estimate of the cost to design and conduct at the site any remedial measures which federal or state authorities may require.
On May 21, 1993, the Company was notified by NYSDEC that it was considered a potentially responsible party (PRP) for the Frontier Chemical Pendleton Superfund Site located in Pendleton, NY. The Company has signed a PRP Agreement with approximately 15 parties and is participating in negotiations for an Administrative Order on Consent with NYSDEC. The PRPs have negotiated a workplan for site remediation and have retained a consulting firm to implement the workplan. Preliminary estimates indicate site remediation will be between $6 and $8 million. The Company is participating with the group to allocate costs among the PRPs. An allocation scheme has yet to be developed.
Monitoring wells installed at another Company facility in 1989 revealed that an undetermined amount of leaded gasoline had reached the groundwater. The Company has continued to monitor free product levels in the wells, and has begun a modest free product recovery project, reports on both of which are routinely furnished to the NYSDEC. Free product levels in the wells have declined, but authorities may require further remediation once most of the free product has been recovered.
The Company is developing strategies responsive to the Federal Clean Air Act Amendments of 1990 (Amendments). The Amendments will primarily affect air emissions from the Company's fossil-fueled electric generating facilities. The Company is in the process of identifying the optimum mix of control measures that will allow the fossil fuel based portion of the generation system to fully comply with applicable regulatory requirements. Although work is continuing, not all compliance control measures have been determined. The Company has adopted control measures for nitrogen oxides (NOx) emissions which must be in effect by the federally mandated compliance date of May 31, 1995. The chosen NOx control measures consist of the installation of low NOx burners on some units, the derating of unit generation by taking burners out of service on other units and placing one unit on cold standby with the redistribution of load to the remaining more efficient units. Capital costs for NOx controls and the installation of continuous emission monitoring systems are not expected to exceed $6.8 million and will be incurred during 1994 and 1995. A range of capital costs between $20 million and $30 million (1993 dollars) has been estimated for the implementation of several potential scenarios which would enable the Company to meet the foreseeable future NOx and sulphur dioxide requirements of the Amendments. These capital costs would be incurred between 1996 and 2000. The Company currently estimates that it could also incur up to $2 million (1993 dollars) of additional annual operating expenses, excluding fuel, to comply with the Amendments. The use of scrubbing equipment is not presently being considered. Likewise, the purchase or sale of "emission allowances," as allowed by the Amendments, is not currently being considered. The Company anticipates that the costs incurred to comply with the Amendments will be recoverable through rates based on previous rate recovery of
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environmental costs required by governmental authorities.
GAS COST RECOVERY.
Many interstate gas pipeline companies entered into contracts with gas producers which required the pipeline companies to pay for a minimum amount of gas whether or not the gas is actually taken from the producer (take-or-pay costs). Pursuant to FERC authorization, the Company's gas suppliers have included certain amounts of their take-or-pay costs in the rates charged to the Company.
The PSC instituted a proceeding in October 1988 to determine the extent to which the gas distribution companies in New York State would be permitted to recover in rates the take-or-pay costs imposed upon them. Through a series of subsequent settlements between the Staff of the PSC and the Company, the Company was permitted to recover in rates 87.5% of the first $12 million of the pipeline take-or-pay costs imposed upon it and all such costs in excess thereof except for a maximum of $562,500.
As of December 31, 1993 the Company had been billed for $17.6 million of take-or-pay costs and has thus far recovered $16.4 million from its customers. The Company expects only insignificant amounts of take-or-pay costs remain to be billed to the Company.
As a result of the restructuring of the gas transportation industry by the FERC, there will be a number of changes in this aspect of the Company's business over the next several years. These changes, which will apply throughout the industry, will affect different companies differently and may result, at least initially, in increases in the gas transportation costs of the Company. The Company will also be required to pay a share of certain transition costs incurred by the pipelines as a result of the FERC restructuring. Although the final amounts of such transition costs are subject to continuing negotiations with several pipelines and ongoing pipeline filings requiring FERC approval, the Company expects such costs to range between $43.5 and $52.0 million. A substantial portion of such costs will be on the CNG Transmission Corporation (CNG) system of which approximately $27 million was billed to the Company on December 3, 1993 payable over the following three years. The Company expects these transition costs to be recoverable in its rates.
In a related matter, in connection with the development of the Empire State Pipeline ("Empire"), the Company is committed as of November 1993, to transportation capacity from Empire, to upstream pipeline transportation and storage service and to the purchase of natural gas in quantities corresponding to these transportation and storage arrangements. The Company also has certain contractual obligations with CNG whereby the Company is subject to demand charges for transportation capacity for a period of eight years. In October 1993, the effective date of implementation of pipeline restructuring pursuant to FERC Order No. 636 and CNG's individual restructuring in Docket No. RS92-14, CNG's transportation rights on upstream pipelines were assigned to its customers, including the Company. The Company has concluded the corresponding contracts with those upstream pipelines.
The transportation service to be provided by Empire was scheduled to phase in over 12 months, at which point the combined CNG and Empire transportation capacity would have exceeded the Company's current requirements. Therefore, the Company recently entered into a marketing agreement with CNG, pursuant to which CNG will assist the Company in obtaining permanent replacement customers for the
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transportation capacity the Company will not require. It may renegotiate its arrangements with CNG and/or Empire or it may negotiate assignment, on a permanent or temporary basis, of the transportation capacity that exceeds the requirements of its customers. In addition, under FERC rules, the Company may sell its excess transportation capacity in the market. While CNG has already secured letters of intent for a substantial portion of such capacity, whether and to what extent CNG and/or the Company can successfully negotiate the assignment or sale of the excess capacity, or at what price, cannot be determined at the present time. The retention of some or all of this excess transportation capacity may cause an increase in the Company's gas supply costs. This would be in addition to any increase caused by other aspects of the gas transportation restructuring.
GAS PURCHASE UNDERCHARGES.
The Company became aware during 1993 that it did not account properly for certain gas purchases for the period August 1990 - August 1992 resulting in undercharges to gas customers of approximately $7.5 million. The Company had previously estimated the effect to approximate as much as $10 million; however, further review determined that the magnitude of the error on previously reported operations was substantially less.
The undercharges arose from the increased complexity arising from the federal deregulation of the gas industry and the Company's transition from a full requirements customer of one gas supplier to the purchase of gas transportation service and natural gas on the open market. Problems of this type are routinely corrected through the Gas Adjustment Clause process and appropriate amounts are collected from or refunded to customers. Of the total undercharges, $2.3 million has previously been expensed and $5.2 million had been deferred on the Company's balance sheet.
The Company advised the PSC and all parties to the Company's most recent rate proceeding of the undercharges. In its August 24, 1993 Order approving the Company's three-year rate settlement the PSC made the Company's current gas rates temporary solely to consider the impacts of the erroneous gas accounting, and in a September 13, 1993 Order the PSC instituted a proceeding to investigate the resulting undercollections and the recoverability of such amounts from customers. In its September 13 Order the PSC directed the Company to demonstrate fully the existence and amount of the undercharges, to explain the reasons for the errors, and to address possible general and specific legal limitations on the Company's right to recover portions of the undercharges. The Company filed evidence and analysis responsive to that Order on October 27, 1993.
On December 30, 1993, a proposed settlement among the Company, PSC Staff and another party was filed with the PSC. It provides for the recovery in rates of $3.2 million over three years, subject to audit and to limitations on rate adjustments established in the August 24 Order. The Company wrote off the $2.0 million balance of the undercharges as of December 31, 1993. That write- off amounts to a reduction in 1993 earnings of four cents per share, net of tax. Although no party, to the Company's knowledge, opposes the proposed settlement, the Company is unable to predict whether the PSC will approve it.
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OTHER MATTERS.
REGULATORY DISALLOWANCES. In June 1992 the Company recorded a charge to earnings of $8.2 million in connection with ice storm restoration costs disallowed by the PSC. In December 1991, the Company recorded a non-cash charge against earnings of $10 million for refunds to be made to customers in connection with a PSC fuel procurement audit.
NUCLEAR FUEL ENRICHMENT SERVICES. The Company has a contract with the United States Enrichment Corporation (USEC), formerly with the DOE, for nuclear fuel enrichment services which assures provision of 70% of the Ginna Nuclear Plant's requirements throughout its service life or 30 years, whichever is less. No payment obligation accrues unless such enrichment services are needed. Annually, the Company is permitted to decline USEC-furnished enrichment for a future year upon giving ten years' notice. Consistent with that provision, the Company has terminated its commitment to USEC for the years 2000, 2001 and 2002. The USEC waived, for an interim period, the obligation to give ten years' notice for 2003. The Company has secured the remaining 30% of its Ginna requirements for the reload years 1994 through 1995 under different arrangements with USEC. The Company plans to meet its enrichment requirements for years beyond those already committed by making further arrangements with USEC or by contracting with third parties. The cost of USEC enrichment services utilized for the next seven reload years (priced at the most current rate) ranges from $4 million to $7 million per year.
ASSERTION OF TAX LIABILITY. The Company's federal income tax returns for 1987 and 1988 have been examined by the Internal Revenue Service (IRS) which has proposed adjustments of approximately $29 million.
The adjustments at issue generally pertain to the characterization and treatment of events and relationships at the Nine Mile Two project and to the appropriate tax treatment of investments made and expenses incurred at the project by the Company and the other co-tenants. A principal issue appears to be the year in which the plant was placed in service.
The Company has filed a protest of the IRS adjustments to its 1987-88 tax liability and has had an initial hearing before the appeals officers. The Company believes it has sound bases for its protest, but cannot predict the outcome thereof. Generally, the Company would expect to receive rate relief to the extent it was unsuccessful in its protest except for that part of the IRS assessment stemming from the Nine Mile Two disallowed costs, although no such assurance can be given.
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Interim Financial Data
In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods. The variations in operations reported on a quarterly basis are a result of the seasonal nature of the Company's business and the availability of surplus electricity.
* Includes recognition of $1.9 million net-of-tax pension plan curtailment ** Includes recognition of $3.4 million net-of-tax pension plan curtailment *** Includes recognition of $5.4 million net-of-tax ice storm disallowance **** Includes recognition of $6.6 million net-of-tax fuels audit disallowance
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
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PART III
ITEM 10.


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 of Form 10-K relating to directors who are nominees for election as directors at the Company's Annual Meeting of Shareholders to be held on April 20, 1994, will be set forth under the heading "Election of Directors" in the Company's Definitive Proxy Statement for such Annual Meeting of Shareholders.
The information required by Item 10 of Form 10-K with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Part I as Item 4 - A of this Form 10-K under the heading "Executive Officers of the Registrant".
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Form 10-K will be set forth under the headings "Report of the Committee on Management on Executive Compensation", "Executive Compensation" and "Pension Plan Table" in the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 of Form 10-K will be set forth under the headings "General" and "Security Ownership of Management" in the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 of Form 10-K will be set forth under the heading "Election of Directors" in the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders.
Pursuant to General Instruction G(3) to Form 10-K, Items 10 through 13 have not been answered because, within 120 days after the close of its fiscal year, the Registrant will file with the Commission a definitive proxy statement pursuant to Regulation 14A which involves the election of directors. Regis- trant's definitive proxy statement dated March 7, 1994 will be filed with the Securities and Exchange Commission prior to April 30, 1994. The information required in Items 10 through 13 under the headings set forth above is incorpo- rated by reference herein by this reference thereto. Except as specifically referenced herein the proxy statement in connection with the annual meeting of shareholders to be held April 20, 1994 is not deemed to be filed as part of this Report.
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Part IV -------
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. The financial statements listed below are shown under Item 8 of this Report.
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for each of the three years ended December 31, 1993
Consolidated Balance Sheets at December 31, 1993 and 1992
Consolidated Statement of Cash Flows for each of the three years ended December 31, 1993
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1993
Schedule V - Property, Plant and Equipment (Utility Plant)
Schedule VI - Accumulated Depreciation and Amortization (Utility Plant)
Schedule VIII - Valuation and Qualifying Accounts
Schedule IX - Short-term Borrowings
Schedule X - Supplementary Income Statement Information
(a) 3. Exhibits
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The Company agrees to furnish to the Commission, upon request, a copy of all agreements or instruments defining the rights of holders of debt which do not exceed 10% of the total assets with respect to each issue, including the Supplemental Indentures under the General Mortgage and credit agreements in connection with promissory notes as set forth in Note 6 of the Notes to Financial Statements.
(b) Reports on Form 8-K - None
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Parentheses denote negative amounts
(a) Includes $375,929 addition to nuclear plant due to Nine Mile Two Settlement recognized in March, 1991.
Rochester Gas and Electric Corporation SCHEDULE V - UTILITY PLANT For the Year Ended December 31, 1992 (Thousands of Dollars)
Parentheses denote negative amounts
Rochester Gas and Electric Corporation SCHEDULE V - UTILITY PLANT For the Year Ended December 31, 1993 (Thousands of Dollars)
Parentheses denote negative amounts
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Rochester Gas and Electric Corporation SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT For the Year Ended December 31, 1991 (Thousands of Dollars)
Parentheses denote negative amounts
NOTES:
a. Represents mainly adjustments to accumulated depreciation due to Nine Mile Two Plant Settlement Agreement recognized in March 1991.
b. Represents reclassification as a long term liability for disposal of nuclear fuel.
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Rochester Gas and Electric Corporation SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT For the Year Ended December 31, 1992 (Thousands of Dollars)
Parentheses denote negative amounts
NOTES:
a. Represents miscellaneous adjustments of $1,003 and interdepartmental transfers of $(15).
b. Represents reclassification as a long term liability for disposal of nuclear fuel.
c. Represents interdepartmental transfers.
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Rochester Gas and Electric Corporation SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT For the Year Ended December 31, 1993 (Thousands of Dollars)
Parentheses denote negative amounts
NOTES:
a. Represents miscellaneous adjustments of $544 and interdepartmental transfers of $23.
b. Represents reclassification as a long term liability for disposal of nuclear fuel.
c. Represents interdepartmental transfers.
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ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1991
FOR THE YEAR ENDED DECEMBER 31, 1992/(b)/
FOR THE YEAR ENDED DECEMBER 31, 1993/(b)/
/(a)/ Accounts written off, less recoveries.
/(b)/ Beginning in 1992 the Company no longer charges uncollectible expenses through the uncollectible reserve. The total amount written off directly to expense in 1992 was $5,116 and in 1993 was $6,241.
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ROCHESTER GAS AND ELECTRIC CORPORATION SCHEDULE IX - SHORT TERM BORROWINGS(1) (Thousands of Dollars)
NOTES:
1. Borrowings under a Revolving Credit Loan Agreement are at Prime, C.D. or Libor rates plus a fraction thereof. Notes issued have various terms of maturity but do not exceed six months. The Company also issues commercial paper at various discount rates, usually maturing within 30-45 days.
2. Average amount outstanding is the simple average of the daily amount outstanding during the period.
3. Weighted average interest rate is computed by dividing the total interest accrued during the period by the daily average amount outstanding.
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ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
(Thousands of Dollars)
The amounts of maintenance and provisions for depreciation and amortization are as set forth in the Statements of Income and of Cash Flows. During the years 1991, 1992, and 1993 and the amounts for royalties or advertising costs did not exceed 1% of total revenues as reported in the Statement of Income. Taxes, other than Federal income tax, which exceed 1% of total revenues were classified as follows:
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
By ROGER W. KOBER ------------------------------------- (Roger W. Kober) (Chairman of the Board, President and Chief Executive Officer)
Date: February 15, 1994
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 in the capacities and on the dates indicated.
Signature Title Date
Principal Executive Officer:
ROGER W. KOBER Chairman of the Board, February 15, 1994 - ------------------------------ (Roger W. Kober) President and Chief Executive Officer
Principal Financial Officer and Principal Accounting Officer:
THOMAS S. RICHARDS Senior Vice President, February 15, 1994 - ------------------------------ (Thomas S. Richards) Finance and General Counsel
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Signature Title Date
Directors:
WILLIAM BALDERSTON III Director February 15, 1994 - ---------------------------------- (William Balderston III)
ANGELO J. CHIARELLA Director February 15, 1994 - ---------------------------------- (Angelo J. Chiarella)
ALLAN E. DUGAN Director February 15, 1994 - ---------------------------------- (Allan E. Dugan)
WILLIAM F. FOWBLE Director February 15, 1994 - ---------------------------------- (William F. Fowble)
JAY T. HOLMES Director February 15, 1994 - ---------------------------------- (Jay T. Holmes)
ROGER W. KOBER Director February 15, 1994 - ---------------------------------- (Roger W. Kober)
THEODORE L. LEVINSON Director February 15, 1994 - ---------------------------------- (Theodore L. Levinson)
CONSTANCE M. MITCHELL Director February 15, 1994 - ---------------------------------- (Constance M. Mitchell)
CORNELIUS J. MURPHY Director February 15, 1994 - ---------------------------------- (Cornelius J. Murphy)
ARTHUR M. RICHARDSON Director February 15, 1994 - ---------------------------------- (Arthur M. Richardson)
M. RICHARD ROSE Director February 15, 1994 - ---------------------------------- (M. Richard Rose)
Director February , 1994 - ---------------------------------- (Harry G. Saddock)