Annual Report (Form 10-K), fiscal year 1994

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, 1994 the Company had 2,075 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, 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, 1994.
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 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, 1994 was 5.28.
(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, 1994 the amount of additional First Mortgage Bonds which could be issued on that basis was approximately $356,674,000. 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, 1994, the Company could issue $194,334,000 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, 1994, the coverage ratio under (b) above (the more restrictive provision) was 2.13.
At December 31, 1994 the Company had $51.6 million of short-term debt outstanding consisting of $32.0 million of unsecured short-term debt and $19.6 million of secured short-term debt.
The Company's Charter provides that unsecured debt may not exceed 15% of the Company's total capitalization (excluding unsecured debt). At December 31, 1994, including the $32 million of unsecured debt already outstanding, the Company was able to issue $69.5 million of unsecured debt under this provision. The Company has unsecured short-term credit facilities totaling $72 million.
The Company has a $90 million revolving credit agreement which expires December 31,1997. 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, 1994, this provision would not restrict borrowings under the revolving credit agreement.
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, 1995, are secured by a lien on the Company's accounts receivable.
The Company has a $30 million credit agreement with a domestic bank until May 31, 1995 to provide funds for the Company's transition cost liability pursuant to Federal Energy Regulatory Commission Order No. 636. Borrowings under this agreement, which are secured by the Company's accounts receivable, totaled $18.7 million (recorded as a deferred credit on the Balance Sheet) at December 31, 1994.
The Company's Charter does not contain any financial tests for the issuance of preference or common stock.
The Company's securities ratings at December 31, 1994 were:
The securities ratings set forth in the table are subject to revision and/or withdrawal at any time by the respective rating organizations and should not be considered a recommendation to buy, sell or hold securities of the Company.
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.
On December 19, 1994, the PSC instituted a proceeding to review the Company's practices regarding acquisition of pipeline capacity, the costs of capacity and the Company's recovery of those costs. Pending conclusion of the proceeding, the PSC directed the Company to recover FERC Order No. 636 transition costs over a five-year period and all other unrecovered gas costs over 18 months. This proceeding follows an announcement made by the Company last fall that it expected purchased gas expense to be higher during the 1994-95 heating season. See the Notes to Financial Statements, Note 10 under the heading "Gas Cost Recovery" and Note 1 under the heading "Rates and Revenue" for further information related to this proceeding and for information related to the discontinuing of the weather normalization adjustment from January-May 1995 and its estimated impact on 1995 earnings.
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, 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.
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.
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 resolved the Company's rate case proceedings initiated in July 1992 and determines the Company's rates from July 1, 1993 through June 30, 1996. The 1993 Rate Agreement includes certain incentive arrangements providing for both rewards and penalties. See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Regulatory Matters" for a summary of recent PSC rate decisions, a summary of the 1993 Rate Agreement and a discussion of the incentive arrangements including a discussion of the risks and rewards available to the Company under the 1993 Rate Agreement.
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 approved by the PSC in March 1994. This tariff allows 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 will absorb 30 percent of any net revenues lost as a result of such discounts through June 1996, while the remainder may be recovered from other customers. The portion recoverable after June 1996 is expected to be determined in a future Company rate proceeding. The Company has negotiated long-term electric supply contracts with three of it's large industrial and commercial electric customers at discounted rates. It intends to pursue negotiations with other large customers as the need and opportunity arise. The Company has not experienced any customer loss due to competitive alternative arrangements.
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. The passage of the National Energy Policy Act of 1992 (Energy Act) has accelerated these competitive challenges by promoting competition in the electric power industry at the wholesale level, and ensuring that a new class of independent power producers established under the Energy Act, as well as qualified facilities and other electric utilities, can achieve access to utility-owned transmission facilities upon payment of appropriate prices. Competition in the Company's gas business was accelerated with the passage in April 1992 of the FERC's Order No. 636. In essence, FERC Order 636 requires interstate natural gas companies to offer customers "unbundled", or separately-priced sale and transportation services. The PSC has been conducting proceedings to investigate various issues regarding the emerging competitive environment
in the electric and gas business in New York State. See Item 7 - Managements Discussion and Analysis of Financial Condition and Results of Operations under the heading "Competition" for information on the competitive challenges the Company faces in it's electric and gas business and how it proposes to respond to those challenges.
ELECTRIC OPERATIONS
The total net generating capacity of the Company's electric system is 1,225,000 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, 50,000 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-Quebec purchased through the Power Authority. The Company's net peak load of 1,374,000 Kw occurred on July 21, 1994.
The percentages of electricity actually generated and purchased for the years 1990-1994 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 23%, 24% and 24%, for the years 1995, 1996 and 1997, 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. In terms of capacity these comprise 38%, 12%, 21%, 7% and 16%, respectively, of the Company's current electric generating system.
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 Company has four licensed hydroelectric generating stations with an aggregate capability of 47 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 is currently participating in negotiations with the New York State Department of Environmental Conservation (NYSDEC) and other parties to receive favorable Water Quality Certifications from the NYSDEC. The outcome of the process, as well as decisions on what environmental conditions FERC will impose in new licenses for the stations, will determine the content of state water quality certifications issued by the NYSDEC. The United States Supreme Court earlier this year decided a case brought by the State of Washington (Tacoma Case) which held that the various States had broad authority to impose non-water quality conditions in their certifications. The NYSDEC holds the view that this is the governing law in the State of New York, and has drafted new provisions accordingly. If the negotiations are unsuccessful, the Company will resume it's litigation in a NYSDEC administrative proceeding initially brought by the Company to challenge the 1992 certifications. This is anticipated to happen in the first quarter of 1995. 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 the stations 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.
Preparation for replacement of the two steam generators at the Ginna Nuclear Plant began in 1993 and will continue until the replacement in 1996. Steam generator fabrication is well underway. All major components for the steam generators have been ordered and most have been delivered. Major sub-assemblies are now being fabricated. Engineering for the installation is underway and will be completed well before the scheduled installation. Cost of the replacement is estimated to be $115 million, about $40 million for the steam generators, about $50 million for the installation and the remainder for Company engineering, radiation protection, plant support and other services. In 1994 the Company spent approximately $16 million for the replacement project. The installation contractor, Bechtel Power Corporation, has established a presence at the Ginna site and 1995 activities will include a number of in-containment modifications during the normal refueling outage in preparation for the 1996 replacement. Following the 1995 outage, support facilities will be constructed in preparation for the spring 1996 replacement.
The gross and net book cost of the Ginna Plant as of December 31, 1994 are $484 million and $258 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 $30.0 million in 1995 and $48.5 million in 1996 for steam generator replacement as discussed above) are estimated to be $47.8 million, $61.3 million and $6.5 million for the years 1995, 1996 and 1997, 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 5,625,000 Therms (one Therm is equivalent to 1,000,000 British Thermal Units). On January 19, 1994, the Company experienced its maximum daily throughput of approximately 4,735,690 Therms.
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, 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 Supply and Costs - Gas" for a discussion of that topic and "Capital Requirements and Gas Operations" for a discussion of Empire.
The Company continues to provide new and additional gas service. Of 235,313 residential gas spaceheating customers at December 31, 1994, 3,376 were added during 1994, and 30% of those were conversions from other fuels.
Approximately 26% of the gas delivered to customers by the Company during 1994 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 hexafluoride, (3) the enrichment of the uranium hexafluoride, (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) A contract is in place with flexibility to supply from 20 to 80 percent of the annual Ginna uranium requirements. A second contract is in place to supply about 20% of the annual requirements for 1995. The remaining requirements are uncommitted.
(4) Seventy percent of the conversion requirements have been procured through 1997.
(5) 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) 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. For further information concerning this contract see Item 8, Note 10 under the heading "Nuclear Fuel Enrichment Services".
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 has completed a conceptual study of alternatives to increase the capacity for the interim storage of spent nuclear fuel at the Ginna Plant. The preferred alternative, based on cost and safety criteria, is to install high-capacity spent fuel racks in the existing area of the spent fuel pool. The additional storage capacity, scheduled to be implemented prior to September 2000, would allow interim storage of all spent fuel discharged from the Ginna Plant through the end of it's Operating License in the year 2009.
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 to be $70.9 million at December 31, 1994. The Company is allowed by the
PSC to recover these costs in rates. The estimated fees are classified as a long term liability and interest is accrued at the three-month Treasury bill rate, adjusted quarterly. The Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of one mill ($.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 $163.0 million, and those for the Company's 14% share of Nine Mile Two are estimated to be approximately $37.1 million (January 1994 dollars). Through December 31, 1994, the Company has accrued and recovered in rates $70.1 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 Note 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 560,000 tons. In 1994 approximately 95% of its requirements were purchased under contract and the balance on the open market. The Company is meeting its requirements during early 1995 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 1.0 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
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 $2.9 million on a variety of projects and facility additions during 1994.
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. The Company can provide no assurance as to what disposal arrangements, if any, New York will have in place. The State has not passed legislation that would designate a site for the disposal of low level radioactive waste. In 1990, then 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 extended it's interim storage capacity at the Ginna Plant from December 31, 1995 through mid-1999. Efforts will be pursued to extend storage capacity beyond 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 Ginna, Beebee, and Russell Stations, which were renewed in July, 1992, February, 1994, and June 1994, respectively. These permits are each effective for a period of five years. Consistent with these permits, no significant changes to the wastewater discharge treatment systems are currently required, nor anticipated.
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 $2.2 million for the year 1995, $2.8 million for the year 1996 and $22.6 million for the year 1997. 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 1994, 1993 and 1992 were $7.3 million, $8.3 million, and $7.4 million 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.
* Method for determining daily capacity, based on current network analysis, reflects the maximum demand which the transmission systems can accept without a deficiency.
ITEM 2.



ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of the Company's electric generating plants in operation as of December 31, 1994, the net generation of each plant for the year ended December 31, 1994, and the year each plant was placed in service are as set forth below:
ELECTRIC GENERATING PLANTS
(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 147 distribution substations having an aggregate rated transformer capacity of approximately 2,091,104 Kva, of which 138, having an aggregate rated capacity of 1,911,938 Kva, were 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 75,486 line transformers with a capacity of 2,973,933 Kva. The Company also owns 24 transmission substations having an aggregate rated capacity of approximately 3,052,017 Kva of which 23, having an aggregate rated capacity of approximately 2,977,350 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 707 wire miles of overhead lines and 399 wire miles of underground lines. The distribution system consists of approximately 16,181 wire miles of overhead lines, approximately 3,580 wire miles of underground lines and 345,988 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 4,172 miles of gas mains and 284,006 installed meters. (See Item 1 - Business, "Gas Operations".)
OTHER PROPERTIES
The Company owns a ten-story office building centrally located in Rochester and other structures and property. The Company also leases a 153,000 square foot Customer Service Center in Rochester.
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 and Item 7, under the heading entitled "Projected Capital and other Requirements".
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, 1994.
ITEM 4 - A. EXECUTIVE OFFICERS OF THE REGISTRANT
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.
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 1994, 1993 and 1992 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 Company believes that future dividend payments will need to be evaluated in the context of maintaining the financial strength necessary to operate in a more competitive and uncertain business environment. This will require consideration, among other things, of a dividend payout ratio that is lower over time, reevaluating assets and managing greater fluctuation in revenues. While the Company does not presently expect the impact of these factors to affect the Company's ability to pay the current dividend, future dividends may be affected. 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 1995, the Company paid a cash dividend of $.45 per share on its Common Stock, up $.01 from the prior quarterly dividend payment of $.44. The January 1995 dividend payment is equivalent to $1.80 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".
Item 6.

Item 6. Selected Financial Data
(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) Rate of return on average common equity excludes the effects of retirement enhancement programs recognized by the Company in 1994 and 1993.
(c) Excludes disallowed Nine Mile Two plant costs written off in 1989.
(d) 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 1994 and 1993 exclude the effects of retirement enhancement programs recognized by the Company during each year and certain gas purchase undercharges written off in 1994 and 1993.
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.
EARNINGS SUMMARY
Operating earnings have improved due to modest rate relief and lower interest expense, coupled with cost control efforts by the Company and savings resulting from work force reduction programs in 1993 and 1994.
Presented below is a table which summarizes the Company's Common Stock earnings on a per-share basis. Non-recurring items and their effect on earnings per share have been identified. Earnings per share as reported in 1994 fell below 1993 levels, reflecting one-time charges for work force reduction programs completed during the past year. A total of 572 persons, or about 22 percent of the work force elected to participate in one of three programs offered in 1993 and 1994. Of that total, 399 were participants in the most recent program completed on October 1, 1994. The overall after-tax savings of the program are estimated to be about $61 million through 1998. The latest program resulted in a one-time charge in September 1994 of $33.7 million, or $.59 per share, net of tax. The 1993 writeoffs totaled $8.2 million or $.15 per share for the earlier programs.
In addition to the cost of the work force reduction programs, earnings as reported include a charge of $.01 per share in 1994 and $.04 per share in 1993 for unrecoverable gas costs.
Excluding the impact of non-recurring items, earnings per share for 1994 and 1993 were up despite the effect of the issuance of additional Common Stock in each year. Future earnings will be affected, in part, by the Company's success in controlling operating and capital costs within the levels targeted under the terms of the 1993 Rate Agreement (see Regulatory Matters), as well as achieving certain incentive goals established in that Agreement. Furthermore, a decision in early 1995 by the Company to discontinue operation of a weather normalization clause under certain circumstances through May 1995 is expected to have an impact on 1995 earnings as discussed under Operating Revenues and Sales. The impact of developing competition in the energy marketplace may also affect future earnings.
EARNINGS PER SHARE - SUMMARY
DIVIDEND POLICY
In December 1993 the Company announced a quarterly dividend increase from $.43 to $.44 per share of Common Stock payable in January 1994. Subsequently, in December 1994 the Company announced a new quarterly dividend rate of $.45 per share payable in January 1995. The Company's Certificate of Incorporation (Charter) provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company. The Company believes that future dividend payments will need to be evaluated in the context of maintaining the financial strength necessary to operate in a more competitive and uncertain business environment. This will require consideration, among other things, of a dividend payout ratio that is lower over time, reevaluating assets and managing greater fluctuation in revenues. While the Company does not presently expect the impact of these factors to affect the Company's ability to pay the current dividend, future dividends may be affected.
COMPETITION
OVERVIEW. The Company is operating in a rapidly developing competitive marketplace for electric and gas service. In its electric business, this competitive environment includes a Federal trend toward deregulation and a state trend toward incentive regulation. The passage of the National Energy Policy Act of 1992 (Energy Act) has accelerated these competitive challenges by promoting competition in the electric power industry at the wholesale level, and ensuring that a new class of independent power producers established under the Energy Act, as well as qualified facilities and other electric utilities, can achieve access to utility-owned transmission facilities upon payment of appropriate prices. Competition in the Company's gas
business was accelerated with the passage of the Federal Energy Regulatory Commission's (FERC) Order No. 636. In essence, FERC Order 636 requires interstate natural gas pipeline companies to offer customers "unbundled", or separately-priced, sale and transportation services.
ELECTRIC UTILITY COMPETITION. Cost pressures on major customers, excess electric capacity in the region, and new technology 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 customer access to the transmission system in order to purchase electricity from suppliers other than the Company.
In New York State, the Public Service Commission (PSC) has encouraged competition by requiring utilities to purchase power from non-utility generating companies at prices in excess of the utilities' internal cost of production, has established various incentive mechanisms in rate proceedings to provide lower cost energy, and has authorized flexible pricing for certain large customers who have "realistic competitive alternatives".
Phase I of a PSC proceeding to address various issues related to increasing competition in the New York State electric energy markets was completed in the summer of 1994. The PSC approved flexible rate discounts for non-residential electric customers who have competitive alternatives and adopted specific guidelines for such rates. The PSC noted that flexible rates being offered by the Company should serve as one of the models for other utilities within the State. Phase II of this proceeding is currently underway with an objective to identify regulatory and ratemaking practices that will assist in a transition to a more competitive electric energy market, including investigating the establishment of an efficient wholesale competitive market, and various issues relating to retail competition. In a Notice issued in December 1994 inviting comments on proposed principles to guide the transition to competition, the PSC set forth nine general principles as follows. First, competition is endorsed, especially at the wholesale level. Second, service affordability must be maintained. Third, research programs, environmental protection, energy efficiency and fuel diversity must be preserved. Fourth, safety and reliability must not be jeopardized. Fifth, new industry structures should provide increased choice for customers, consumer protection, efficiency incentives and flexibility to accommodate individual utilities. Sixth, more competition should lead to less regulation. Seventh, the current vertically integrated industry is incompatible with effective competition. Eighth, utilities that cooperate in the furthering of these principles should have a reasonable opportunity to recover their costs. Ninth, changes in the industry should result in rising income levels.
While the Company is in agreement with the spirit underlying most of the principles described above, their
implementation could subsequently alter the nature and magnitude of the business risks faced by the Company. This is especially true of any change resulting from the seventh principle. In general, the Company believes market-based solutions to the challenges facing this industry will ultimately result in the greatest shareholder value, and it will continue to work to implement such solutions. The Company cannot predict when Phase II will be completed or the final outcome of this proceeding.
GAS UTILITY COMPETITION. Competition in the Company's gas business has existed for some time, as larger customers have had the option of obtaining their own gas supply and transporting it through the Company's distribution system. FERC Order 636 enables 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 has shifted from interstate pipeline companies to local distribution companies, such as the Company.
In October 1993 the PSC initiated a proceeding to address issues involving the restructuring of gas utility services to respond to competition. In December 1994, the PSC issued an order which established regulatory policies and guidelines for natural gas distributors. The requirements of the order having the greatest impact on the Company are as follows. First, the Company must offer its customers unbundled access to upstream facilities such as storage and transportation capacity on the interstate pipelines with which the Company does business. Second, the Company may offer to package an individual supply of gas to an individual customer in cases where that would lower the Company's overall cost of supplying gas. Third, the Company must offer an aggregation program whereby individual customers could join together in a pool for the purpose of purchasing gas from a supplier; in such cases the Company would still provide the service of distributing the gas on the Company's system. Fourth, the PSC allow the full recovery of the transition costs resulting from FERC Order 636, and require that a share of these costs be borne by firm transportation customers. Fifth, the PSC will institute a future proceeding to consider incentive-based gas cost recovery mechanisms, a departure from the full flow- through mechanism in place today. Lastly, the PSC will institute a separate proceeding to bring about programs ensuring that all customers have access to a basic, affordable gas service. The Company is reviewing these policies and, at the present time, is unable to predict their impact.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. The stock of New York utilities, including the Company, has dropped during the past year reflecting, in part, investor concern over the impact of the competitive and regulatory changes which have occurred. Some critics have suggested that certain New York State utilities should write down certain regulatory or generating assets as a result of these changes. The Company has deferred certain costs and is recognizing them as expenses when they are reflected in rates and
recovered from customers as permitted by Statement of Financial Accounting Standard No. 71 (SFAS-71). These costs are shown as Regulatory Assets on the Company's Balance Sheet and a discussion and summarization of such Regulatory Assets is presented in Note 10 of the Notes to Financial Statements. Deferral of these costs is appropriate while the Company's rates are regulated under a cost-of-service approach. In a purely competitive pricing approach, such costs might not have been incurred or deferred. Accordingly, if the Company's rate setting were changed from a cost-of-service approach and it was no longer allowed to defer these costs under SFAS-71, certain of these assets may not be fully recoverable. In addition, stranded assets (or other costs) arise when investments are made in facilities or costs are incurred to service customers and such costs may not be fully recoverable in rates. Examples include purchase power contracts (i.e. the Kamine/Besicorp Allegany L.P. contract, see Projected Capital and Other Requirements) or uneconomic generating assets. Excluding the Kamine/Besicorp Allegany L.P. contract, estimates of stranded asset costs are highly sensitive to the competitive wholesale market price assumed in the estimation for electricity. The amount of stranded assets at December 31, 1994 cannot be determined at this time, but could be significant. While the Company currently believes that its regulatory and stranded assets are probable of recovery in rates, industry trends have moved more toward competition, and in a purely competitive environment, it is not clear to what extent, if any, writeoffs of such assets may occur.
THE COMPANY'S RESPONSE. The growing pace of competition in the energy industry has been a primary focus of management over the past three years. The Company accepts the challenges of this new environment and is working to anticipate the impact of increased competition. Its business strategy for one year and in summary for five years, focuses on improving cost-effective service while reducing expenses and maintaining a competitive return for the shareholder. The Company is engaged in a continuous process improvement program to find opportunities for improved service and efficiency. It has implemented three work force reduction programs during 1993 and 1994 which have had, and will continue to have, a favorable impact on reducing operating costs, while still enabling the Company to deliver safe, quality service. Also, the Company in August 1994 streamlined its internal organization by combining 14 division- sized functions into three functional areas as part of an ongoing effort to provide customers with the best possible service at the lowest possible price.
The Company is operating under 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. By settlement with the PSC and others, the Company has a competitive rate tariff that allows negotiated rates with larger industrial and commercial customers
that have competitive electric supply options. Furthermore, the Company has proposed for PSC approval two new flexible pricing tariffs to encourage economic development and new business growth in our service territory.
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 mitigate its costs and increase earnings in the new gas business environment.
The Company is evaluating all the factors which impact the rates it charges its customers and therefore its competitive position, both with respect to industrial and commercial customers as well as residential customers. In that regard, it is reviewing its regulatory assets (costs which have been deferred for collection in future rates) and generating facilities for their impact on the Company's rate structure. The Company's workforce reduction programs, efforts to control fixed and operational costs and decisions to delay any collection of incentives earned under the 1993 Rate Agreement (see Regulatory Matters) all relate to a focus on trying to maintain a rate structure which has long-term benefits for the competitive presence of the Company in the industry. The Company is reviewing its financing strategies as they relate to debt and equity structures, the cost of these structures including the dividend program and their impact on the Company's rate structure. All of these evaluations are in the context of the new competitive environment and the ability of the Company to shift from a fully regulated to a more competitive and growth- oriented organization.
In addition to strategies aimed at creating a competitive rate structure, the Company is reviewing strategies which may enhance it's ability to respond to competitive forces and regulatory change. These strategies may include business partnerships or combinations with other companies, internal restructuring involving a separation of some or all of its wholesale and retail businesses, and acquisitions of related businesses. No assurance can be given that any of these potential strategies will be pursued or the corresponding results on the financial condition or competitive position of the Company.
LIQUIDITY AND CAPITAL RESOURCES
During 1994 cash flow from operations, together with proceeds from external financing activity (see Consolidated Statement of Cash Flows), provided the funds for construction expenditures, the retirement of long-term debt and short- term borrowings and the retirement and refinancing of Preferred Stock.
Capital requirements during 1995 are anticipated to be satisfied primarily from the use of internally generated funds.
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.
Under Federal and New York State laws and regulations, the Company is required to purchase the electrical output of unregulated cogeneration facilities which meet certain criteria (Qualifying Facilities). With the exception of one contract which the Company was compelled by regulators to enter into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts of capacity, the Company has no other long-term obligations to purchase energy from Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the contract with Kamine was negotiated, the Company was required to pay Kamine a price for power that is substantially greater than the Company's own cost of production and other purchases. Since that time, the State law mandating a minimum price higher than the Company's own costs has been repealed and PSC estimates of future prices on which the contract was based have declined dramatically.
In September 1994 the Company filed a lawsuit against Kamine seeking to void its contract for the forced purchase of unneeded electricity at above- market prices which would result in substantial cost increases for the Company's customers. The Company estimates that Kamine will owe the Company $400 million by the midpoint of the contract term and if the contract extends to its full 25- year term, the total amount of such overpayments (plus interest) could reach approximately $700 million. Alternatively, the Company sought relief to ensure that its customers would pay no more for the Kamine power than they would pay for power from the Company's other sources of electricity. Kamine answered the Company's complaint, seeking to force the Company to take and pay for power at the above-market rates and claiming damages in an unspecified amount alleged to have been caused by the Company's conduct. The Company is unable to predict the ultimate outcome of this litigation. The Company began receiving test generation from the Kamine facility during the last quarter of 1994. In late December 1994, the Company announced it would no longer be accepting electric power from this facility because it is the Company's position, in addition to other beliefs, that the Kamine facility is no longer a "Qualifying Facility" as specified under Federal regulations.
On January 27, 1995 Kamine initiated a lawsuit against the Company in Federal District Court for the Western District of New York for alleged anti- trust violations by the Company that are based on the same issues that are raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks injunctive relief similar to that requested in Kamine's answer to the Company's lawsuit in New York State Court and damages of $420 million. The Company intends to vigorously defend against this lawsuit, but is unable to predict the outcome at this time.
The Company's most current Integrated Resource Plan (IRP) explores options for complying with the 1990 Clean Air Act Amendments. The IRP is part of an ongoing planning process to examine options for the future with regard to generating resources and alternative methods of meeting electric capacity requirements. Activities are currently under way to:
- Modify Units 2, 3, and 4 at Russell Station and Unit 12 at Beebee Station, all coal-fired facilities, to meet Federal Environmental Protection Agency standards and Clean Air Act requirements,
- Explore possible partnerships with certain large customers to use alternative generation or existing generation to mutual benefit,
- Use demand side management programs to reduce the need for generating capacity, and
- Replace the two steam generators at the Ginna Nuclear Plant.
Replacement of the two steam generators at the Ginna Nuclear Plant is expected to be completed in 1996. Much of the preliminary preparation is being done during the normal annual refueling and maintenance outages. The Company anticipates that the 1996 outage for refueling and final replacement will take about 70 days. Cost of the replacement is estimated at $115 million; about $40 million for the units, about $50 million for installation and the remainder for engineering and other services. As discussed under Regulatory Matters, a three- year rate settlement establishes a mechanism to share variances from the estimated $115 million cost between customers and the Company.
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 1994 included $31 million of expenditures made at the Company's Ginna Nuclear Plant, of which $16 million was incurred for preparation to replace the steam generators. The Company spent $15 million on this project in 1993. In addition, nuclear fuel expenditures of $11 million were incurred at Ginna during 1994. A refueling outage at Ginna normally occurs annually for a period of approximately 40 to 50 days. Refueling is expected to take place on an 18-month cycle once the new steam generators are installed.
Exclusive of fuel costs, the Company's 14 percent share of electric production plant expenditures at the Nine Mile Two nuclear facility totaled $5 million in 1994. Expenditures of $5 million during 1994 were also 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 and resumed full operation on December 3, 1993. The next refueling outage for Nine Mile Two is scheduled for April 1995.
Electric transmission and distribution expenditures, as presented in the Capital Requirements table, totaled $26 million in 1994, 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. The Empire State Pipeline (Empire), an intrastate natural gas pipeline subject to PSC regulation between Grand Island and Syracuse, New York commenced operation in November 1993. Empire provides capacity for up to 50 percent of the Company's gas requirements. The Company is participating as an equity owner of Empire, along with subsidiaries of Coastal Corporation and Westcoast Energy Inc. The PSC authorized the Company to invest up to $20 million in Empire. The Company's share of ownership in Empire will depend upon final project costs and method of financing selected by Empire. In June 1993 Empire secured a $150 million credit agreement, the proceeds of which were used to finance approximately 75 percent of the total construction cost and initial operating expenses. At December 31, 1994 the Company had invested a net amount of $10.3 million in Energyline and was committed to provide a guarantee for $9.7 million of the borrowings under the credit agreement.
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 resulted in gas property construction requirements of $20 million in 1994.
ENVIRONMENTAL ISSUES
GENERAL. 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. 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. (See Note 10 of the Notes to Financial Statements.)
FEDERAL CLEAN AIR ACT AMENDMENTS. 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. A range of capital costs between $20 million and $30 million has been estimated for the implementation of several potential scenarios which would enable the Company to meet the foreseeable NOx and sulphur dioxide requirements of the Amendments. These capital costs would be incurred between 1996 and 2000. The Company estimates that it could also incur up to $2.1 million of additional annual operating expenses, excluding fuel, to comply with the Amendments. 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.
REDEMPTION OF SECURITIES
Discretionary redemption of securities totaled $24.5 million during 1994. A $16 million first mortgage bond maturity and $11.3 million of sinking fund obligations were also a part of the Company's capital requirements in 1994.
Capital requirements in 1993 included a $75 million first mortgage bond maturity, $17 million of sinking fund obligations, and discretionary first mortgage bond redemptions of $120 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 1992 to 1994 and the current estimate of capital requirements through 1997 are summarized in the Capital Requirements table.
* Excludes prospective refinancings.
FINANCING AND CAPITAL STRUCTURE
Capital requirements in 1994 were satisfied primarily by a combination of internally generated funds and short-term borrowings and the Company foresees modest near-term financing requirements. With an increasingly competitive environment, the Company believes maintaining a high degree of financial flexibility is critical. In this regard, the Company's long-term objective is to control capital expenditures, to move to a less leveraged capital structure and to increase the common equity percentage of capitalization toward the 50 percent range.
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, and other factors.
FINANCING. Under provisions of the Company's 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. At December 31, 1994, including the $32.0 million of unsecured indebtedness already outstanding as discussed in the following paragraph, the Company was able to issue $37.5 million of additional unsecured debt under this provision.
Short-term credit is available from certain banks pursuant to a $90 million revolving credit agreement which continues until December 31, 1997 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 to provide for borrowing up to $30 million for the exclusive purpose of financing FERC Order 636 transition costs (see Energy Supply and Costs-Gas) and up to $20 million as needed from time to time for other working capital needs. Borrowings under this agreement, which can be renewed annually, are secured by a lien on the Company's accounts receivable. The Company also has unsecured lines of credit totaling $72 million with several other banks. Funds available pursuant to these lines of credit are at the discretion of the respective banks. At December 31, 1994 the Company had short-term borrowings outstanding of $51.6 million, consisting of $32.0 million of unsecured short- term debt and $19.6 million of secured short-term debt. In addition, borrowings of $18.7 million associated with FERC Order 636 transition costs (recorded on the Balance Sheet as a deferred credit) were outstanding at December 31, 1994.
In March 1994 the Company redeemed 180,000 shares of its 8.25% Preferred Stock, Series R, representing all of the outstanding shares of this series. At the Company's option, 120,000 of these shares were redeemed prior to their normal sinking fund redemption date. Later that month, the Company issued 250,000 shares of 6.60% Preferred Stock, Series V.
During 1994 approximately 644,000 new shares of Common Stock were sold through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan (ADR Plan), providing $14.8 million to help finance its capital expenditures program. New shares issued in 1994 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 Company's retained earnings at December 31, 1994 were $74.6 million, a decrease of approximately $0.5 million compared with a year earlier. Retained earnings were reduced by approximately $21.9 million in September 1994 resulting from the charge for a workforce reduction program, as discussed under the heading Earnings Summary. Common equity (including retained earnings) comprised 44.5 percent of the
Company's capitalization at December 31, 1994, with the balance being comprised of 7.3 percent preferred equity and 48.2 percent long-term debt. 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 10 of the Notes to Financial Statements. To improve its capital structure, the Company currently anticipates the issuance of new shares of Common Stock, primarily through the Company's ADR Plan. The Company is reviewing its financing strategies as they relate to debt and equity structures in the context of the new competitive environment and the ability of the Company to shift from a fully regulated to a more competitive organization.
REGULATORY MATTERS
NEW YORK STATE PUBLIC SERVICE COMMISSION (PSC). The Company is subject to PSC regulation of rates, service, and sale of securities, among other matters. 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. 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 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 petition the PSC for relief.
In the first quarter of 1994 the Company filed with the PSC certain adjustments required under various clauses of the 1993 Rate Agreement and new rates were subsequently approved and became effective for the rate year beginning July 1, 1994 (Year 2 under the Agreement). These new rates primarily reflect adjustments for higher property taxes, a Federal tax rate increase, and variations in electric sales between actual and projected levels offset, in part, by operating and maintenance expense savings achieved in Year 1 under the 1993 Rate Agreement.
A summary of recent PSC rate decisions is presented in the table titled Rate Increases. The amounts presented in this table do not include any variations from the estimated cost of fuel included in base rates which are or may be collected/refunded through the Company's fuel clause provisions (see Operating Revenues and Sales).
* See under heading Regulatory Matters for additional details. Amounts for 1995 are subject to certain adjustments to be filed with the PSC by the Company in March 1995.
The 1993 Rate Agreement includes:
- Incentive mechanisms that have the potential to either increase or reduce earnings from 5 to 110 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, 1995, these incentives have the potential to affect earnings by approximately $12 million.
- Mechanisms for sharing costs between customers and shareholders for operation and maintenance expense variations. In general, these variances are shared 50% by customers and 50% by the Company, unless those costs are directly manageable by the Company, in which case there is no sharing and such costs are to be absorbed/retained by the Company.
- Mechanisms for sharing 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. If there is an overspending variance, the Company will write off 50% of the net cumulative amount of the variance.
- Sharing mechanism regarding the replacement of the Ginna Nuclear Plant 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. Replacement of the steam generators was made subject to a final prudency review by the PSC.
- 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 base revenue increase shown in the table titled Rate Increases may be adjusted up or down in Year 3. Negotiated electric base rate increases could be reduced to zero or increased up to an additional 1.6% in Year 3 and 1.8% in the following year. Negotiated gas base rate increases could also be reduced to zero or increased up to an additional 1.6% in Year 3, and 1.8% in the following year, exclusive of the impact of Empire going into service.
Contained in the rate order for Year 2 is recognition of $9.6 million related to the Company's performance in Year 1, recovery of which the Company has delayed for future consideration. The $9.6 million is comprised of the following:
- $1.9 million for ERAM,
- $6.7 million for an Integrated Resource Management Incentive or relative electric production efficiency, and
- $1.0 million for a Service Quality Incentive.
In electing to delay for possible future recovery those incentive amounts for which it was entitled, the Company gave consideration to the current and future competitive environment and its objective for minimizing price impacts on the customer while protecting earnings for shareholders.
The Company obtained PSC approval for a new flexible pricing tariff for major industrial and commercial electric customers in a settlement approved by the PSC in March 1994. This tariff allows 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 will absorb 30 percent of any net revenues lost as a result of such discounts through June 1996, while the remainder may be recovered from other customers.
The portion recoverable after June 1996 is expected to be determined in a future Company rate proceeding. Under these tariff provisions, the Company has negotiated long-term electric supply contracts with three of its large industrial and commercial electric customers at discounted rates. It intends to pursue negotiations with other large customers as the need and opportunity arise. The Company has not experienced any customer loss due to competitive alternative arrangements.
The PSC Staff is currently reviewing the Company's application for the recovery of certain deferred gas costs as discussed under the heading Energy Supply and Cost - Gas.
The PSC has been conducting proceedings to investigate various issues regarding the emerging competitive environment in the electric and gas business in New York State, as noted under the heading Competition.
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. Of the total undercharges, $2.3 million had previously been expensed and $5.2 million had been deferred on the Company's Balance Sheet. In March 1994, the PSC approved a December 1993 settlement among the Company, PSC Staff and another party providing for the recovery in rates of $2.6 million over three years. The Company wrote off $2.0 million of the undercharges as of December 31, 1993, reducing 1993 earnings by four cents per share, net of tax. In April 1994 the Company wrote off an additional $0.6 million reducing 1994 earnings by approximately one cent per share, net of tax. Due to rate increase limitations established for Year 2 of the rate settlement, the Company is precluded from recovering the undercharges until Year 3, which begins July 1, 1995.
In June 1992 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 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.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant changes in the amounts of revenues and expenses, comparing 1994 to 1993 and 1993 to 1992. The Notes to Financial Statements contain additional information.
OPERATING REVENUES AND SALES
Compared with a year earlier, operating revenues rose
five percent in 1994 following a six percent increase in 1993. Operating revenues in 1994 were pushed higher by gains in retail customer electric and gas revenues, while revenues from the sale of electric energy to other utilities were basically unchanged from a year earlier. Customer revenue increases in 1994 resulted primarily from rate relief and recovery of higher fuel costs. 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.
Changes in FUEL AND PURCHASED POWER COST REVENUES normally have been earnings neutral in the past. 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 1993 and $3.9 million in 1994, primarily reflecting actual experience in both electric fuel costs and generation mix compared with rate assumptions. Deferred costs associated with the DOE's assessment for future uranium enrichment decontamination and certain transition costs incurred by the Company's gas supply pipeline companies and billed to the Company are being recovered through the Company's fuel adjustment clauses.
The effect of WEATHER variations on operating revenues is most measurable in the Gas Department, where revenues from
spaceheating 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 spaceheating. Weather in the Company's service area during 1993 was colder than normal, in contrast to 1994 which was warmer than normal, despite record-setting cold weather in January 1994. Overall, weather during 1994 was 4.9 percent warmer than 1993 on a calendar-month heating degree day basis. Warmer than normal summer weather during 1994 and 1993 boosted electric energy sales to meet the demand for air conditioning usage. 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.
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 cycle month basis for the months of October through May, inclusive. The weather normalization adjustment for a billing cycle applies 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 1994 and 1993 by approximately $1.25 million and $1.2 million respectively. Adjustments will continue through June 1996 in accordance with the 1993 Rate Agreement for weather which is colder than normal. However, beginning in January 1995 and continuing until May 1995, the Company elected to discontinue the operation of this clause in circumstances where the weather is warmer than normal because of the unusually mild weather that has been experienced in its service territory and the adverse effects on customer bills. The earnings impact of this decision in 1995 will range between $3.5 and $8.7 million depending on the duration of mild weather for the heating season.
Compared with a year earlier, KILOWATT-HOUR SALES OF ENERGY TO RETAIL CUSTOMERS were nearly flat in 1994, after climbing about one percent in 1993. Electric demand for air conditioning usage had a significant impact on such sales in each of these years. During 1993 and 1994, an increase in combined sales to residential and commercial customers more than offset a decline in sales to industrial customers, which occurred as a result, in part, of a decline in local manufacturing employment. The Company had a net gain of over 2,600 new electric customers during 1994, including nearly 350 new commercial customers.
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 1993 and 1994 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 the possibility of 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 distribute this gas, which amounted to 13.6 million dekatherms in 1994 and 12.4 million dekatherms in 1993. These purchases have caused decreases in customer revenues, with offsetting decreases in purchased gas expenses, but in general do not adversely affect earnings because transportation customers are billed at rates which, except for the cost of buying and transporting gas to our city gate, 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 COMBINED, including unbilled sales, were down about two percent in 1994, after being nearly flat in 1993. These changes reflect, primarily, the effect of weather variations on therm sales to customers with spaceheating. If adjusted for normal weather conditions, residential gas sales would have increased about 0.6 percent in 1994 over 1993, while nonresidential sales, including gas transported, would have increased approximately 1.9 percent in 1994. The average use per residential gas customer, when adjusted for normal weather conditions, was slightly down in 1994, following a modest decrease in 1993.
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 $44.0 million in 1994 after increasing $40.2 million in 1993. These increases were driven by higher gas purchased for resale costs in each comparison period. The increases in operating expenses were mitigated by the Company's continuing efforts to curtail increases in maintenance and other operation expenses. Operating expenses are summarized in the table titled Operating Expenses.
OPERATING EXPENSES
- --------------------------------------------------------------------------------
INCREASE OR (DECREASE) FROM PRIOR YEAR
(Thousands of Dollars) 1994 1993
ENERGY COSTS - ELECTRIC. For both comparison periods, 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. The average cost of coal and nuclear fuel decreased in 1994 over 1993.
The Company purchases electric power to supplement its own generation when needed to meet load or reserve requirements, and when such power is available at a cost lower than the Company's production cost. For both comparison periods, the increase in purchased electricity expense was primarily caused by an increase in kilowatt-hours purchased. Average rates for purchased electricity declined in 1994 and in 1993.
ENERGY SUPPLY AND COSTS - GAS. As a result of the implementation of FERC Order 636, and the commencement of operation of Empire, the Company now purchases all of its required gas supply directly from numerous producers and marketers under contracts containing varying terms and conditions. The Company holds firm transportation capacity on ten 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.
The Company acquires gas supply and transportation capacity based on its requirements to meet peak loads which generally occur in the winter months. With Empire going on-line, the Company's gas supply and transportation capacity have also
been enhanced and increased. The Company expects to have excess gas and transportation capacity at various times throughout the year which it will attempt to sell separately or bundled as a package to customers outside the Company's franchise area. The Company is also able to mitigate transportation costs via the capacity release market. To what extent the Company can successfully achieve the assignment or sale of any excess gas and/or transportation capacity, or at what price, cannot be determined at the present time.
As a result of the restructuring of the gas transportation industry by FERC and related decisions, there will be a number of changes in this aspect of the Company's business over the next several years. These changes will require the Company to pay a share of certain transition costs incurred by the pipelines as a result of the FERC-ordered industry 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 $44 and $52 million. A substantial portion of such costs will be on the CNG system of which approximately $27 million was billed to the Company in December 1993 and subsequently paid by the Company. The Company has entered into a $30 million credit agreement with a domestic bank to provide funds for the Company's transition cost liability to CNG. At December 31, 1994 the Company had $18.7 million of borrowings outstanding under the credit agreement. The Company has begun collecting those costs through the Gas Clause Adjustment in its rates.
It was primarily an increase in average purchased gas rates that pushed up the cost of gas purchased for resale for both comparison periods. These higher rates reflect, in part, increased demand charges and newly assessable gas service restructuring charges as a result of FERC Order 636. In contrast to 1993, a decrease in the volume of gas purchased for resale helped to mitigate the overall increase in purchased gas expense in 1994.
A reconciliation of gas costs incurred and gas costs billed to customers is done annually, as of August 31, and the excess or deficiency is refunded to or recovered from customers during a subsequent period. In October 1994 the Company submitted to the PSC its annual reconciliation providing for recovery of $24 million of deferred gas costs, which was substantially higher than in previous years due to the factors mentioned above.
The Staff of the PSC has reviewed the Company's application for recovery of these deferred costs and various other parties requested that the PSC conduct hearings to determine whether and on what terms the deferral should be recovered. On December 19, 1994 the PSC instituted a proceeding to review the Company's practices regarding acquisition of pipeline capacity, the deferred costs of the capacity and the Company's recovery of those costs. The costs included in the
deferral have ordinarily been recovered in the past and the Company believes that they should be recovered in this instance; however, it is possible that with respect to these costs, the PSC may not recognize all of them in rates. If that were to occur, the Company would be compelled to discontinue deferring and recovering costs above the allowed amount, and would recognize the disallowed costs as they were incurred as a charge against earnings. In addition, in a more adverse decision, the PSC could order the Company to refund a portion of such costs previously collected from ratepayers. Pending the conclusion of the proceeding, the PSC directed the Company to recover FERC Order 636 transition costs over a five-year period and all other unrecovered gas costs over 18 months.
As an interim measure, on February 1, 1995, the PSC directed the Company to remove from existing rates $16 million of gas revenues representing a portion of the costs attributable to excess capacity over the remaining term of the contracts. Prospective capacity release credits obtained by the Company are to be used to offset such amounts. These deferred costs are subject to recovery by the Company from customers, with interest, to the extent the Company's actions are found prudent.
The Company cannot predict to what extent the deferred costs described above would be recoverable in rates.
The Company's purchased gas expense charged to customers will be higher during the 1994-95 heating season for the reasons described above.
OPERATING EXPENSES, EXCLUDING FUEL. After rising approximately $8.8 million in 1993, the growth in other operation expenses remained flat in 1994, a direct result of the Company's cost control efforts and workforce reduction programs. For 1994, higher costs for the Company's demand side management program, claims, and uncollectibles were offset by lower payroll and employee welfare costs due to employee reductions and reduced expenses for contractors and consultants. The change in other operation expenses for the 1993 comparison period reflects primarily increased payroll costs and demand side management expenses partially offset by lower fire and liability insurance costs, transportation, materials and supplies, and legal expense.
Statement of Financial Accounting Standards 112 (SFAS-112), "Employees' Accounting for Postemployment Benefits", was adopted by the Company during the first quarter of 1994. SFAS-112 requires the Company to recognize the obligation to provide postemployment benefits to former or inactive employees after employment but before retirement. The additional postemployment obligation at the time of the accounting change was approximately $11 million and is being deferred on the Balance Sheet. The Company anticipates filing with the PSC for recovery of the incremental expenses as the result of the adoption of SFAS-112.
Statement of Financial Accounting Standards 115 (SFAS-115), "Accounting for Certain Investments in Debt and
Equity Securities" was also adopted by the Company in the first quarter of 1994 and requires that debt and equity securities not held to maturity or held for trading purposes be recorded at fair value with unrealized gains and losses excluded from earnings and recorded as a separate component of shareholders' equity. The Company's accounting policy, as prescribed by the PSC, with respect to its nuclear decommissioning trusts is to reflect the trusts' assets at market value and reflect unrealized gains and losses as a change in the corresponding accrued decommissioning liability.
Lower maintenance expense in both comparison periods reflects reduced payroll and contractor costs.
Despite an increase in depreciable plant in both comparison periods, depreciation declined moderately in 1993 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. For the 1994 comparison period, the higher depreciation expense reflects the increase in depreciable plant.
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 increased property tax rates and generally higher property assessments. The 1994 comparison period also reflects certain assessments for prior years' taxes.
During the first quarter of 1993, the Company adopted SFAS-109 entitled "Accounting for Income Taxes" issued by the FASB in February 1992. The Company's adoption of SFAS-109 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. In 1993, the Company adjusted it's tax reserve balances to reflect this new rate. Such adjustment had no material effect on the Company's financial condition or results of operations.
OTHER STATEMENT OF INCOME ITEMS
Variations in non-operating Federal income tax reflect mainly accounting adjustments related to retirement enhancement programs (see Earnings Summary), regulatory disallowances, and employee performance incentive programs (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 and the third quarter of 1994. These programs are discussed under Earnings Summary.
Recorded under the caption Regulatory Disallowances is the recognition of the 1992 PSC order related to a March 1991 ice storm, and a 1993 settlement with the PSC, as supplemented in 1994, regarding certain 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. Other--Net Income and Deductions for 1993 and 1994 results mainly from the recognition of employee performance incentive programs in each of those years. These programs recognize employees' achievements in meeting corporate goals and reducing expenses. For the 1994 comparison period, Other--Net Income and Deductions also reflects higher miscellaneous interest revenues.
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 1992-1994. The average short-term debt outstanding decreased in 1993 and 1994.
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, 1994.
Consolidated Balance sheets at December 31, 1994 and 1993.
Consolidated Statement of Cash Flows for each of the three years ended December 31, 1994.
Notes to Consolidated Financial Statements.
Financial Statement Schedules -
The following Financial Statement Schedule is 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 II - Valuation and Qualifying Accounts
B. Supplementary Data
Interim Financial Data.
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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 1 to the financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" in 1994.
PRICE WATERHOUSE LLP
Rochester, New York January 20, 1995 (except for Note 10, as to which the date is February 1, 1995)
Consolidated Statement of Retained Earnings
The accompanying notes are an integral part of the financial statements.
* Reclassified for comparative purposes. The accompanying notes are an integral part of the financial statements.
* Reclassified for comparative purposes. The accompanying notes are an integral part of the financial statements.
The accompanying notes are an integral part of the financial statements.
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 ratemaking and accounting practices and policies of the PSC.
Energyline Corporation, which is a wholly-owned subsidiary, 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. 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% of the total construction cost and initial operating expenses. Energyline is obligated to pay its 20% share of the balance outstanding subject to a maximum commitment of $9.7 million under the credit agreement. Excluding the loan commitment, at December 31, 1994 the Company had invested a net amount of $10.3 million in Energyline.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries Roxdel and Energyline. All intercompany balances and transactions have been eliminated.
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% 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.
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. Beginning July 1994 through December 31, 1994, $7.3 million was recoverable from customers. The company is not currently recognizing ERAM amounts as part of income. The ultimate recognition, if any, will be determined based on a filing with the PSC during 1995.
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 applies only if the actual heating degree days are lower than 97.5% or higher than 102.5% of the normal heating degree days. Weather normalization adjustments lowered gas revenues in 1994 and 1993 by approximately $1.25 million and $1.2 million respectively. Adjustments will continue through June 1996 in accordance with the 1993 multi- year rate settlement agreement for weather which is colder than normal (also see Note 10).
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 period.
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% per annum of average depreciable property in 1994, 1993, and 1992.
FERC ORDER 636. Under this order, gas supply and pipeline companies are allowed to pass restructuring and transition costs associated with the implementation of the order on to their customers. The Company, as a customer, has estimated total costs to range between $44 and $52 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 $33.7 million of these costs were paid to various suppliers, of which $15 million has 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 Consolidated 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 ranged from 3.9% to 7.1% during the three-year period ended December 31, 1994.
The Company did not accrue 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. Statement of Financial Accounting Standards (SFAS) 109, Accounting for Income Taxes, was adopted by the Company during the first quarter of 1993 (see Note 2).
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 Financial Accounting Standards Board 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.
POSTEMPLOYMENT BENEFITS. SFAS-112, "Employers ' Accounting for Postemployment Benefits", was adopted by the Company during the first quarter of 1994. SFAS- 112 requires the Company to recognize the obligation to provide postemployment benefits to former or inactive employees after employment but before retirement. The additional postemployment obligation at the time of the accounting change was approximately $11 million and is being deferred on the balance sheet.
INVESTMENTS IN DEBT AND EQUITY SECURITIES. SFAS-115, "Accounting for Certain Investments in Debt and Equity Securities" was adopted by the Company in the first quarter 1994 and requires that debt and equity securities not held to maturity or held for trading purposes be recorded at fair value with unrealized gains and losses excluded from earnings and recorded as a separate component of shareholders' equity. The Company's accounting policy, as prescribed by the PSC, with respect to its nuclear decommissioning trusts is to reflect the trusts' assets at market value and reflect unrealized gains and losses as a change in the corresponding accrued decommissioning liability.
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.
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 Consolidated 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:
The Company adopted SFAS-109 "Accounting for Income Taxes" in 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 and 1994 was $241 million and $206 million, respectively. 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 1993 the statutory income tax rate was 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.
As of December 31, 1994, the regulatory asset recognized by the Company as a result of adopting SFAS-109 is attributed to $184 million in depreciation, $21 million to property taxes, $18 million of deferred finance charges - Nine Mile Two and $3 million of Miscellaneous items offset by $18 million attributed to investment tax credits and $2 million to revenue taxes.
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 $43.3 million pension plan curtailment charge. *** Includes $9.2 million pension plan curtailment charge.
During 1994, the Company offered to its employees a Temporary Retirement Enhancement Program (TREP 3). A total of 399 employees elected to participate in TREP 3 resulting in a net curtailment charge of $43.3 million including $71.1 million cost of the enhanced benefit offset by a curtailment gain of $27.8 million. In connection with the curtailment, the Company revalued the projected benefit obligation as of September 30, 1994 utilizing the then current discount rate of 8.25%.
The projected benefit obligation at December 31, 1994, September 30, 1994 and December 31, 1993 assumed discount rates of 8.50%, 8.25%, and 7.25%, respectively and long-term rate of increase in future compensation levels of 6.00%. The assumed long-term rate of return on plan assets was 8.50%. 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 1994 and 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 1994, the health care benefit consisted of a contribution of up to $193 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 as the benefit becomes due.
The plans' funded status reconciled with the Company's balance sheet is as follows:
The Accumulated Postretirement Benefit Obligation at December 31, 1994 and 1993 assumed discount rates of 8.50% and 7.25%, respectively and long-term rate of increase in future compensation levels of 6 percent.
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 Consolidated Statement of Income.
(a) Excludes cash, unamortized debt expense and other common items.
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 Consolidated 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 include disallowed costs of $374.3 million. Such costs, net of income tax effects, were previously written off in 1987 and 1989.
NOTE 6. LONG TERM DEBT
(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 the 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 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 1993 and 1994 requirements were met by certification of additional property.
On February 15, 1994 the Company redeemed $2.75 million principal amount of its First Mortgage 10.95% Bonds, Series FF, pursuant to a sinking fund provision. On June 15, 1994 the Company redeemed all of its outstanding $15 million principal amount of First Mortgage 13 7/8% Bonds, Series JJ, due June 15, 1999. Of the $15 million total, $2.5 million was redeemed through a mandatory sinking fund provision, and the remaining $12.5 million was redeemed at the Company's option.
There are no sinking fund requirements for the next five years. Bond maturities for the next five years are:
(d) 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, 1997. 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 2.82% for 1994, 2.19% for 1993 and 2.74% for 1992. The interest rate will be adjusted monthly unless converted to a fixed rate.
(e) 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, 1997. The annual interest rate was adjusted to 3.10% effective November 15, 1992, to 2.75% effective November 15, 1993 and to 4.40% effective November 15, 1994. 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 1994 of 8.62% for long term debt with similar terms and average maturities (13 years), the fair value of the Company's long term debt outstanding (including Promissory Notes as described above) is approximately $667 million at December 31, 1994.
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.
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
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. The Company redeemed the remaining 180,000 shares on March 1, 1994 at - --------- $100 per share. Capital stock expense of $1.4 million was charged against retained earnings in connection with the redemption of the Series R Preferred Stock in 1994.
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.
SERIES V. The Series V is subject to a mandatory sinking fund sufficient to - --------- redeem on each March 1 beginning in 2004 to and including 2008, 12,500 shares at $100 per share and on March 1, 2009, the balance of the outstanding shares. The Company has the option to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking fund.
Based on an estimated dividend rate at year-end 1994 of 7.50% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (8.65 years), the fair value of the Company's Preferred Stock, subject to mandatory redemption, is approximately $54 million at December 31, 1994.
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.
Note 8. Common Stock
At December 31, 1994, there were 50,000,000 shares of $5 par value Common Stock authorized, of which 37,669,963 were outstanding. No shares of Common Stock are reserved for options, warrants, conversions, or other rights. There were 549,135 shares of Common Stock reserved and unissued for shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan and 138,870 shares reserved and unissued for employees under the RG&E Savings Plus Plan.
Capital stock expense increased in 1992 and 1993 primarily due to expenses associated with the public sale of Common Stock. Redemption of the Company's 8.25% Preferred Stock, Series R, decreased capital stock expense by $0.9 million in 1993 and $1.4 million in 1994.
COMMON STOCK
NOTE 9. SHORT TERM DEBT
At December 31, 1994 and December 31, 1993, the Company had short term debt outstanding of $51.6 million and $68.1 million, respectively. The weighted average interest rate on short term debt outstanding at year end 1994 was 6.01% and was 4.50% for borrowings during the year. For 1993, the weighted average interest rate on short term debt outstanding at year end was 3.46% and was 3.48% for borrowings during the year.
The Company has a $90 million revolving credit agreement for a term of three years. In November of 1994 the Company was granted a one-year extension of the commitment termination date to December 31, 1997. Commitment fees related to this facility amounted to $169,000 per year in 1994, 1993, and 1992.
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, 1994, the Company would be able to incur $37.5 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.
The Company has entered into a Loan and Security Agreement to provide for borrowings up to $30 million for the exclusive purpose of financing Federal Energy Regulatory Commission (FERC) Order 636 transition costs(636 Notes) and up to $20 million as needed from time to time for other working capital needs (Secured Notes). Borrowings under this agreement, which can be renewed annually, are secured by a lien on the Company's accounts receivable. Additional unsecured lines of credit totaling $72 million (Unsecured Notes) are also available from several other banks, at their discretion.
At December 31, 1994, borrowings outstanding were $18.7 million of 636 Notes (recorded on the Balance Sheet as a deferred credit), $19.6 million of Secured Notes, and $32.0 million of Unsecured Notes.
NOTE 10. COMMITMENTS AND OTHER MATTERS
CAPITAL EXPENDITURES.
The Company's 1995 construction expenditures program is currently estimated at $132 million, including $30 million related to replacement of the steam generators at the Ginna Nuclear Plant. The Company has entered into certain commitments for purchase of materials and equipment in connection with that program.
NUCLEAR-RELATED MATTERS.
DECOMMISSIONING TRUST. The Company is 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.
Under accounting procedures approved by the PSC, the Company has collected approximately $70.1 million through December 31, 1994. In connection with the Company's rate settlement completed in August 1993, the PSC approved the collection during the rate year ending June 30, 1995 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 $163.0 million for Ginna and $37.1 million for the Company's 14% share of Nine Mile Two (January 1994 dollars). This estimate is based principally on the application of a Nuclear Regulatory Commission (NRC) formula to determine minimum funding with an additional allowance for removal of non-contaminated structures. 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 believes that decommissioning costs are likely to exceed these estimates but is unable to predict the costs at this time. The Company currently anticipates performing a site specific cost analysis of decommissioning at Ginna during 1995.
The NRC requires reactor licensees to submit funding plans that establish minimum NRC external funding levels for reactor decommissioning. The Company's plan, filed in 1990, consists of an external decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two share. The Company is depositing in an external decommissioning trust the amount of the NRC minimum funding requirement only. Since 1990, the Company has contributed $45.7 million to this fund and, including investment returns, the fund has a balance of $49.0 million as of December 31, 1994. The amount attributed to the allowance for removal of non-contaminated structures is being held in an internal reserve. The internal reserve balance as of December 31, 1994 is $24.4 million.
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.
The Staff of the Securities and Exchange Commission and the Financial Accounting Standards Board are currently studying the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. If current accounting practices for such costs were changed, the annual provisions for decommissioning costs would increase, the estimated cost for decommissioning could be reclassified as a liability rather than as accumulated depreciation and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. If annual decommissioning costs increased, the Company would defer the effects of such costs pending disposition by the Public Service Commission.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. As part of the National Energy Act (Energy 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 $22.1 million, excluding inflation and interest. The first installment of $1.6 million was paid in 1993. The Company made the second of 15 payments for this purpose in April 1994, remitting approximately $1.4 million. The third of 15 payments (approximately $1.5 million) was made in October 1994. A liability has been recognized on the financial statements along with a corresponding regulatory asset. For the two facilities the Company's liability at December 31, 1994 is $18.5 million ($16.9 million as a long-term liability and $1.6 million as a current liability). In October 1993, the Company began recovery of this deferral through its fuel adjustment clause. The Company believes that the full amount of the assessment will be recoverable in rates as described in the Energy Act.
NUCLEAR FUEL DISPOSAL COSTS. The Nuclear Waste Policy Act (Nuclear Waste Act) of 1982, as amended, requires the United States Department of Energy (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 by the Company in June 1985. The Company estimates the fees, including accrued interest, owed to the DOE to be $70.9 million at December 31, 1994. The Company is allowed by the PSC to recover these costs in rates. The estimated fees are classified as a long-term liability and interest is accrued at the current three-month Treasury bill rate, adjusted
quarterly. The Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of one mill ($.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.
SPENT NUCLEAR FUEL LITIGATION. The Nuclear Waste Act obligates the DOE to accept for disposal spent nuclear fuel ("SNF") starting in 1998. Since the mid-1980s the Company and other nuclear plant owners and operators have paid substantial fees to the DOE for the disposal of SNF. DOE has indicated that it may not be in a position to accept SNF in 1998. On June 20, 1994, Northern States Power Company and other owners and operators of nuclear power plants filed suit against DOE and the U.S. in the U.S. Court of Appeals for the District of Columbia Circuit asking for a declaration that DOE is not acting in accordance with law, seeking orders directing DOE to submit to the Court a description of and progress reports on a program to begin acceptance of SNF by 1998, and requesting other relief at appropriate times including an order allowing petitioners to pay fees into an escrow fund rather than to DOE. The Company has joined Northern States and the other petitioners in this litigation. On September 9, 1994, the DOE responded to the petition by filing a motion to dismiss stating that (1) the petition was premature, (2) it has taken no "final" action that would be subject to review and (3) any injury suffered as a result of its failure to begin spent fuel acceptance in 1998 is too speculative. On September 30, 1994, the petitioners filed their opposition to the DOE's motion. On October 14, 1994, DOE filed its reply to the petitioners' opposition.
NUCLEAR FUEL ENRICHMENT SERVICES. The Company has a contract with the United States Enrichment Corporation (USEC), formerly part of the DOE, for nuclear fuel enrichment services which assures provision for 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 and 2004. 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. Negotiations are underway with Urenco, a European enrichment facility to fill all or part of the unfilled enrichment services through 2002. The estimated cost of enrichment services utilized for the next seven years (priced at the most current rates) is expected to be $6 million in 1995 and ranges from $10 million to $13 million every 18 months thereafter.
INSURANCE PROGRAM. The Price-Anderson Act establishes a Federal program insuring against public liability in the event of a nuclear accident at a licensed U.S. reactor. 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 $79.3 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 a surcharge for New York State premium taxes. The Company's interests in two nuclear units could thus expose it to a potential liability for each accident of $90.4 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.
Claims alleging radiation-induced injuries to workers at nuclear reactor sites 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. If an insuring program's losses exceeded its other resources available to pay claims, the Company could be subject to maximum assessments in any one policy year of approximately $5.0 million and $19.5 million in the event of losses under the replacement power and property damage coverages, respectively.
NON-UTILITY GENERATING CONTRACT. Under Federal and New York State laws and regulations, the Company is required to purchase the electrical output of unregulated cogeneration facilities which meet certain criteria (Qualifying Facilities). With the exception of one contract which the Company was compelled by regulators to enter into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts of capacity, the Company has no other long-term obligations to purchase energy from Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the contract with Kamine was negotiated, the Company was required to pay Kamine a price for power that is substantially greater than the Company's own cost of production and other purchases. Since that time the State law mandating a minimum price higher than the Company's own costs has been repealed and PSC estimates of future prices on which the contract was based have declined dramatically.
In September 1994, the Company filed a lawsuit against Kamine seeking to void its contract for the forced purchase of unneeded electricity at above- market prices which would result in substantial cost increases for the Company's customers. The Company estimates that Kamine will owe the Company $400 million by the midpoint of the contract term and if the contract extends to its full 25 year term, the total amount of such overpayments (plus interest) could reach approximately $700 million. Alternatively, the Company sought relief to ensure that its customers would pay no more for the Kamine power than they would pay for power from the Company's other sources of electricity. Kamine answered the Company's complaint, seeking to force the Company to take and pay for power at the above-market rates and claiming damages in an unspecified amount alleged to have been caused by the Company's conduct. The Company is unable to predict the ultimate outcome of this litigation. The Company began receiving test generation from the Kamine facility during the last quarter of 1994. In late December 1994, the Company announced it would no longer be accepting electric power from this facility because it is the Company's position, in addition to other beliefs, that the Kamine facility is no longer a "Qualifying Facility" as specified under Federal regulations.
On January 27, 1995, Kamine initiated a lawsuit against the Company in Federal District Court for the Western District of New York for alleged anti- trust violations by the Company that are based on the same issues that are raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks injunctive relief similar to that requested in Kamine's answer to the Company's lawsuit in New York State Court and damages of $420 million. The Company intends to vigorously defend against this lawsuit, but is unable to predict the outcome at this time.
ENVIRONMENTAL MATTERS.
The following table lists various sites where past waste handling and disposal has or may have occurred that are discussed below:
* orders on consent signed.
COMPANY-OWNED WASTE SITE ACTIVITIES. As part of its commitment to environmental excellence, the Company is conducting proactive Site Investigation and/or Remediation (SIR) efforts at six Company-owned sites where past waste handling and disposal may have occurred. Remediation activities at three of these sites are in various stages of planning or completion and the Company is conducting a program to restore, as necessary to meet environmental standards, the other three sites. The Company anticipates spending $10 million over the next five years on SIR initiatives. Approximately $4.5 million has been provided for in rates through June 1996 ($1.5 million annually) 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.
The Company owns, and was the prior owner or operator of, a number of locations within the vicinity of the Lower Falls of the Genesee River, which had been identified by the New York State Department of Environmental Conservation (NYSDEC). The preceding paragraph includes references to Company owned property in this vicinity. 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 manufactured gas plant sites within the larger, original site once the State of New York adopts new Federal hazardous waste criteria. These manufactured gas plant sites make up three of the six sites referenced in the previous paragraph. There is at least some material at one of the individual manufactured gas plant sites that could trigger relisting. The Company is unable to predict what further listing action NYSDEC may take.
As already mentioned, the Company and its predecessors formerly owned and operated three manufactured gas facilities within the Lower Falls area. In September 1991, the Company initiated a study of
subsurface conditions in the vicinity of retired facilities at its West Station manufactured gas property and has since commenced the removal of soils containing hazardous substances in order to minimize any potential long-term exposure risks. Cleanup efforts have been temporarily suspended while the Company investigates more cost effective remedial technologies. The Company has obtained a research permit (including an air permit) in order to evaluate the burning of material from its West Station property in a coal-fired boiler as a possible disposal strategy. At the second of the three manufactured gas plant sites known as East Station, an interim remedial action was undertaken in late 1993. Groundwater monitoring wells were also installed to assess the quality of the groundwater at this location. The Company has informed the NYSDEC of the results of the samples taken. These results may indicate that some further action may be required.
At the third Lower Falls area property owned by the Company (Front Street) where gas manufacturing took place, a boring placed in Fall 1988 for a sewer system project showed a layer containing a black viscous material. The study of the layer 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 since the report's submittal. The Company is formulating plans for long term management of the site.
Another property owned by the Company where gas manufacturing took place is located in Canandaigua, New York. No residues of the former gas production operations have been discovered there, although investigative work has been limited to date.
On another portion of the Company's property in the Lower Falls (Brewer Street), 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 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 an existing 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 most recent 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 an inactive hazardous waste disposal site. The Company is unable to assess what implications the NYSDEC letter may have for the County's claim against it.
Monitoring wells installed at another Company facility (Brooks Avenue) 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. In December 1994, the NYSDEC granted a permit for the storage of hazardous wastes at this location. Conditions of the permit require additional investigation and corrective action of the hazardous constituents at the site. It is estimated that such investigations may cost approximately $100,000. The cost of corrective actions cannot be determined until investigations are completed.
SUPERFUND AND OTHER SITES. The Company has been or may be associated as a potentially responsible party (PRP) at seven sites not owned by it, but for which the Company has been identified as a PRP. The Company has signed orders on consent for five of these sites and recorded estimated liabilities totaling approximately $0.8 million.
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 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 and has signed a consent order to that effect. The Company, in the lower tier of PRPs, paid its $27,500 share of such cost. Although 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 determine the cost to design and conduct at the site any remedial measures which Federal or state authorities may require, the Company does not expect its costs to exceed $250,000.
On May 21, 1993, the Company was notified by NYSDEC that it was considered a PRP for the Frontier Chemical Pendleton Superfund Site located in Pendleton, NY. The Company has signed, along with other participating parties, an Administrative Order on Consent with NYSDEC. The Order on Consent obligates the parties to implement a work plan and remediate the site. The PRPs have negotiated a work plan for site remediation and have retained a consulting firm to implement the work plan. 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. In April 1994, the Company recorded an estimated liability of $0.7 million for site remediation based on preliminary allocation. Subsequent work has indicated that total is likely to be lower when final.
The Company is involved in the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky and has signed various consent orders to that effect. The Company has contributed to a study of the site and estimates that its share of the cost of investigation and remediation would approximate $205,000.
The Company has been named as a PRP at three other sites and has been associated with another site for which the Company's share of total projected costs is not expected to exceed $120,000. Actual Company expenditures for these sites are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company's share of responsibility for such costs as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several.
FEDERAL CLEAN AIR ACT AMENDMENTS. 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. A range of capital costs between $20 million and $30 million has been estimated for the implementation of several potential scenarios which would enable the Company to meet the foreseeable NOx and sulphur dioxide requirements of the Amendments. These capital costs would be incurred between 1996 and 2000. The Company estimates that it could also incur up to $2.1 million of additional annual operating expenses, excluding fuel, to comply with the Amendments. 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.
GAS COST RECOVERY.
As a result of the restructuring of the gas transportation industry by the Federal Energy Regulatory Commission (FERC) pursuant to Order No. 636 and related decisions, there will be a number of changes in this aspect of the Company's business over the next several years. These changes will require the Company to pay a share of certain transition costs incurred by the pipelines as a result of the FERC-ordered industry 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 $44 and $52 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 and subsequently paid by the Company. The Company has entered into a $30 million credit agreement with a domestic bank to provide funds for the Company's transition cost liability to CNG. At December 31, 1994 the Company had $18.7 million of borrowings outstanding under the credit agreement. The Company has begun collecting those costs through the Gas Clause Adjustment (GCA) in its rates.
The Company is committed to transportation capacity on the Empire State Pipeline (Empire) which commenced operation in November 1993, as well as to upstream pipeline transportation and storage services. The Company also has contractual obligations with CNG and upstream pipelines whereby the Company is subject to charges for transportation and storage services for a period extending to the year 2001. The combined CNG and Empire transportation capacity exceeds the Company's current requirements. This temporary excess has occurred largely due to the Company's initiatives to diversify its supply of gas and the industry changes and increasing competition resulting from the implementation of FERC Order 636.
Under FERC rules, the Company may transfer its excess transportation capacity in the market. The Company is attempting to do that, whenever possible. The Company also 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. While CNG has already secured letters of intent for a substantial portion of such capacity and has ordered compressors and other related equipment associated with the planned modifications to CNG's pipeline, whether and to what extent CNG and/or the Company can successfully negotiate the assignment of the excess capacity, or at what price, cannot be determined at the present time. The ability of CNG to market this capacity may depend on FERC approval of rolled-in (rather than incremental) rate treatment for the CNG new facility costs necessary to serve the letter of intent customers. Several CNG customers have protested CNG's proposed rolled-in rate treatment, arguing that such costs should be borne as incremental by the letter of intent customers. The FERC has issued a preliminary determination on non-environmental issues in which they
concluded that it would be in the public interest to authorize construction and operation of the proposed facilities. Subsequent to the protests filed in response to the proposed rolled-in rate treatment of the facility costs, the Company entered into an amended and restated marketing agreement with CNG. As a result of this agreement and the negotiations surrounding its implementation, CNG is prepared to file a settlement agreement with the FERC, reflecting certain changes in the facilities and their cost. The impact of the changes on rates is favorable to the approval of rolled-in treatment of the facility costs. As a result, the Company anticipates that there will not be significant objection to the settlement, however, the timing of the FERC decision on the settlement and with respect to environmental issues cannot be determined at the present time and that decision is necessary to implement the permanent assignment of the excess capacity. The Company has also exercised its option to postpone for one year the commencement of certain Empire-related transportation service that was scheduled for November 1994. The Company will continue to pursue other options for the release of the capacity.
A reconciliation of gas costs incurred and gas costs billed to customers is done annually, as of August 31, and the excess or deficiency is refunded to or recovered from customers during a subsequent period. In October 1994, the Company submitted to the PSC its annual GCA reconciliation providing for recovery of $24 million of deferred gas costs, which was substantially higher than in previous years principally due to factors mentioned above.
The Staff of the PSC has reviewed the Company's application for recovery of deferred costs and the Consumer Protection Board, along with certain individuals or groups of ratepayers, has requested that the PSC conduct hearings to determine whether and on what terms the deferral should be recovered. On December 19, 1994, the PSC instituted a proceeding to review the Company's practices regarding acquisition of pipeline capacity, the deferred costs of the capacity and the Company's recovery of those costs. The costs included in the deferral have ordinarily been recovered in the past and the Company believes that they should be recovered in this instance; however, it is possible that with respect to these costs, the PSC may not recognize all of them in rates. If that were to occur, the Company would be compelled to discontinue deferring and recovering costs above the allowed amount, and would recognize the disallowed costs as they were incurred as a charge against earnings. In addition, in a more adverse decision, the PSC could order the Company to refund a portion of such costs previously collected from ratepayers. Pending conclusion of the proceeding, the PSC directed the Company to recover Order 636 transition costs over a five-year period and all other unrecovered gas costs over 18 months.
As an interim measure, on February 1, 1995 the PSC directed the Company to remove from existing rates $16 million of gas revenues representing a portion of the costs attributable to excess capacity over the remaining term of the contracts. Prospective capacity release credits obtained by the Company are to be used to offset such amounts.
These deferred costs are subject to recovery by the Company from customers, with interest, to the extent the Company's actions are found prudent.
The Company cannot predict to what extent the deferred costs described above would be recoverable in rates.
The Company's purchased gas expense charged to customers will be higher during the 1994-95 heating season for the reasons described above. In addition, beginning in January 1995 and continuing until May 1995, the Company elected to discontinue the operation of its weather normalization clause (see Note 1) in circumstances where the weather is warmer than normal because of the unusually mild weather that has been experienced in its service territory and the adverse effects on customer bills. The earnings impact of this decision in 1995 will range between $3.5 and $8.7 million depending on the duration of mild weather for the heating season.
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. Of the total undercharges, $2.3 million had previously been expensed and $5.2 million had been deferred on the Company's balance sheet. In March 1994, the PSC approved a December 1993 settlement among the Company, PSC Staff and another party providing for the recovery in rates of $2.6 million over three years. The Company wrote off $2.0 million of the undercharges as of December 31, 1993, reducing 1993 earnings by four cents per share, net of tax. In April 1994, the Company wrote off an additional $0.6 million reducing 1994 earnings by approximately one cent per share, net of tax. Due to rate increase limitations established for the second year of the rate settlement, the Company is precluded from recovering the undercharges until the third year of the rate settlement, which begins July 1, 1995.
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 is 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 the appeals officers have indicated a decision may be forthcoming on the service year issue in 1995. 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.
The IRS has also completed in 1994 its audit of the Company's Federal income tax returns for 1989 and 1990, which has resulted in a proposed refund of $600,000. Since this refund arises from the contentious issues from the prior audit, the Company has filed a protest with the IRS.
REGULATORY AND STRANDED ASSETS.
Certain costs are deferred and recognized as expenses when they are reflected in rates and recovered from customers as permitted by Statement of Financial Accounting Standard No. 71, "Accounting of the Effects of Certain Types of Regulation". These costs are shown as Regulatory Assets. Such costs arise from the traditional cost-of-service rate setting approach where all prudently incurred costs are recoverable through rates. Deferral of these costs is appropriate while the Company's rates are regulated under a cost-of-service approach.
In a purely competitive pricing approach, such costs might not have been incurred or deferred. Accordingly, if the Company's rate setting were changed from a cost-of-service approach and it was no longer allowed to defer these costs under SFAS 71, certain of these assets may not be fully recoverable.
Below is a summarization of the Regulatory Assets as of December 31, 1994.
- Income Taxes: This amount represents the unrecovered portion of tax benefits from accelerated depreciation and other timing differences which were used to reduce tax expense in past years. The recovery of this deferral is anticipated when the effect of the past deductions reverses in future years.
- Deferred Ice Storm Charges: These costs result from the non-capital storm damage repair costs following the March 1991 ice storm.
- Uranium Enrichment Decommissioning Deferral: This amount is mandated to be paid to DOE over the next 13 years. The Energy Policy Act of 1992 requires utilities to contribute such amounts based on the amount of uranium enriched by DOE for each utility.
- FERC 636 Transition Costs: These costs are payable to gas supply and pipeline companies which are passing various restructuring and other transition costs on to the Company, as ordered by FERC.
- Demand Side Management Costs Deferred: These costs are Demand Side Management costs which relate to programs initiated to increase efficiency with which electricity is used.
- Deferred Fuel Costs - Gas: These costs are recoverable over future years and arise from an annual reconciliation of gas revenues and costs (as described in Note 1).
Stranded assets (or other costs) arise when investments are made in facilities or costs are incurred to serve customers and such costs may not be fully recoverable in rates. Examples include purchase power contracts (i.e., the Kamine contract) or uneconomic generating assets.
Excluding the Kamine contract described above, estimates of stranded asset costs are highly sensitive to the competitive wholesale price assumed in the estimation for electricity. The amount of stranded assets at December 31, 1994, cannot be determined at this time but could be significant.
While the Company currently believes that its regulatory and stranded assets are probable of recovery in rates, industry trends have moved more toward competition, and in a purely competitive environment, it is not clear to what extent, if any, writeoffs of such assets may occur.
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 $21.9 million net-of-tax pension plan curtailment ** 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
Item 9.

Item 9. Changes in and Disagreements with Accountants and Financial Disclosure.
None.
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 18, 1995, 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. Registrant's definitive proxy statement dated March 6, 1995 will be filed with the Securities and Exchange Commission prior to April 30, 1995. The information required in Items 10 through 13 under the headings set forth above is incorporated 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 18, 1995 is not deemed to be filed as part of this Report.
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, 1994
Consolidated Balance Sheets at December 31, 1994 and 1993
Consolidated Statement of Cash Flows for each of the three years ended December 31, 1994
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1994
Schedule II - Valuation and Qualifying Accounts
(a) 3. Exhibits - See List of Exhibits
(b) Reports on Form 8-K:
The Company filed a Form 8-K, dated February 10, 1995 reporting under Item 5. Other Events, information relating to gas cost recovery and also cogeneration contract litigation.
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(THOUSANDS OF DOLLARS)
FOR THE YEAR ENDED DECEMBER 31, 1992
FOR THE YEAR ENDED DECEMBER 31, 1993
FOR THE YEAR ENDED DECEMBER 31, 1994
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, in 1993 was $6,241 and in 1994 was $9,000.
LIST OF EXHIBITS
Exhibit 3-1* - Restated Certificate of Incorporation of Rochester Gas and Electric Corporation under Section 807 of the Business Corporation Law filed with the Secretary of State of the State of New York on June 23, 1992. (Filed in Registration No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 3-2* - Certificate of Amendment of the Certificate of Incorporation of Rochester Gas and Electric Corporation Under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 18, 1994. (Filed as Exhibit 4 in May 1994 on Form 10-Q for the quarter ended March 31, 1994, SEC File No. 1-672.)
Exhibit 3-3* - By-Laws of the Company, as amended to date. (Filed as Exhibit 3-2 in February 1994 on Form 10-K for the year ended December 31, 1993, SEC File No. 1-672-2)
Exhibit 4-1* - Restated Certificate of Incorporation of Rochester Gas and Electric Corporation under Section 807 of the Business Corporation Law filed with the Secretary of State of the State of New York on June 23, 1992. (Filed in Registration No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 4-2* - Certificate of Amendment of the Certificate of Incorporation of Rochester Gas and Electric Corporation Under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 18, 1994. (Filed as Exhibit 4 in May 1994 on Form 10-Q for the quarter ended March 31, 1994, SEC File No. 1-672.)
Exhibit 4-3* - By-Laws of the Company, as amended to date. (Filed as Exhibit 3-2 in February 1994 on Form 10-K for the year ended December 31, 1993, SEC File No. 1-672-2)
Exhibit 4-4* - General Mortgage to Bankers Trust Company, as Trustee, dated September 1, 1918, and supplements thereto, dated March 1, 1921, October 23, 1928, August 1, 1932 and May 1, 1940. (Filed as Exhibit 4-2 in February 1991 on Form 10-K for the year ended December 31, 1990, SEC File No. 1-672-2)
Exhibit 4-5* - Supplemental Indenture, dated as of March 1, 1983 between the Company and Bankers Trust Company, as Trustee (Filed as Exhibit 4-1 on
Form 8-K dated July 15, 1993, SEC File No. 1- 672)
Exhibit 10-1* - Basic Agreement dated as of September 22, 1975 among the Company, Niagara Mohawk Power Corporation, Long Island Lighting Company, New York State Electric & Gas Corporation and Central Hudson Gas & Electric Corporation. (Filed in Registration No. 2-54547, as Exhibit 5-P in October 1975.)
Exhibit 10-2* - Letter amendment modifying Basic Agreement dated September 22, 1975 among the Company, Central Hudson Gas & Electric Corporation, Orange and Rockland Utilities, Inc. and Niagara Mohawk Power Corporation. (Filed in Registration No. 2-56351, as Exhibit 5-R in June 1976.)
Exhibit 10-3 - Agreement dated September 25, 1984 between the Company and the United States Department of Energy, as amended to date.
Exhibit 10-4* - Agreement dated February 5, 1980 between the Company and the Power Authority of the State of New York. (Filed as Exhibit 10-10 in February 1990 on Form 10-K for the year ended December 31, 1989, SEC File No. 1-672-2)
Exhibit 10-5* - Agreement dated March 9, 1990 between the Company and Mellon Bank, N.A. (Filed as Exhibit 10-1 in May 1990 on Form 10-Q for the quarter ended March 31, 1990, SEC File No. 1-672)
Exhibit 10-6* - Basic Agreement dated September 22, 1975 as amended and supplemented between the Company and Niagara Mohawk Power Corporation. (Filed as Exhibit 10-11 in February 1993 on Form 10-K for the year ended December 31, 1992, SEC File No. 1-672-2)
Exhibit 10-7* - Operating Agreement effective January 1, 1993 among the owners of the Nine Mile Point Nuclear Plant Unit No. 2. (Filed as Exhibit 10-12 in February 1993 on Form 10-K for the year ended December 31, 1992, SEC File No. 1-672-2)
(A) Exhibit 10-8* - Rochester Gas and Electric Corporation Deferred Compensation Plan. (Filed as Exhibit 10-14 in February 1994 on Form 10-K for the year ended December 31, 1993, SEC File No. 1-672-2)
(A) Exhibit 10-9 - Rochester Gas and Electric Corporation Executive Incentive Plan, Restatement of January 1, 1994.
(A) Exhibit 10-10 - Rochester Gas and Electric Corporation Long Term Incentive Plan, Restatement of January 1, 1994.
Exhibit 23 - Consent of Price Waterhouse, independent accountants
Exhibit 27 - Financial Date Schedule, pursuant to Item 601(c) of Regulation S-K.
* Incorporated by reference. (A) Denotes executive compensation plans and arrangements.
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.
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 /s/ ROGER W. KOBER ------------------------------------- (Roger W. Kober) (Chairman of the Board, President and Chief Executive Officer)
Date: February 16, 1995
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:
/s/ ROGER W. KOBER Chairman of the Board, February 16, 1995 - ------------------------------ (Roger W. Kober) President and Chief Executive Officer
Principal Financial Officer:
/s/ THOMAS S. RICHARDS Senior Vice President, February 16, 1995 - ------------------------------ (Thomas S. Richards) Corporate Services and General Counsel
Principal Accounting Officer:
/s/ DANIEL J. BAIER Controller February 16, 1995 - ------------------------------ (Daniel J. Baier)
SIGNATURE TITLE DATE
DIRECTORS:
WILLIAM BALDERSTON III Director February 16, 1995 - ---------------------------------- (William Balderston III)
ANGELO J. CHIARELLA Director February 16, 1995 - ---------------------------------- (Angelo J. Chiarella)
ALLAN E. DUGAN Director February 16, 1995 - --------------------------------- (Allan E. Dugan)
WILLIAM F. FOWBLE Director February 16, 1995 - ---------------------------------- (William F. Fowble)
JAY T. HOLMES Director February 16, 1995 - ---------------------------------- (Jay T. Holmes)
ROGER W. KOBER Director February 16, 1995 - ---------------------------------- (Roger W. Kober)
DAVID K. LANIAK Director February 16, 1995 - ---------------------------------- (David K. Laniak)
THEODORE L. LEVINSON Director February 16, 1995 - ---------------------------------- (Theodore L. Levinson)
CONSTANCE M. MITCHELL Director February 16, 1995 - ---------------------------------- (Constance M. Mitchell)
CORNELIUS J. MURPHY Director February 16, 1995 - ---------------------------------- (Cornelius J. Murphy)
ARTHUR M. RICHARDSON Director February 16, 1995 - ---------------------------------- (Arthur M. Richardson)
M. RICHARD ROSE Director February 16, 1995 - ---------------------------------- (M. Richard Rose)