ML17058B772

Annual Rept 1992, for Nmpns,Units 1 & 2

ML17058B772
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1992
From:	Kober R ROCHESTER GAS & ELECTRIC CORP.
To:
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ML17058B768	List: ML17058B767 ML17058B769 ML17058B770 ML17058B771 ML17058B772
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NUDOCS 9305240313
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Text

ROCHESTER GAS AND ELECTRIC CORPORATION ANNUAL REPORT 1992

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The Company supplies electric and gas service wholly within the State of New York, and is engaged in the production, transmission, distribution and sale of these services in a nine-county area centering around the City of Rochester.

The Company's territory, which has a population of approximately 920,000, is well diversified among residential, commercial and indus- Rochester trial customers. In addition to the City of Rochester, which is the third largest city and a major industrial center in the State, it includes a large and prosperous farming area.

(COVER) The cover pictures bursts of light from RG&E's laser show at the recently restored High Falls area'f downtown Rochester. As part of a hydroelectric relicensing community improvement program, RG& E created the spectacular light showin this historic locale.

Rochester's birth and the river's history are displayed on the gorge wall with photo projections, laser lights and special High Falls lighting. Inits series of performances last October, more than 125,000 people viewed the River of Light Program.

(SHOWN LEFT) A lookinto the control room of the laser show at High Falls. All functions of the elaborate visual display are controlled from here.

(SHOWN RIGHT) A look out of the control room.

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[

Statement of Income 31 Statement of Retained Earnings 31'alance Sheet 32 9

Statement of Cash Flows 33 Notes to Financial Statements 34-49 Report of Independent Accountants 49 Report of Management 50

, Interim Financial Data 50 Common Stock and Dividends Selected Financial Data 52-53 0

8 Electric Department Statistics Gas Department Statistics

I llse of 1992 Revenue Dollar Taxes 18C Other Operations 17C Purchased Gas 16C Wages 8 Benefits 15C Oepreclatlon & Amortization 10C Electric Fuel 8 Purchased Electricity 9C Oividends 8t Reinvested Earnings BC Interest Source of 1992 Revenue Dollar Residential (25C Electric, 21C Gas) 46C Commercial (20C Electric, 5C Gas) 25C Industrial (16C Electric, 1C Gas) 17C Other (7C Electric, 2C Gas) 9C Electric Sales to Other Utilities 3C

Highlights Letter,to Shareholders HG&E Partnership Management's Discussion and Analysis 14 New Appointments 30 Financial Reports 31 Directors and Officers Investor Information Inside Back Cover

1992 1991'hange FinanCial Data (Don~ tn Thousands)

Operating revenues: Electric $ 633,808 $ 617,542 i 3 Gas $ 261,724 $ 235,728 11 Operating expenses $ 761,588 $ 728,511 5 Operating income $ 133,944 $ 124,759 7 Net income S 70,439 $ 57,997 21 Earnings applicable to common stock S 62,149 $ 51,034 22 Rate of return on average common equity 9.98% 8.60% 16 Common Stock Data Weighted average number of shares outstanding (thousands) 33,258 31,794 Per common share:

Earnings $ 1.86 $ 1.6t) 16 Dividends $ 1.68 $ 1.62 4 Book Value (year end) $ 18.92 $ 18.41 3 Year-end market price $ 24.50 $ 23.25 5 Operating Data Sales (thousands)

Kilowatt-hours to customers 6,455,986 6,447,377 Kilowatt-hours to other utilities 1,062,738 1,034,370 3 Therms of gas sold and transported 526,443 470,938 12 Customers (year end)

Electric 333,674 331,242 Gas 267,954 264,844 Construction expenditures, less allowance for funds used during construction (thousands) $ 125,205 $ 124,057 1 Employees (year end) 2,702 2;755 (2)

Rochester Gas erat Bcctrie Corporation a

ast year I wrote about our corporate vision to change from the traditional "utility-business-as-usual approach" in managing this company. I talked about "simplification, instilling a new feeling of competitiveness, streamlining of operations, and eliminating layers of bureaucracy." To improve the way we do business, I said our most important short-term goal is to fortify our pledge to customer satisfaction. We want to become partners with our customers. As the partner-ships take place, the balance of our ambi-tious business plan will come into reach.

Roger 0 Koher, Chairman of the Board, President and Chief Execotint Officer We want RG&E to be a leader in the new competitive environment. Revenues were off at mid year. I called for Well, we'e on our way. We met most of expense reductions and asked our people to our 1992 objectives in the new Corporate try to offset what the ice storm write-offand Business Plan. But, to me, that achievement unfavorable weather were taking away. They is not nearly as important or revealing as the came through for us. Their efforts made the reform in management philosophy that is difference. While I and the Executive taking place here. We had talked about Management Team take credit for aggres-breaking out of the obsolescent "utility sively promoting thoughtful change in the mentality" mold. It's no longer talk; we'e way we do business, it was the determination doing it! of RG&E people that really turned things around in 1992.

PROFITABILITY When you think about it, that call to action Let's start with financial performance; was a corporate milestone. You see, we probably your main concern as a share- assumed responsibility within the company holder. Ifyou'e read our 1992 fourth- for unpredictable, adverse events and still quarter and year-end fiscal report you managed to increase shareholder earnings.

already know our reported earnings That management strategy has not too often are up from 1991. That's a good result been applied in the natural monopoly envi-when we consider the write-offfor some ronment of the utilitybusiness.

disallowed costs stemming from the The strategy is consistent with our intent 1991 ice storm and a cool summer that to break away from the old, more vulnerable drew down heavily on air conditioning utilitybusiness mentality. This is a driving electric revenues. force in the new thinking that is moving Rochcarcr Gaa araa Breccia Corporarroo

RGB to the leading edge of utility reform, We'e not the only power company with an ensuring our place in the rapidly shifting IRP, but there is at least one wrinkle that utilitybusiness climate. I think sets us apart. Ifit's unusual for a We are more competitive. We are looking power company to consider embracing for more ways to work with customers who potential competitors in energy supply, then willhave a choice of energy supplier. our IRP is unusual. We are seeking active We are building partnerships with our partnerships with industrial and commercial customers and our regulators to help us run customers in workable energy-producing a solvent business. projects.

RESOURCE PLANNING

...it was the determination of In this report last year I described our RG&Epeople that really turned Corporate Business Plan and its major objec- things around in 1992.

tives. In 1992 we constructed a companion Partnerships with customers may result in landmark plan that is the basis for charting RGkE operating customers'lectric gener-the successful future of our operations. ating or cogenerating equipment. We may Our Integrated Resource Plan gRP) is one become part owners with customers in of the most comprehensive and innovative energy-producing projects or even own the approaches to long-range electric supply whole facility under a contractual relation-strategies. ship with an industrial, commercial or insti-In our IRP we applied exhaustive study tutional customer. Another example is our to the components of our operations. Each partnership in the Empire State Pipeline that of our owned-and-operated electric gener- willoffer an alternative natural gas supply in ating facilities was subjected to intense cost- upstate New York.

benefit analyses based on projected This all has to do with new ways of lifetimes, fuel, operating expenses, capital thinking. To prepare for the new utility envi-costs and environmental considerations. ronment and remain competitive we'e Other potential sources of power were finding ways to do things better. Where other factored in, such as electric load control gas and electric companies may see obsta-through our energy management efforts that cles, we see opportunities. It's all part of our can control energy requirements and fore- commitment to the goals of the Corporate stall power plant construction. Electric Business Plan that center largely on price of power potential from cogenerators in the product, customer satisfaction and financial private sector was calculated as well. reward for shareholders.

After closely examining all the individual pieces, we assembled more than a dozen WHERE DO WE DRAW THE LINE?

comprehensive scenarios. The idea was to In line with our departure from traditional minimize costs to the customer while utility thinking, we are taking a critical look providing an attractive rate of return for at the components of our business. Ifa investors and producing environmental component is shown not to be competitive benefits for the communities. We'e saying we willdo one of two things. Either we will "that's being competitive!" make that operation competitive, or we'l get Roeheeeee Gee ood Becuie Cceteeeeioo

rid of it. The principle is simple; ifa maintenance and save our customers unit can't continue to contribute to a $ 30 million by the year 2009.

company's success, it's no longer an asset; Applying the criterion of insisting that an it's a liability. You keep assets and get asset remain an asset, we decided to rid of liabilities. replace the steam generators. Preliminary work began this year with actual replace-CASE IN POINT ment scheduled for 1996. The project Our Ginna nuclear power plant is more willcost $ 115 million over four years.

than 20 years old. It has served our Here's some further evidence of our customers well since it first went into redirected thinking. Our contracts for the commercial operation in 1970, economically steam generator replacement call for the and competitively producing half of our contractors to absorb any cost overruns, customers'lectric power needs. I said and set incentives to complete the job on h our IRP closely studied the useful futures schedule. That's become the corporate of our power plants. The IRP examined policy in dealing with vendors. We'e the remaining operating life of the Ginna running our place like a business and we plant to the expiration of its license in the expect the same from our suppliers.

year 2009.

ONE-STOP SHOPPING The strategy is consistent with Customer satisfaction is at the root of our ourintent to break away from the business reform at RGAE. In 1992, we oM, more vulnerable utility further obligated our corporate culture to business mentality... improve customer service. Customer contact Three options were open for the Ginna training programs have been intensified.

plant. One was to shut the plant down. A customer satisfaction communications Another was to continue to operate the plant program was started so that employees can with the existing and aging steam generators track measurable results. We look for better until 2009 at reduced efficiencies. Replacing ways to accommodate our customers the steam generators was the third. residential, commercial, industrial, institu-No scenario showed any benefit for the tional and municipal alike.

customers in shutting the plant down, so We ask ourselves tough questions. Why, that option was set aside. Continuing to for example, should it be that a gas and operate the plant with the original steam electric company performs customer generators showed, under close examination, services on its own schedule? How about that there would be no cost saving, and that thinking about the customer's schedule and declining generating capacity would likely the customer's convenience? And, why require replacement power from fossil-fired should it be that a customer sometimes has stations with attending air-quality impact. to make several calls or be shuffled from one In contrast, replacement of the steam genera- service department to another to get what tors could restore declining electric capacity they want? And, where is it written that our at the plant, better ensure reliability, reduce connection with our customers ends at the planned shutdowns for refueling and meter? We have to minimize what has to be

done to serve customers and offer better Management Team reporting directly to me.

ways for customers to do business with us. This group of executives represents a depar-Here's one thing we came up with. We'e ture from the more traditionally narrow designing a customer service concept that scope of utility management in the old

'we call "One-Stop Shopping." A new orga- marketplace that was free from competition.

nizational structure, drawn from existing It is a team concept in which the members departments and personnel, is being set into have accepted a willingness to change place so that an RG&E customer can always business operations; to constantly reinvent make just one call or visit us and get their the way we do business. We believe good business taken care right there and then. performance breeds good business, and we Our One-Stop Shopping plan starts this Where other gas and electric year. We have leased a commercial complex in Rochester that willhouse the One-Stop companies may see obstacles, resources under one roof. We think meshing ve see opportllnities.

the components of customer service into a believe we'e on the way to becoming a gas new structure at a common location will and electric company that willflourish in the produce impressive results. The new facility new world of utility operations. To sum up is expected to be fully staffed and functional our real success in 1992, I say this. "In 1992 this year. RG&E got hold of its future."

And, as for the immediate future as we see WHERE IT'S ALL GOING it, we are responding to three critical areas in This business is changing fast, and we'e our business. We willincrease customer trying to place RG&E in the best position satisfaction, become more cost competitive, to take advantage of the opportunities out and we willgrow this business.

there. Innovation, action and employee In the theme section of this report that commitment are key to our progress. follows this letter we describe and illustrate We'e separating ourselves from the old some progress in energy management and utilitybusiness that too often relied on regu- employee achievement that is putting us in lators to help cover costs and not often the lead of the changing gas and electric enough on effective, strategic thinking. We business. Following the theme section is our are moving beyond regulation so that we Management's Discussion and Analysis willbecome what we plan to do, not what report where you'l find our 1992 operations we'e told to do. and results covered in detail.

Our new thinking is demonstrated by the proposed three-year rate settlement agree-ment before the Public Service Commission.

The proposed agreement achieves the objec-(ul /

tive ofjoining the interests of the company Roger W. Kober and our customers by improving ser vice and Chairman of the Board, controlling costs. President and To help shape RG&E for the future, Chief Executive Officer I established a nine-member Executive February 3, 1993 Rochester Gaa teat Etectric Corpcratioa

Customer satisfactionis at the core of our vision. Satisfied customers are the best guarantee for a healthy corporate future that advances public acceptance, competitive prices, employee effectiveness and attractive financial performance. Our f993 Corporate Business Plan plainly states the corporate direction.

"Our first priorityis providing as the supplier of choice safe, reliable, environmentally responsible, cost-efficient energy and service to our customers." ~ Customer satisfaction comes from good service. Getting your money's worthis good servicein anybody's book. Mfe're forming partnerships with our customers that willhelp them get the most for their energy dollar.

COMMERCIAL & INDUSTRIAL ase-Hoyt operates a large printing complex in the Rochester area. The company was planning an expansion of the facility but there was some thought on the part of the parent company to relocate it instead. ~ Printing is energy inten-sive with large presses, chiller systems for processes, and tempera-ture and humidity control equip-G ment. After an energy audit, we 0 ~ 1 I made recommendations and r

provided technical support and cash incentives for energy-efficient equip-ment and lighting that are substan-tially cutting Case-Hoyt's energy bills. The reduced costs of operating, due to RGEcE's energy management programs, allow Case-Hoyt to put the savings into other prograiils

'r( I that protect and even create industrial jobs in this area Rochester-based printers, Case-Hoyt Corporation, found substantial energy savings and incentivesin partnership with RG&E. Project engineers from Case-Hoytand RG&Eare seen going over specifications.

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leason Works, a longtime Rochester-based manufacturer of gears and tool and die equipment, received engineering and incentives from RG&E for chillers, motor drives and lighting. Energy savings are substantial here, too.

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A comprehensive RGBEindustrial energy audit of Gleason Works led to greater electric value and savings for this Rochesterindustry.

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ur partnerships with institutional n a smaller scale, a family-customers brought more efficient owned bike repair shop received lighting, motors and special energy- added energy product value from efficient equipment to many schools us in the form of improved, such as Greece Athena High School energy-efficient lighting. More pictured in this report. At Greece than 2,000 commercial and Athena RG&E provided engineering industrial customers benefited and incentives for state-of-the-art, from RGBs energy utilization natural-gas-fueled equipment that programs in 1992.

offers cost-saving building air condi-tioning while heating the school's swimming pool.

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C'amily-owned bike shop, Bicycle Country, found better lighting and energy efficiencyin partnership with RG&E.

Greece Athena High School found energy savings with a natural-gas-fueled chiller that helps air condition the schoolin one mode while heating the poolin another. RGBE formed energy parlnerships with many schools andinstitutionsin 1992.

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RESIDENTIAL any households harbor an old water heaters. More than 1,000 second refrigerator operating in the residential customers took basement or garage. The older advantage of these offers last year.

models are neither energy efficient ~ In all, energy partnerships with nor often used for much. People customers are producing annual hang on to them because it's not energy savings of 69,745,000 easy to get rid of them. You have to kilowatt-hours. That's enough elec-pay a company to pick them up and tricity to power 10,000 homes for a dispose of them in an environmen- year. And, that's better value for our tally acceptable manner. ~ In an customers'nergy dollar, a key part advertising campaign we call these of customer service, and another second refrigerators "energy hogs," step forward in controlling the G

and we offer our residential electric higher costs of energy. FRIG I DAIRE I~)I 4 MADC ONLY DY OCNCOAL MOSOCS customers an easy way to get rid of them. We'l have them removed at no cost and even leave a $ 50 U.S.

Savings Bond behind as an added incentive. ~ Our contractor col-lects the refrigerators and disposes of them in an environmentally approved manner. As of yew-end, more than 7,000 second refrig-erators were collected. ~ We'e offering rebate incentives for customers to shift from electric to gas appliances. Qualifying electric customers can get anywhere from i'

$ 140 to $ 220 back on the purchase .7 of certain gas appliances such as water heaters, dryers and ranges.

Last year, 2,573 customers took 4-Residential electric advantage of the offers. ~ We are customers take giving rebates for qualifying high- advantage ofincentives r efficiency central air conditioning to switch from electric I appliances to gas systems, heat pumps and electric appliances. Picturedis a customer whois switching from electric coi% to gas burners.

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IDEAS THAT ARE PAYING OFF ooking for better ways to do strength and helps maintain steam for a sleeving mechanism that cuts things is another key to success. generator efficiency. In that the time technicians spend inside Our Employee Suggestion Program process, technicians enter the the steam generators, increasing offers a formal channel where steam generators to operate their productive time on the job.

employees can contribute ideas sleeving equipment. They are They fabricated the tool in an that may reduce costs and improve exposed to very low levels of RG&E machine shop.

productivity. While working on a radiation. The exposure is closely ~ Another idea is scheduled refueling, maintenance monitored, and as workers saving nearly $ 70,000.

and inspection outage at the Ginna approach the conservative, safe limit A few electric substa-nuclear power plant, some RG&E of accumulated dose, they have to tion people thought people thought of a way to improve be replaced. ~ Three inventive they could make the steam generator tube sleeving RG&E employees working at the barrier board gaskets process. Sleeving restores tube plant came up with a special fitting right at RG&E rather than ordering them from a supplier. These gaskets, costing more gC than $ 3,500 apiece, are used in large substation transform-ers. Their thinking proved right when they showed that the gaskets could be produced by skilled workers at RG&E for less than

$ 100 each. ~ Cash awards in 1992 ranged from the $ 50 mini-mum to the $ 10,000 maximum for a total payout of $ 85,173. The l~

1 ideas adopted are saving the II company more than $ 500,000 a year. And 1993 is off to a great start with an employee idea that can potentially save the company

$ 230,000 a year by compressing a five-day training and qualification program into three days. ~ Better energy values for our customers, and better ways of doing things are moving us along well in our goal of improved customer satisfaction as their energy supplier of choice.

These RG& E employees thought there may be a better way to produce special substation gaskets. Kevin Sullivan(leftjand JimSuterfounda way that already saved the company

$ 70,000. (above)

RG&E's Sharon Eckert restructured a five-day training and qualification program for nuclear plant contractors to take placeinjust three days, producing a potential annual savings of more than $200,000. (left)

Imaginative RG&Eemployees broughtanidea fora special steam generator maintenance tool to lifein a company machine shop. Pictured are Lauren Blood(leftJ and Dick CantwelL Tom May (not pictured j was the thirdin this team of inventors. (page 12)

he following is Management's assessment which is a long-range plan used to examine of significant factors which have affected options for the future with regard to gener-the Company's financial condition and ating resources and alternative methods of operating results. meeting electric capacity requirements. The plan covers a 15-year period, beginning in 1992, and provides current strategies and Liquidity and Capital Resources alternatives for meeting the Company's customers'nergy requirements in a During 1992 cash flow from operations, changing business and technological envi-together with proceeds from external ronment. The IRP takes into account antici-financing activity (see Statement of Cash pated capacity requirements and available Flows, page 33) provided the funds for resource options, as well as factors such as construction expenditures and the retirement reliability, price of product, public accep-and refinancing of long-term debt. Addi- tance, financial integrity, environmental tional external financing during 1993 is issues, the competitive marketplace, demand anticipated by the Company to satisfy capital side management and potential new requirements, including security maturities technologies.

and sinking fund obligations. One result of the IRP was the decision Projected Capital and Other Requirements. made by the Company in December 1992 to replace the two steam generators at the Ginna The Company continues to make gener- nuclear plant in 1996. Like similar plants, the ating plant modifications and its construction Ginna nuclear plant has experienced degra-program focuses on the need to serve new dation in some of the tubes that make up customers, to provide for the replacement of each steam generator. About 30 percent of obsolete or inefficient utility property and to these tubes have required repair. In addition, modify facilities consistent with the most a chemical buildup in some of the tubes has current environmental and safety regulations. reduced their heat transfer capability. Both Nuclear plant expenditures to meet the conditions would continue to erode the Company's commitment to maintain a high plant's performance ifthe existing steam level of nuclear safety and performance and generators were left in place. Installation of to satisfy regulatory requirements and new steam generators was the most cost-industry standards are reflected in its effective, reliable and environmentally projected construction program. Construction compatible option for the plant evaluated as requirements also include additional expen- part of the IRP. The new steam generators ditures to be made at the Company's fossil- should result in reduced maintenance costs fueled and hydro generating plants. and help sustain a high level of plant avail-The Company has no current plans to ability. Cost of replacement is estimated at install additional baseload generation. The $ 115 million, with preparation to begin Company has accepted bids and is contin- during the plant's routine 1993 fuel outage.

uing negotiations for the addition of approxi- Outlined below are other results of the IRP mately 24 megawatts of capacity savings to process to date:

be phased-in over the 1993-1995 period and, ~ The plan calls for evaluating the possibility beginning in 1994, expects approximately of using either alternative generation or 55 megawatts of capacity to be supplied by a current generating equipment in partnership cogenerator under contract with the with certain large industrial customers.

Company.

~ The Company will continue to use demand In June 1992 the Company filed with the side management programs to reduce the New York State Public Service Commission need for generating capacity.

(PSC) an Integrated Resource Plan (IRP)

~ The Company will consider phasing out our similar measures as conditions of the FERC coal-fired Beebee Station by the year 2000, renewal licenses, which request the unless it is converted to natural gas and Company intends to oppose. Upon the expi-operated under a partnership arrangement ration of its current extensions of time in with a large customer. which to respond to these conditions, the

~ Two of the four units at the Company's Company plans to request a NYSDEC coal-fired Russell Station are expected to be hearing on them and to negotiate with the converted to burn low-sulfur coal by the NYSDEC for their amicable resolution.

year 2000. The remaining two units will Unless so resolved or vacated through either be converted to burn low-sulfur coal litigation, certain of the conditions would or natural gas, or will be phased out by negate economic operation of one or more that same year. of the stations and may require the Company to abandon efforts to relicense the stations The Company has four hydroelectric so affected.

generating facilities (aggregate capability of Construction is expected to begin in 1993 49 megawatts) operating under licenses on the Empire State Pipeline Project issued by the Federal Energy Regulatory Commission (FERC), all for terms expiring (Empire), an intrastate natural gas pipeline December 31, 1993. In December 1991 the subject to PSC regulation which is proposed to be constructed between Grand Island and Company submitted final license renewal Syracuse, New York. The Company is partic-applications to FERC for these facilities. At the expiration of the licenses, FERC may ipating as an equity owner of Empire, along issue new licenses to the Company or, in the with subsidiaries of Coastal Corporation and alternative, may issue licenses to new Union Enterprises, LTD. In June 1991 the licensees or recommend to the United States PSC authorized the Company to invest up to Congress takeover of the stations by the $ 20 million in Empire subject to certain Federal government. In the event of a conditions, notably that the investment not be takeover of a station by the Federal govern- included in rate base. This project will ment or the issuance of a license to a new provide capacity for up to 50 percent of the licensee, the Federal Power Act (FPA) Company's gas requirements by its second provides that the Company may be compen- year of operation. The construction of sated for the loss of the station in an amount Empire was approved by the PSC in to be determined by FERC. There are no March 1991 and proceedings in October 1991 for State judicial review of the PSC competing applications. After the Company decision were dismissed in July 1992.

provided supplemental information, FERC The Canadian National Energy Board in accepted all four renewal applications for June 1992 granted authorization for filing and commenced its environmental TransCanada, a gas transmission company, to review. As a part of the FERC licensing construct the Blackhorse extension to its process under the FPA, the New York State Department of Environmental Conservation existing main line in order to connect with (NYSDEC) recently issued certifications for Empire at Grand Island. The only remaining each of these four hydro stations. The certifi- major regulatory requirements for Empire cations contain a wide array of conditions, involve Corps of Engineers permits to cross some of which could be difficultand/or navigable waters and federally-regulated expensive for the Company to meet. Several wetlands and that process is underway. An of the conditions appear to be beyond inservice date for Empire of November 1993 NYSDEC's ability to impose, under present is currently anticipated. In 1992 the law, in such certifications. NYSDEC has Company formed a wholly-owned requested FERC to require the same or subsidiary, Energyline Corporation, to Rochccrcr Gac arci Bccaic iArporarioo

acquire its ownership interest in Empire. Nine Mile 7wo nuclear facility, exclusive During 1992 approximately $ 10 million was of fuel costs. Nuclear fuel expenditures of invested by the Company in the Energyline $ 9 million were incurred at Ginna in 1992 Corporation, and up to an additional and expenditures of $ 2 million were made

$ 10 million is expected to be invested during for nuclear fuel at Nine Mile 7wo. On 1993. The Company's share of ownership in March 4, 1992 Nine Mile 7wo was taken out Empire will be dependent upon final project of service for a scheduled refueling outage.

costs and the timing and method of financing Refueling was completed and Nine Mile 7wo selected by the Company. resumed operation on July 4, 1992. The prior The Company's capital expenditures refueling outage occurred from early program is under continuous review and will September 1990 to month-end January 1991.

be revised depending upon the progress of The next refueling outage for Nine Mile 7wo construction projects, customer demand for is anticipated to begin in September 1993.

energy, rate relief, government mandates A refueling outage at Ginna normally occurs and other factors. In addition to its projected annually for a period of approximately 40 to construction requirements, the Company 50 days.

may consider, as conditions warrant, the Electric transmission and distribution redemption or refinancing of certain long- expenditures, as presented in the table below, term securities. totaled $ 35 million in 1992, of which Capital Requirements and Electric $ 30 million was for the upgrading of electric Operations. Electric production plant distribution facilities to meet the energy expenditures in 1992 included $ 35 million requirements of new and existing customers.

of expenditures made at the Company's In 1992 the Company also recognized Ginna nuclear plant and $ 3 million for its $ 3.9 million of transmission and distribution 14 percent share of expenditures at the improvements, a portion of the Company's Capital Requfrements Actual Projected 1990 1991 1992 1993 1994 1995 Type of Facilities (Millions of Dollars)

Electric Property:

Production $ 47 $ 44 $ 47 $ 55 $ 59 $ 60 Transmission and Distribution 31 29 35 32 35 36 Street Lighting and Other 2 2 2 2 2 2 Subtotal 80 75 84 89 96 98 Nuclear Fuel 7 12 11 15 19 14 Total Electric 87 87 95 104 115 112 Gas Property 20 22 19 17 19 24 Common Property 15 13 15 18 12 19 Total 122 122 129 139 146 155 Carrying Costs:

Allowance for Funds Used During Construction (AFUDC) 5 4 2 3 3 4 Deferred Financing Charges Included in Other Income 3 5 3 1 Total Construction Requirements 130 131 134 143 149 159 Securities Redemptions, Maturities and Sinking Fund Obligations* 28 92 160 116 27 9 Total Capital Requirements $ 158 $223 $ 294 $ 259 $ 176 $ 168

<<Excludes prospective refinancings.

cost associated with a severe March 1991 ice Environmental Issues.

storm (see following paragraph).

The production and delivery of energy In early March 1991, the City of results in the emission of pollutants that may Rochester, New York and surrounding be harmful to the environment. In recogni-counties were hit by a severe ice storm, the tion of the Company's responsibility to worst storm in the history of the Company's preserve the quality of the air, water, and service territory. Pending a review at the time land it shares with the community it serves, by the PSC of storm-related costs, as well as the Company has taken a variety of measures the Company's performance during the (e.g., self-auditing, recycling and waste mini-storm, $ 36.4 million of storm-damage repair mization, training of employees in hazardous costs were reflected under deferred debits on waste management) to reduce the potential the Company's December 31, 1991 Balance for environmental damage from its energy Sheet. The Company had estimated that operations and, specifically, to manage and approximately 20 percent of these deferred appropriately dispose of wastes currently costs were related to capital improvements being generated. The Company, nevertheless, (with operating and maintenance expenses has been contacted, along with numerous comprising the balance). In the Company's others, concerning wastes it has sent off-site June 1992 rate decision, the PSC accepted to licensed treatment, storage and disposal the Company's estimated capital improve- sites where authorities have later questioned ments and, accordingly, in 1992 the the handling of such wastes. In such Company commenced recognizing those instances, the Company typically seeks to storm-related capital costs. The final deter- cooperate with those authorities and with mination of the amount to be capitalized has other site users to develop cleanup programs not yet been made by the Company. Addi- and to fairly allocate the associated costs.

tional details of the Company's June 1992 As a part of our commitment to rate decision, including recovery of the 1991 environmental excellence, the Company is storm-damage repair costs, are discussed on conducting voluntary Site Investigation and page 21 under the heading New York State Remediation (SIR) efforts at Company-Public Service Commission (PSC).

owned sites where past contaminant Capital Requirements and Gas handling and disposal may have occurred.

Operations. In the Gas Department, the The purpose of these investigations is to replacement of older cast iron mains with determine ifremedial measures are longer-lasting and less expensive plastic and appropriate. The Company estimates coated steel pipe, the relocation of gas mains spending $ 10 million over the next 5 years for highway improvement, and the installa- on SIR initiatives.

tion of gas services for new load resulted in On November 15, 1990 the Federal Clean construction expenditures of $ 19 million in 1992. Following its construction during 1991 Air Act Amendments of 1990 (Amendments) became law. The Amendments will affect air at a cost of approximately $ 3.3 million, a emissions and quality control measures new 5.0 mile, 24-inch gas pipeline was placed in service in January 1992. This new primarily at the Company's fossil-fueled electric generating facilities (see Note 10 of gas connection has helped the Company the Notes to Financial Statements). A Clean improve supply reliability in the north-western quadrant of the Company's gas Air Act Task Force has been formed within the Company to review compliance with franchise area.

these requirements and is in the process of identifying the optimum mix of control measures and associated potential technology changes that will allow the fossil-fuel based

portion of the generation system to fully to 1992 and the current estimate of capital comply with state and federal environmental requirements through 1995 are summarized requirements. Although work is continuing, in the table on page 16.

the compliance control options have not as For the period 1993 to 1995, the Company yet been determined for the entire fossil- anticipates construction requirements to total fueled system. More detailed compliance approximately $ 450 million. Expenditures decisions are expected to be made by mid- made at the Company's nuclear facilities to 1993. Capital costs, however, between improve operating efficiency and reliability

$ 30 million and $ 50 million (1992 dollars) and to comply with regulatory requirements have currently been estimated for the imple- are a significant component of electric mentation of several potential compliance production plant costs over the period. Such scenarios. Such capital costs would be projected plant costs include an allowance incurred between 1993 and 2000 ifthe by the Company of $ 14 million in 1993, Company elected to go forward with any $ 20 million in 1994 and $ 15 million in 1995 such scenario. The Company currently for the replacement of the steam generators estimates that it could also incur up to at the Ginna nuclear plant.

$ 1.5 million (1992 dollars) of additional In addition to its construc- Projected Capital annual operating expenses, excluding fuel, to tion expenditures, the Repotrements comply with the Amendments. The use of Company has security (millions ol dolloroi scrubbing equipment is not presently being maturities and sinking considered. Likewise, the purchase or sale of fund obligations totaling "emission allowances", as allowed by the $ 152 million over the Amendments, is not currently being consid- three-year period 1993 to ered. The Company anticipates that the costs 1995 as shown by the incurred to comply with the Amendments graph to the right.

will be recoverable through rates based on Excluded from the capital previous rate recovery of environmental requirements table on costs required by governmental authorities. page 16 are expenditures associated with the Redemption of Securities. Empire project and the A $ 75 million first mortgage bond Company's obligations maturity and $ 5 million of sinking fund obli- to the United States gations were a part of the Company's capital Department of Energy for 93 94 95 requirements in 1992. In addition, discre- nuclear waste disposal tionary first mortgage bond redemptions and uranium enrichment 0 Mandatory retirement of securities totaled $ 79.5 million during 1992. decommissioning (see 0 Carrying costs Capital requirements in 1991 included Notes 1 and 10 of the Cl Cash expenditures for construction

$ 28 million of sinking fund redemptions, a Notes to Financial

$ 15 million first mortgage bond maturity, Statements).

and a discretionary first mortgage bond The AFUDC amounts included in the table redemption of $ 49.3 million. on page 16 are the financing costs associated with major projects under construction. This Capital Requirements Summary. carrying cost becomes part of the capitalized The Company's capital program is cost of the related project. The Company designed to maintain reliable and safe begins to earn a cash return on its invest-electric and natural gas service and to meet ment, including this carrying cost, when the future customer service requirements. Capital cost of the project is included in rate base, requirements for the three-year period 1990 which generally is at the time the project Roersessee Gas aan Beeseie eerrssesatess

enters service. In addition to AFUDC, prior to the issue of such securities. As finan-carrying charges include the recognition of cial market conditions warrant, the Company certain customer prepaid financing costs, as may, from time to time, issue securities to further discussed on page 23. permit the early redemption of higher-cost senior securities. The Company's financing liquidity, Financing and Capital Structure. program is under continuous review and may Capital requirements in 1992 were satis- be revised depending upon the level of fied by a combination of long-term debt and construction, financial market conditions, equity issues, internally generated funds, rate relief, cost of capital and other factors.

and short-term borrowings. The Company Financing. Interim financing is available during 1992 continued to from certain domestic banks in the form of take advantage of favorable short-term borrowings under a $90 million Embedded (Annual)

Cost of Long-Term market rates and security revolving credit agreement which continues Debt - Year End $ 67 provisions which allow early until December 31, 1995 and may be redemption to refinance extended annually. Borrowings under this

$ 65

$ 50 million of its higher agreement are secured by a subordinate 8.9'/o cost long-term debt. Such mortgage on substantially all property except

$63 refinancing activity over the cash and accounts receivable. Additional 8.7%

past two years has helped borrowing capability for up to $ 20 million of to reduce the annual cost short-term debt is also available under a 85%

$ 59 a of long-term debt by approx- separate credit agreement with a domestic imately $ 4.5 million and bank. Borrowings under this agreement, ss7 contributed to a drop in which can be renewed annually, are secured 1% the Company's embedded by the Company's accounts receivable. Also,

$ $$ cost of long-term debt from beginning in August 1992, additional unse-7.9'/o 8.6% at year-end 1990 to cured short-term borrowing capacity of up to 7.9% at the end of 1992, as $ 25 million is available from a domestic 7.7'/o illustrated by the graph to bank, at its discretion. At December 31, 1992 90 91 92 the left. Common share- the Company had short-term borrowings holders equity increased outstanding of $ 50.8 million, consisting of during 1992 as the result of a public issue $ 20.8 million of unsecured short-term debt of two million shares of Common Stock and $ 30.0 million of secured short-term debt.

in August. Under provisions of the Company's The Company believes that an average of Certificate of Incorporation (Charter), the approximately 80 percent to 85 percent of the Company may not issue unsecured debt if funds required per year for its 1993 through immediately after such issuance the total 1995 construction program will be generated amount of unsecured debt outstanding would internally and the balance will be obtained exceed 15 percent of the Company's total through the sale of securities and short-term secured indebtedness, capital, and surplus borrowings. The Company also anticipates without the approval of at least a majority of that the sale of securities and short-term the holders of outstanding Preferred Stock.

borrowings will be required to satisfy Under this restriction, the Company as of security maturities and sinking fund obliga- December 31, 1992 was able to issue tions over the three years 1993 through 1995. $ 45.2 million of additional unsecured debt.

Although the Company expects to issue Additional interim financing capability securities during 1993, it is the Company's remains available with secured borrowings intention to utilize its credit agreements to under the Company's credit agreements, as meet any interim external financing needs discussed above.

gi

In March 1992 the Company completed its outstanding First Mortgage 9Ye% Bonds, the public sale of $ 100 million principal Series Z.

amount of First Mortgage 8Y% Bonds, due During 1992 the Company received 2002, Series QQ. Proceeds from this $ 13.3 million to help finance its capital financing were used to repay certain of the expenditures program from the sale of Company's outstanding short-term debt and approximately 585,000 new shares of to finance a portion of the Company's capital Common Stock through its Automatic requirements. Dividend Reinvestment and Stock Purchase In June 1992 the Company refinanced Plan (ADR Plan). New shares issued in 1991

$ 60.5 million of long-term debt when it and 1992,through the ADR Plan were completed a public offering of $ 10.5 million purchased from the Company at a market First Mortgage 6.35% Bonds, Series RR, and price above the book value per share at the

$ 50 million First Mortgage 6Ya% Bonds, time of purchase.

Series SS, both due 2032, in connection with Capital Structure. The Company the issuance of a like amount of New York improved its ratio of common equity to total State Energy Research and Development capitalization during 1992 primarily through Authority Pollution Control Refunding the public sale of Common Stock as Revenue Bonds. The proceeds were used for discussed earlier. The Company's retained the early redemption of $ 10.5 million of First earnings at December 31, 1992 were Mortgage 12N% Bonds, Series HH, and a $ 67.0 million, an increase of approximately

$ 50 million Annual Adjustable Rate $ 5.5 million compared with December 31, Promissory Note. Redemption of this unse- 1991. As discussed on page 21 under the cured Promissory Note has given the heading New York State Public Service Company additional financing flexibility Commission, earnings under the terms of its Charter to issue unse- were reduced in June cured debt. 1992 when the Company In August 1992 the Company issued recorded an $ 8.2 million 2,000,000 shares of new Common Stock. ($ 5.4 million after tax) rhoe The shares were offered to the public at a write-offof ice storm- f45 1,600 price of $ 24 per share. The offering raised related costs. Likewise,

$ 46,460,000 in net proceeds, which were the Company recorded the used to retire short-term debt incurred in the effect of a fuel audit Company's construction program. settlement with the PSC In September 1992 the Company filed a of $ 10.0 million S. y s.o" shelf registration with the Securities and ($ 6.6 million after tax)

Exchange Commission to issue up to in December 1991. As

$ 200 million.of First Mortgage Bonds, shown by the graph to Designated Secured Medium-Term Notes, on the right, common equity 400 terms to be determined at the time of sale. (including retained This registration statement became effective earnings) comprised October 8, 1992 and allows the Company 43.8 percent of the 90 91 92 financing flexibilityregarding the timing of Company's capitalization new issues. The Company plans to use the at December 31, 1992, 0 Common Equity 0 Preferred Stxk net proceeds from the sale of these notes with the balance being G LonpTerm0ebt a portion of its capital requirements to'inance comprised of 8.0 percent 'Excludes amounts due or or to discharge or refund outstanding indebt- preferred equity and redeemab!e within one year.

edness. In January 1993, the Company issued 48.2 percent long-term

$ 30 million of such Medium-Term Notes at debt. At December 31, an annual interest rate of 7.00% to refinance 1992 the Company had

$ 110.3 million of long-term debt due within the Company must absorb 50% to 100% of the one year and $ 6.0 million of preferred stock additional costs. The Settlement. Agreement redeemable within one year which, if provides for a return on equity of 11.50% for included in capitalization, would increase the each rate year, with the Company allowed to long-term debt component of capitalization retain any earnings up to 14.5%. Earnings at 1992 year-end to 51.5 percent, reduce the above 14.5% will be refunded to customers.

preferred equity to 7.9 percent and reduce Should earnings fall below 8.5%, or cash common equity to 40.6 percent of capitaliza- interest coverage fall below 2.2 times, the tion. As presented, these percentages are Settlement Agreement provides that the based on the Company's capitalization inclu- Company can seek relief by petitioning the sive of its long-term liability to the United PSC for a review of the settlement terms.

States Department of Energy (DOE) for The Company is unable to predict whether nuclear waste disposal as explained in Note 1 the Settlement Agreement will be approved of the Notes to Financial Statements. by the PSC. A decision is not likely until

~ i Excluded from the capitalization percentages mid-1993.

is the DOE long-term liability for uranium New York State Public Service enrichment decommissioning. It is the Commission (PSC). Recent PSC rate deci-Company's long-term objective to move to a sions and the Company's pending rate less leveraged capital structure and to requests are summarized in the table on increase the common equity percentage of page 22. The PSC concluded that the July capitalization toward the 45 percent range. 1992 rate increases should, for the twelve To improve its capital structure, the months ending June 1993, allow the Company will consider the redemption of Company to achieve approximately a 2.88 higher-cost senior securities and the issuance times pretax interest coverage, exclusive of of new shares of common stock. AFUDC and the amortization of deferred Nine Mile Two customer prepaid financing Rate Base and Regulatory Policies.

costs, discussed on page 23. In addition The Company is subject to regulation of to the amounts indicated in the table on rates, service, and sale of securities, among page 22, the June 1992 PSC rate order other matters, by the PSC. The Company was authorized the amortization of certain non-granted authority in June 1992 to increase its cash rate moderators (primarily deferred rates for electric and gas service effective Nine Mile Two customer prepaid financing July 1992. These new rates were based on a costs) totaling $ 5.1 million in the Electric forecasted test year for the twelve months Department.

ending June 30, 1993. The Company has In its June 1992 rate decision, the PSC filed a request with the PSC to increase base allowed the Company to defer and recover rates for electric and gas service effective through rates over a period of ten years July 1993. On January 29, 1993 the approximately $ 21.3 million of non-capital Company, the PSC Staff and other interested incremental storm-damage repair costs which parties filed a proposed Settlement the Company had incurred as a result of a Agreement with the PSC. Such Settlement March 1991 ice storm (see Capital Require-Agreement, ifapproved by the PSC, would ments and Electric Operations). The PSC has determine the Company's rates through permitted the unamortized balance of these June 30, 1996 and includes certain incentive allowed costs to be included in rate base. An arrangements providing for both rewards and additional $ 8.2 million of non-capital storm-penalties. Ifoperation and maintenance costs damage costs incurred by the Company were are below projected levels, the Company will disallowed rate recovery by the PSC and the share up to 50% of the savings with its Company accordingly recorded in the second customers. Ifsuch costs exceed projections, quarter of the year a charge to earnings in the RoAcs<a Cur a+i Bccuic Coqeiarion

Hate Increases Granted Amount of Increase Rate of Return on Class of Effective (Annual Basis) Percent Service Date of Increase (000's) Increase Rate Base Equity Electric July 12, 1990 $ 36,059 6.6% 9.91% 12.10%

July 1, 1991 33,133 5.5 9.66 11.70 July 1, 1992 32,220 5.2 9.31 11.00 Gas July 12, 1990 4,250 Increase'uthorized 1.7 9.91 12.10 July 1, 1991 1,148 0.4 9.66 11.70 July 1, 1992 12,316 4.1 9.31 11.00 Pending Requested Amount oflncrease'Annual Rate of Return on Class of Basis) Percent Service Date of Filing (000's) Rate Base Equity Electric July 31, 1992 $ 18,462 2.8% 9.46% 11.50%

Gas July 31, 1992 2,615 1.1 9.46 11.50

• As amended, for the rate year ending June f994, as provided in the proposed Settlement Agreement. For the subsequent two rate years, thc Settlement Agrccment also provides for a return on equity of I 1.50%.

amount of $ 8.2 million, equivalent to with the PSC Staff and other interested approximately $ .17 per share, net of tax. parties regarding this filing, but a final PSC After issuance of the two million shares of decision on this filing may not be made stock in August 1992, the net-of-tax effect before June 1993.

for the year was $ .15 per share. As previ- In March 1991 the PSC issued an order ously discussed, Company-estimated capital regarding a settlement agreement among the costs resulting from the ice storm were Nine Mile Two owners, the PSC Staff and allowed rate recognition by the PSC. other intervenors resolving all open Following the March 1991 ice storm, ratemaking issues with respect to the electric rates which the PSC authorized for construction of the unit and its operation the Company in June 1991 were made through January 19, 1990. Under the provi-subject to a refund of $ 4 million contingent sions of this settlement, a Nine Mile Two upon the filing with the PSC of a revised commercial operation date of April 5, 1988 storm emergency plan. In an order issued was recognized by the PSC with respect to June 10, 1992, the PSC determined that this the rates and accounts of the Company.

plan-filing contingency had been met and Accordingly, final accounting entries that the $ 4 million was no longer subject to reflecting recognition of this agreement in refund. conformity with the Uniform Systems of In late July 1992 the Company filed rate Accounts of the PSC were made in the first requests with the PSC as summarized under quarter of 1991 increasing electric utility the heading "Pending" in the table above. plant together with a corresponding increase The higher rates were requested to cover in accumulated depreciation. Supplemental those increases in capital and operating agreements approved by the PSC in early costs projected for the rate year ending 1992 and 1993, respectively, have estab-June 30, 1994 that are neither adequately lished for each Nine Mile Two owner an provided for in present rates nor expected to allowed level of shared costs for ratemaking be offset by increased revenues from sales. purposes through December 31, 1993.

As discussed earlier, the Company has In a series of rate orders preceding the negotiated a multi-year settlement agreement commercial operation of Nine Mile Two, the

Company was allowed to include certain This legislation changes the Federal regula-Nine Mile Two plant costs in rate base prior tion of utilities in a number of ways. One to commercial operation. AFUDC was not provision of the Energy Act provides that accrued on these amounts. Instead, the United States utilities with nuclear gener-Company accumulated a similarly calculated ating facilities be assessed an annual decon-amount until commercial operation and tamination and decommissioning fee payable recorded it on the Balance Sheet as a to the DOE. This annual fee will be in place deferred credit (liability), with an equivalent for 15 years and could be assessed as early as amount recorded as a deferred debit (asset). 1993. The Company's annual fee is approxi-The deferred credit represents customer mately $ 1.8 million for the Ginna nuclear prepaid financing costs, while the deferred plant and the estimated amount for its debit represents financing cost (or AFUDC). share of Nine Mile Two is approximately The latter is expected to be recovered over $ .1 million. This obligation has been reflected the life of the facility through amortization if on the Company's December 31, 1992 the PSC chooses to utilize these prepaid Balance Sheet, together with a corresponding financing costs to moderate customer rates. deferred debit based on the language of the For the rate year beginning July 1992, the Energy Act. The Company believes it will Company started amortizing $ 2.5 million of receive the ultimate recovery of this deferral these deferred credits to Other Income as through its fuel adjustment clause. The permitted by the PSC's June 1992 rate order. Company is currently reviewing other provi-Amortization of these deferred credits to sions of the Energy Act as they relate to Other Income has aggregated $ 21.4 million the Company.

through December 31, 1992. The June 1992 rate order also authorized the Company to Results of Operations write off $ 2.5 million of deferred and other expenses as an offset to these deferred credit The following financial review identifies balances. In the pending multi-year the causes of significant changes in the Settlement Agreement discussed above, no amounts of revenues and expenses, comparing additional amounts of such deferred credits 1992 to 1991 and 1991 to 1990. The Notes are proposed to be used through the period to Financial Statements on pages 34 to 49 of ending June 30, 1996. this report contain additional information.

Pursuant to an order issued by the PSC in Operating Revenues and Sales.

November 1991, the Company started Compared with a year earlier, operating refunding $ 10 million to its electric revenues rose five percent in 1992 after customers through adjustments to their increasing three percent in 1991. Gains in energy bills over a twelve-month period retail customer electric and gas revenues beginning in January 1992. The PSC order offset a decline in electric revenues from the approved a settlement agreement between the sale of electric energy to other utilities.

PSC Staff and the Company relating to the Customer revenue increases due to rate relief Staff's audit of the Company's fuel procure- were partially offset by lower gas unbilled ment practices. The Company recognized the revenues and the impact of colder weather on settlement agreement in December 1991 and air conditioning usage. Operating revenues accordingly recorded a $ 6.6 million net-of- adjusted to exclude fuel expense were also tax reduction to net income, thereby reducing up in 1992 as shown by the graph on earnings per share by approximately $ .21 for page 24. Details of the revenue changes the fourth quarter of 1991. are presented in the table on page 24.

National Energy Policy Act of 1992. In Unbilled revenues are the estimated October 1992 the National Energy Policy Act revenues attributable to energy which has of 1992 (Energy Act) was signed into law.

been delivered to customers but for which the Notes to Financial Statements, pretax the metered amount has not been read and earnings were increased $ 2.4 million in 1991 recorded on the Company's books. Such and increased $ 4.4 million in 1992, primarily revenues do not enhance the Company's cash reflecting actual experience in both electric position. The Company records monthly fuel costs and generation mix compared with accruals for unbilled revenues. rate assumptions. In addition, beginning in The Company's Statement of September 1990, fuel clause revenues Operating Revenues Less Fuel Expense Income reflects net unbilled include the recovery of margins (revenues (miiiioos or dorrsrs J revenues of $ 5.0 million in less incremental cost of fuel) not currently 1990, $ 2.6 million in 1991, provided for in base rates and which are not ar6 and $ (0.8) million in 1992. collected due to the implementation of the Primarily as a result of the Company's energy efficiency programs seasonal nature of gas (discussed below in this section). For the revenues, unbilled revenues 1992 comparison period, fuel clause reve-will normally be near their nues also reflect a revenue matching adjust-maximum around January and ment resulting from a refund to electric at their minimum near the end customers as described in the last paragraph of June. under the heading New York State Public The Company's fuel clause Service Commission.

provisions currently provide The effect of weather variations on oper-that customers and share- ating revenues is most measurable in the Gas holders will share, generally Department, where revenues from space on an 80%/20% basis, respec- heating customers comprise about 85 to 90 91 92 tively, the benefits and detri- 90 percent of total gas operating revenues.

0 Gas Revenues ments realized from actual Variation in weather conditions can also have 0 Electric Revenues electric fuel costs, generation a meaningful impact on the volume of gas mix, sales of gas to dual-fuel delivered and the revenues derived from the customers and sales of electricity to other transportation of customer-owned gas since utilities compared with PSC-approved a substantial portion of these gas deliveries forecast amounts. As a result of these sharing is ultimately used for spaceheating. As arrangements, discussed further in Note 1 of displayed by the graph to the left on page 25, Operating Reuenues 1rrcrease or (Decrease) from Prior Year Electric Department Gas Deparimenl (Thousands ot Dollars) 1992 1991 1992 1991 Customer Revenues (Estimated) from:

Rate Increases $ 30,108 $ 33,666 $ 4,437 $ 3,106 Unbilled Revenues, Net 2,559 (9,894) (5,943) 7,557 Fuel Clause Adjustments (14,258) 2,236 906 (4,052)

Weather Effects (Heating) 1,636 (204) 20,372 (3,333)

Customer Consumption (7,572) 7,197 8,412 (3,181)

Transportation Gas, Net Effect (6,828) (4,036)

Other 6,864 3,999 4,640 3,171 Total Change in Customer Revenues 19,337 37,000 25,996 (768)

Electric Sales to Other Utilities (3,071) (13,853)

Total Change in Operating Revenues s16,266 S23,1 47 $ 25,996 $ (768)

Raehouor Oas ooo Ekorric Carpororioo

after experiencing unseasonably mild increase in sales to all major customer groups weather during the 1990 and 1991 heating in 1992; but, like 1991, the combined growth seasons, weather in the Company's service in electric sales to commercial and industrial area during 1992 was 3.4 percent colder than customers was limited to approximately one normal and 13.6 percent colder compared percent as these customers continued to feel with 1991. While this cooler weather during the constraints of the national economy.

1992 enhanced gas sales, unseasonably cold Strengthening kilowatt-hour sales of energy summer weather during the year limited in 1992 was the impact of nearly 2,400 new electric energy sales to meet electric customers, which follows the Oegree Day the demand for air conditioning addition of approximately 2,350 customers a Variations From usage, compared with the hot, year earlier.

Normal dry 1991 summer weather Like many other electric utilities, the conditions. Overall, 1991 was Company is encouraging energy efficiency 8.4 percent warmer than through demand side management (DSM) normal, but 3.7 percent cooler programs. Objectives of the DSM programs 4OO than 1990. include increasing the efficiency with which As part of the June 1992 rate electricity is used and shifting electric load mP decision, customers who use from peak to non-peak times, thus helping to gas for spaceheating and save energy and delay the are provided service under need to add new gener- Electric Service Classification No. 1 ating capacity. DSM Market Profile (raoosoods ormwh soldi (primarily residential programs include rebates customers) are subject to for energy-efficient equip- et9 92 a weather normalization ment, audits which focus 9O ass r

9'2 adjustment to reflect the impact on potential techniques e,ooo of variations from normal for saving energy, weather on a billing-cycle consumer information and 0 Cooling Degree month basis for the months of outreach, and design October 1992 through May assistance to encourage Days'May-sept.)

0 Heating Degree Days'Jan..Dec.)

1993, inclusive. The weather energy-efficient new con-

'Each degree ol mean normalization adjustment for a struction. In general, the daily temperature billing-cycle will apply only if Company is being allowed above 65 degreesis considered to be one the actual heating degree days to amortize major DSM 2,000 cooling degree day; are lower than 97.5 percent or program expenditures below65 degreesis considered to be one higher than 102.5 percent of over a five-year period.

heating degree day. the normal heating degree An incentive allowance Normal days. Weather normalization (award) of approximately 9O 91 92 Heating Degree Days 6,713 Cooling Degree Days 63i adjuStmentS 1OWered gaS $ 1.1 million was provided Other Utilities revenues in 1992 by approxi- for in the Company's June H Other Industrial mately $ 1.8 million. 1992 rate decision based Commercial After climbing one percent in 1991, on the Company's DSM 0 Residential growth in kilowatt-hour sales of energy to performance through retail customers was nearly flat in 1992 as December 31, 1991. The reduction in margins illustrated by the graph to the right. Growth (revenues less incremental cost of fuel) in electric energy sales in 1992 was inhibited resulting from the implementation of DSM by the impact of cooler weather during the projects is estimated and is recovered in rates.

summer months on air conditioning usage. Fluctuations in revenues from electric Electric sales to industrial customers led the sales to other utilities are generally related to

the Company's customer energy 1991, while nonresidential sales, including Gas Market Profile requirements, New York Power gas transported, in 1992 would have rmilliooo or raonoo sold ood rroosporrod J Pool energy market and trans- increased approximately 4.0 percent. The mission conditions and the average use per residential gas customer, availability of electric genera- when adjusted for normal weather conditions tion from Company facilities. was up in 1992, following a decrease in art Such revenues in 1992 also 1991. Total therms of gas transported reflect the sale of energy at a increased in 1992 and 1991, primarily as a lower rate per megawatt hour result of higher sales to certain large indus-and the impact of lower contract trial and municipal transportation customers.

sales of energy. A decline in Fluctuations in "Other" customer revenues these contract sales, together shown in the table on page 24 for both with generally lower New York comparison periods is largely the result of Power Pool requirements, led to revenues associated with a New York State lower kilowatt-hour sales to tax enacted in 1991 (see Taxes Charged to other utilities in 1991. Operating Expense), and, variations in The transportation of gas for miscellaneous revenues and consumption 90 91 92 large-volume customers who (billing) days.

0 Transported are able to purchase natural gas 0 Other from sources other than the Operating Expenses.

0 industrial 0 Commercial Company remains an important Compared with the prior year, operating 0 Residential component of the Company's expenses were up 4.5 percent in 1992 marketing mix. Company facili- following a two percent increase in 1991, ties are used to transport this as summarized in the table on page 27 and gas, which amounted to 12.6 million as illustrated by the graph on page 28.

dekatherms in 1992 and 10.9 million Excluding the effect of higher taxes and the dekatherms in 1991. These purchases have 1992 recognition of certain postretirement caused decreases in customer revenues, benefits discussed on page 28, operating as shown in the table on page 24, with expenses were up only 1.4 percent in 1992 offsetting decreases in fuel expenses, but do and a modest one-half percent in 1991.

not adversely affect earnings because trans- Operating expenses were increased approxi-portation customers are billed at rates which, mately $ 1.0 million in 1992 as the Company except for the cost of gas, approximate the began in July to recognize over a ten-year rates charged the Company's other gas period the deferred March 1991 ice storm service customers. Gas supplies transported costs as allowed by the PSC (see New York in this manner are not included in Company State Public Service Commission).

therm sales, depressing reported gas sales to Energy Costs Electric. For the 1992 non-residential customers. comparison period, fuel expense for electric Therms of gas sold and transported, generation was lower by $ 16.7 million due, including unbilled sales, were up in part, to a revenue matching adjustment 11.8 percent in 1992, following a 2.2 per- resulting from a refund to electric customers cent increase in 1991 as illustrated by the as described in the last paragraph under New graph to the upper left. These increases York State Public Service Commission.

reflect, primarily, the effect of weather Although the Company generated less variations on therm sales to customers with electric power in 1992, the decrease in spaceheating. Ifadjusted for normal weather electric fuel expense was more than the conditions, residential gas sales would have decrease in electric generation as the average increased about 2.3 percent in 1992 over cost of coal and nuclear fuel declined. For g

the 1991 comparison period, less generation are available at prices lower than CNG's from the Company's fossil-fueled units was commodity price and 2) the acquisition of largely responsible for the decrease in fuel those short-term supplies would not jeopar-expenses for electric generation. dize the reliability of the Company's long-The Company purchased fewer kilowatt- term supply or unduly increase its cost.

hours of energy in 1992 and 1991 compared Under the contracts with CNG, the Company with the prior year. The variation in has obtained rights to 4.2 million dekatherms purchased electricity expense for both of CNG storage capacity. With underground comparison periods was primarily caused by natural gas storage capability, the Company a fluctuation in the average rates for is in a better position to take advantage of purchased electricity. off-peak season purchases of gas and Energy Costs and Supply Gas. The enhance its supply reliability to serve Company receives gas supply and related projected peak day requirements. Also, in transportation services under a series of connection with the Empire project, addi-contracts with CNG Transmission tional transportation agreements have been Corporation (CNG). These contracts provide entered into with pipelines upstream of for a combination of unbundled services Empire that permit the Company to directly (storage and transmission of Company- access U.S. and Canadian natural gas purchased gas) for approximately 30% of the supplies and storage facilities once Empire Company's annual gas purchases, and becomes operational.

bundled sales services (including gas supply, ln April 1992 FERC issued Order No. 636 storage and transmission) for the remainder with the intention of fostering competition of the Company's annual supplies that will and improving access of customers to gas not otherwise be purchased for transport to supply sources. In essence, FERC Order the Company via the proposed Empire No. 636 "divests" the natural gas pipelines of project (see Projected Capital and Other sole ownership of transportation capacity Requirements). The Company expects that it rights, transfers those capacity rights, in part, will annually purchase a quantity of gas to the pipelines'ustomers, and requires the equal to 25% of the CNG bundled sales pipelines to offer their services so that the service gas supply from other sources under reliability of service associated with gas from short-term contracts when: 1) those supplies any source is equal and terminates the Operating Expenses Increase or (Decrease) from Prior Year (Thousands of Dollars) 1992 1991 Fuel for Electric Generation $ (16,729) $ (11,315)

Purchased Electricity 2,023 (6,581)

Gas Purchased for Resale 11,512 (2,733)

Other Operation 18,184 13,846 Maintenance (2,695) 3,024 Depreciation 478 8,346 Amortization of Other Plant 369 (1,932)

Taxes Charged to Operating Expenses Local, State and Other Taxes 10,603 12,614 Federal Income Tax 9,332 (231)

Total Change in Operating Expenses $ 33,077 8 15,038

pipelines'onopoly in providing Standards Board's (FASB) SFAS-106 for Operating Expenses rrrdrrlrrrrr rd dollars] gas merchant services. The financial reporting purposes. Among other res Company's gas procurement things, SFAS-106 requires accrual account-strategy, as discussed above, has ing for postretirement benefits other than SOO rrs pursued such rights; therefore, pensions. The Company estimates that the FERC Order No. 636 enhances net periodic cost for postretirement benefits, the Company's ability to imple- excluding pensions, will be approximately ment this strategy by estab- $ 7.8 million based on accrual accounting lishing a regulatory basis for its required by SFAS-106. The net periodic rights, rather than requiring it to cost includes approximately $ 2.8 million negotiate for such rights in indi- amortization of the unrecognized transition vidual pipeline rate cases. obligation (the accumulated postretirement The cost of gas purchased for benefit obligation at adoption), currently resale increased in the 1992 estimated at $ 56.4 million to be amortized comparison period primarily over twenty years. The PSC allowed the due to higher residential and Company revenues in rates equal to 90 91 92 commercial spaceheating sales, $ 7.0 million in 1992 in recognition of C3 Depreciation rt reflecting colder weather. In this obligation. The Company has filed a Amortization contrast to 1991, however, when petition with the PSC for deferral accounting Cl Taxes 0 Fuel Expenses lower average rates led to a treatment for the balance of the expense 0 Other Operating 8 drop in the cost of gas to be accrued.

Iitatntenance Costs purchased for resale, a decline Fluctuation of maintenance expense in in 1992 average rates could not both comparison periods was largely offset the effect of the higher volume of gas due to increased activity in 1991 associated required for sales during the year. with electric distribution facilities; and, Operating Expenses, Excluding FueL for the 1992 comparison period, lower Other operation expenses rose over both maintenance expense at nuclear production comparison periods as shown by the table on facilities.

page 27. The recording of certain postretire- Depreciation expense in the 1992 compar-ment benefits other than pensions, as ison period was basically unchanged as the required by Statement of Financial effect of an increase in depreciable plant Accounting Standards No. 106 (SFAS-106) was nearly offset by a decrease in the and discussed in the following paragraph, depreciation related to the Ginna nuclear increased other operation expenses in 1992 plant due to a three-year extension of its by $ 4.9 million. Compared with a year operating license. The amortization of earlier, other operation expenses in 1992 also the Sterling property abandonment was reflect an increase of $ 3.0 million for trans- completed in July 1992. An increase in mission wheeling charges and additional accrued decommissioning expenses and expenses of about $ 1.6 million associated additional depreciable plant caused with the Company's share of Nine Mile depreciation expense to increase in the Two operation expenses. The increase in 1991 comparison period.

other operation expenses for the 1991 Taxes Charged to Operating Expenses.

comparison period primarily resulted from The increase in local, state and other taxes higher payroll costs, increased regulatory for both comparison periods resulted from assessments, and higher transmission increases in revenue taxes. These were wheeling charges. impacted by a one-half percent increase in During the first quarter of 1992, the the New York State gross revenue tax, the Company adopted the Financial Accounting accounting for which began in October 1991

retroactive to January 1, 1991. Also, higher (see page 23) and the 1992 PSC order related assessments and tax rates on property to the March 1991 ice storm (see page 21).

increased these taxes. For the 1991 comparison period, the In February 1992, FASB issued SFAS-109 fluctuation in Other Income is primarily entitled "Accounting for Income Taxes", associated with the amortization of customer superseding SFAS-96. SFAS-109 requires prepaid Nine Mile 7wo financing costs the Company to adjust certain of its deferred which had been deferred, as discussed under tax assets and liabilities to reflect periodic the heading New York State Public Service changes in tax rates. In addition, the Commission. Such non-cash earnings were Company will also be required to provide $ 3.3 million in 1990, $ 4.8 million in 1991, deferred taxes for the effect of tax benefits and $ 2.5 million in 1992. Other income in previously flowed through to the Income 1992 also includes $ 3.5 million of proceeds Statement. The Company will adopt received in settlement of lawsuits filed SFAS-109 in the first quarter of 1993. The against certain contractors involved in the Company has proposed in its current rate construction of the Nine Mile 7wo filing with the PSC that, upon adoption of nuclear plant.

SFAS-109, any charge or credit to earnings Both mandatory and optional redemptions that might result from the change in of certain higher-cost first mortgage bonds accounting method be deferred and subse- have helped to reduce long-term debt quently amortized with carrying charges. expense interest over the three-year period Since the Company's deferred taxes have 1990-1992, despite the issuance of addi-been adjusted for regulatory purposes to tional long-term debt in 1991 and 1992. In the current statutory rate where permissible, 1992, the effect of lower interest rates on the impact of SFAS-109 is believed to be debt expense was partially offset by immaterial. See Note 2 of the Notes to increased short-term borrowings.

Financial Statements for an analysis of Federal income taxes.

Earnings/Summary Other Statement of Income Items Presented on page 30 is a table which summarizes the Company's Common Stock AFUDC variances are generally related to earnings in total and on a per-share basis.

the amount of utility plant under construction As previously explained, Common Stock and not included in rate base. AFUDC levels earnings per share in the second quarter of also reflect decreases in the gross rate to 1992 were reduced by approximately 4.50 percent effective September 1992 from $ .17 per share, net of tax, following earlier rates of 5.50 percent, 7.10 percent, recognition of the disallowance of and 8.60 percent. $ 8.2 million of deferred ice storm-related Variations in non-operating Federal costs. After issuance of the two million income tax reflect mainly June 1992 additional shares of stock in August 1992, accounting adjustments related to the March the net-of-tax effect for the year was 1991 ice storm and a 1991 accounting adjust- $ .15 per share. In the fourth quarter of 1991, ment in connection with the Nine Mile 7wo earnings were reduced by $ .21 per share settlement agreement. when the Company recorded the effects of Recorded under the caption "Other Income the fuel procurement settlement approved by and Deductions" is the recognition of the the PSC as discussed earlier. Also, the 1991 PSC order associated with the Company estimates that a loss of revenues Company's fuel procurement practices as a result of the 1991 ice storm reduced

earnings by $ .07 per share, net of tax, for dividend rate of $ .43 per share payable in calendar year 1991. January 1993. The Company's Charter In December 1991 the Company provides for the payment of dividends on announced a quarterly dividend increase Common Stock out of the surplus net profits from $ .405 to $ .42 per share of Common (retained earnings) of the Company.

Stock payable in January 1992. Accordingly, dividend payments are depen-Subsequently, in December 1992 the dent on future earnings, in addition to finan-Company announced a new quarterly cial requirements and other factors.

Earnings Summary Earnings Shares Earnings tThousands of Dollars) (Thousands) per Share 1992 $ 62,149 33,258 $ 1.86 1991 $ 51,034 31,794 $ 1.60 1990 $ 53,856 31,293 $ 1.72

• Weighted average shares outstanding At the 1992 annual meeting of shareholders in May, Angelo J. Chiarella and Jay T. Holmes were elected to the Company's board of directors.

Angelo J. Chiarellais president and chief Jay T. Holmesis senior vice president executive officer, Midtown Holdings Corp. corporate affairs and secretary of He replaces Theodore J. Altier, former Bausch 8 Lomb Incorporated. He chairman and chief executive officer, replaces William G. vonBerg, executive Altier 8 Sons Shoes, Inc. who served on director, Executive Service Corps of the board for more than 12 years. Rochester, Inc. who served on the board for more than 20 years.

(Thousands of Dollars) Year Ended December 31 1992 1991 1990 Operating Revenues Electric $ 608,267 $ 588,930 $ 551,930 Gas 261,724 '35,728 236,496 869,991 824,658 788,426 Electric sales to other utilities 25,541 28,612 42,465 t

Total Operating Revenues 895,532 853,270 830,891 Dperatlng Expenses Fuel Expenses Fuel for electric generation 48,376 65,105 76,420 Purchased electricity 29,706 27,683 34,264'32,512 Gas purchased for resale 141,291 129,779 Total Fuel Expenses 219,373 222,567 243,196 Operating Revenues Less Fuel Expenses 676,159 . 630,703 587,695 Other Operating Expenses Operations excluding fuel expenses 226,624 208,440 194, 594 Maintenance 62,720 65,415 62,391 Depreciation and amortization 85,028 84,181 77,767 Taxes local, state and other ~ 124,252 113,649 101,035 Federal income tax 43,591 34,259 34,490 Total Other Operating Expenses 542,215 505,944 470,277 Operating Income 133,944 124,759 117,418 Other Income and Deductions Allowance for other funds used during construction 164 675 2,689 Federal income tax 4,195 4,580 2,459 Regulatory disallowances (Note 10) (8,215) (10,000)

Other, net 6,155 6,078 4,062 Total Other Income and Deductions 2,299 1,333 9,210 Income Before Interest Charges 136,243 126,092 126,628 Interest Charges Long term debt 60,810 63,918 64,873 Other, net ~

7,178 7,082 4,593 Allowance for borrowed funds used during construction (2,184) (2,905) (2,719)

Total Interest Charges 65,804 68,095 66,747 Net Income 70,439 57,997 59,88'1 Dividends on Preferred Stock 8,290 6,963 6,025 Earnings Applicable to Common Stock 62,149 $ ~ 51,034 $ 53,856 Weighted Average Nuimber of Shares for Period (000's) 33,258 31,794 31,293 Earnings per Common Share $ 1.86 $ 1.60 $ 1.72 55XXKK(N(BRllKDtM3$M (Thousands of Dollars) Year Ended December 31 1992 1991 1990 Balance at Beginning ofPeriod 61,515 $ 62,542 $ 57,983 Add Net Income 70,439 57,997 - 59,881 Total 131,954 120,539 117,864 Deduct Dividends declared on capital stock Cumulative preferred stock 8,290 6,963 6,025 Common stock 56,696 52,061 49,297 Total 64,986 59,024 55,322 Balance at End of Period $ 66,968 $ 61,515 $ 62,542 The accompanying notes are an integral part of the financial statements.

I

(Thousands of Dollars) At December 31, 1992 1991 Assets UtilityPlant Electric $ 2,175,255 $ 2,122,248 Gas 341,466 320,385 Common 123,034 116,858 Nuclear fuel 158,826 147,063 2,798,581 2,706,554 Less: Accumulated depreciation 1,125,502 1,067,471 Nuclear fuel amortization 127,615 111,178 1,545,464, 1,527,905 Construction work in progress 83,832 76,848 Net'Utility Plant 1,629,296 -1,604,753 Current Assets Cash and cash equivalents 1,759 1,488 Accounts receivable, net of allowance for doubtfu 1 accounts; 1992 $ 500; 1991 $ 411 '2,292 84,053 Unbilled revenue receivable 60,184 55,921 Materials and supplies, at average cost Fossil fuel 12,273 10,766 Construction and other supplies 13,130 12,539 Gas stored underground 9,998 7,057 Prepayments 19,985 17,185 Total Current Assets 209,621 189,009 Deferred Debits Unamortized debt expense 13,553 9,611 Deferred finance charges Nine Mile Two 20,492 25,586 Deferred ice storm charges 24,197 ,36,431 Uranium enrichment decommissioning deferral 28,613 Nuclear generating plant decommissioning funds 29,549 19,221 Nine Mile Two deferred costs 34,300 30,121 Other 59,821 39,064 Total Deferred Debits 210,525 160,034 Total Assets 3 2.049.442 3 1,953.796 Capttallzatlon and Liabilities Capitalization Long term debt mortgage bonds 566,980 530,422 promissory notes 91,900 141,900 Preferred stock redeemable at option of Company 67,000 67,000 Prefened stock subject to mandatory redemption 54,000 60,000 Common shareholders'quity Common stock 591,532 529,339 Retained earnings 66,968 61,515 Total Common Shareholders'quity 658,500 590,854 Total Capitalization 1,438,380 1,390,176 Long Term Liability(Department ofEnergy):

Nuclear waste disposal 65,989 63,626 V

Uranium enrichment decommissioning 28,613 Total Long Term Liabilities 94,602 63,626 Current Liabilities Long term debt due within one year 110,250 96,750 Preferred stock redeemable within one year 6,000 Short term debt 50,800 59,500 Accounts payable 40,579 53,983 Dividends payable 17,035 15,555 Taxes accrued 13,743 12,050 Interest accrued 15,461 16,313 Other 13,409 13,450 Total Current Liabilities 267,277 267,601 Deferred Credits and Other Liabilities Accumulated deferred income taxes 171,673 162,955 Deferred finance charges Nine Mile Two 20,492 25,586 Pension costs accrued 20,278 13,515 Other 36,740 30,337 Total Deferred Credits and Other Liabilities 249,183 232,393 Commitments and Other Matters (Note 10)

Total Capitalization and Liabilities 0 2,049.442 6 1,953,706

'Die accompanying notes are an integral part of the financial statements.

(Thousands of Dollars) Year Ended December 31 1992 1991 1990 Cash Flow from Dperatlons iVet income 70,439

$ $ 57,997 S 59,881 Adjustments to reconcile net income to net cash provided from operating activities:

Depreciation and amortization 85,028 84,181 77,767 Amortization of nuclear fuel 18,803 23,606 25,573 Deferred fuel electric  ;, 2,543 4,122 (477)

Deferred income taxes 10,466 9,124 16,682 Allowance for funds used during construction I (2,348) (3,580) (5;408)

Unbilled revenue, net (6,631). (8,931) (2,818)

Ice storm costs "12,234 (36,431)

Nuclear generating plant decommissioning (10,328) (15,581) (3,640)

Changes in certain current assets and liabilities:

Accounts receivable (8,239) (4,773) 1,519 Materials and supplies fossil fuel (1,507) 7,506 (5,183) construction and other supplies (591) (315) (1,246)

Taxes accrued 1,693 1,444 (2,805)

Accounts payable (13,404) 6,914 (6,077)

Interest accrued (852) 1,722 (690)

Other current assets and liabilities, net (2,528) (592) (6,602)

Other, net (13,726) (6,966) 5,616

~

Total Operating $ 141,052 $ 119,447 $ 152,092 Cash, Flow from Investing Activities UtilityPlant Plant additions $ (115,790) S (114,579) S (1 23,887) fuel additions

'uclear (11",763) (13,058) (8,297)

Less: Allowance for funds, used during construction 2,348 3,580 5,408 Additions to UtilityPlant (125,205) (,124,057) (126,776)

Other, net 490 (685) (98)

Total Investing 5 (124,715) 5 (124,742) $ (126,874)

Cash Flow from Financing Activities Proceeds from:

Sale/Issue of common stock $ 63,928 $ 13,446 S 3,058 Sale of preferred stock 30,000 Sale of long term debt, mortgage bonds 160,500 100,000 Short term borrowings (8,700) 17,100 42,400 Retirement of long term debt (160,000) (92,334) (28,000)

Capital stock expense (1,735) (495) . (230)

Discount and expense ofissuing, long term debt (6,368) (3,310)

Dividends paid on preferred and common stock (63,506) (57,704) (54,787)

Other, net (185) (464) 908 Total Financing $ '16,066) S 6,239 $ (36,651)

Increase (decrease) in cash and cash equivalents $ 271 S 944 $ (11,433)

Cash and cash equivalents at beginning of year $ 1,488 S 544 $ 11,977 Cash and cash equivalents at end of year $ 1,759 $ 1,488 $ 544

~IIIIIIIIIIIIIIIIIIIRIIIIIIIIIII (Thousands of Dollars) Year Ended December 31 1992 1991 1990 Cash PaId During the Year Interest paid (net of capitalized amount) $ 64,431 S 63,848 S 64,851 Income taxes paid $ 22,911 $ 20,399 $ 17,516 the accompanying notes are an integral part of thc 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 accoun'ting policies conform to generally accepted accounting principles as applied to New York State public utilities giving effect to the rate-making and accounting practices and policies of the PSC.

In June 1988, the Board of Directors authorized the creation of Utilico'm, Inc. as a wholly owned subsidiary. Utilicom develops and markets computer software to assist customers in complying with state and federal environmental and safety regulations. The subsidiary activity has to date remained insignificant to the Company's financial position and results of operation.

In April 1990, the Board of Directors authorized the creation of Energyline Corporation, a wholly owned subsidiary, which was incorporated in July 1992. Energyline was formed as a gas corporation to fund the Company's investment in the Empire State Pipeline project. 'ipeline The Company has invested approximately $ 10 million in Empire as of December 31, 1992.

The financial statements reflect the reclassification of Pension Costs Accrued from Current Liabilities to Other Liabilities, and the reclassification of certain deferred costs. Prior periods have been restated for comparative purposes.

A description of the Company's principal accounting policies follows.

Rates and Revenue.

Revenue is recorded on the basis of meters read. In addition, beginning in July 1988, as part of a PSC rate decision, the Company commenced recording an estimate of unbilled revenue for service rendered subsequent to the meter-read date through the end of the accounting period.

Pursuant to rate orders, $ 2.4 million, $ 2.2 million and $ 13.8 million was amortized to earnings in lieu of cash rate relief in 1992, 1991 and 1990, respectively.

Tariffs for electric and gas service include fuel cost adjustment clauses which adjust the rates monthly to reflect changes in the actual aveiage 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 an 80%/20% basis up to a $ 2.6 million cumulative, after-tax', annual gain or loss to the Company. Thereafter, 100 percent of additional fuel clause adjustment amounts are assigned to customers. The electric fuel cost adjustment also provides that any-variation from forecast net revenues on sales to electric utiliti'es be shared on the same 80%/20% basis.

In addition, there is a similar 80%/20% 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.

As part of the June 1992 rate decision, rates for customers who use gas for spaceheating and are provided service under Service Classification No. 1 (primarily residential customers) are subject to a weather normalization adjustment to reflect theimpact of variations from normal weather on a billing cycle month basis for the months of October 1992 through May 1993, inclusive. The weather normalization adjustment for a billing cycle willapply only ifthe 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 1992 by approximately $ 1.8 million.

Deferred Fuel Costs. I The Company practices fuel cost deferral accounting as prescribed by the PSC under the electric and gas cost adjustment clauses included in the tariff schedules of the Company.

A reconciliation of recoverable gas costs with gas revenues is done annually as of August 31, and the excess or deficiency is refunded to or recovered from the customers during a subsequent twelve-month period beginning in December. These deferred fuel costs are reflected as a component of unbilled revenues.

Kochnev Gas sal Bccpie ~

UtilityPlant, Depreciation and Amortization.

The cost of additions to utility plant and replacement of retirement units of property is capi-talized. Cost includes labor, material, and similar items, as well as indirect charges such as engi-neering 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%, 3.3% and 3.5% per annum of average depreciable property in 1992, 1991 and 1990, respectively. The decrease in depreciation provision percentages over the last 2 years is the result of a combina-tion of the 3t/~ year extension of Ginna's license term and generally lengthening estimated useful lives. Amortization includes $ .7 million in 1992, $ .3 million in 1991 and $ 2.2 million in 1990 related to the Sterling project property loss.

lIucfear Fuel Disposal Costs.

The Nuclear Waste Policy Act (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 retriev-able 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 $ 66.0 million at December 31, 1992.

The Company is allowed by the PSC to recover these costs in rates. The estimated fees are clas-sified as a long-term liability and interest is accrued at the current three-month Treasury bill rate, adjusted quarterly. The Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of one mill ($ .001) per KWH of nuclear energy generated and sold. This charge is currently being collected from customers and paid to the DOE pursuant to PSC authorization. The Company expects to utilize on-site storage for all spent or retired nuclear fuel assemblies until an interim or permanent nuclear disposal facility is operational.

Nuclear Decommissioning Costs.

Decommissioning costs (costs to take the plant out of service in the future) for the Company's Ginna Nuclear Plant are estimated to be approximately $ 145.8 million, and those for the Company's 14% share of Nine Mile Two's decommissioning costs are estimated to be approximately $ 33.5 million (1991 dollars). Through December 31, 1992, the Company has accrued and recovered in rates $ 52.4 million for this purpose and is currently accruing for de'commissioning costs at a rate of approximately $ 8.9 million per year based on the use of a combination of internal and external sinking funds. (See Note 10.)

The decommissioning costs, which form the basis for current accruals, were derived from the record of the Company's prior rate proceeding (PSC Opiniori 92-15, issued June 1992).

Uranium Enrichment Decontamination and Decommissioning Fund.

As part of the National Energy Act (Act) issued in October 1992, utilities with nuclear, gener-ating facilities willbe assessed an annual fee payable over 15 years to pay for the decommis-sioning of Federally owned uranium enrichment facilities. The assessments for Ginna and Nine Mile.Two are estimated to total $ 28.6 million, excluding inflation and interest. A liability has been recognized on the financial, statements along with an offsetting regulatory asset. The Company believes that this amount will be recoverable in rates as described in the Act.

((Vote I continued on page 36)

8888 (continued from Allowance for Funds llsed During Construction.

page 35)

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 classi-fied in the Statement of Income as Allowance for Borrowed Funds Used During Construction, an offset to Interest Charges, and Allowance for Other Funds used During Construction, h part of Other Income.

The gross rates approved by the PSC for purposes of computing AFUDC were: 4.5%

effective September 1, 1992 through December 31, 1992; 5.5% effective April 1, 1992 through

,August 31, 1992; 7.1% effective July 1, 1991 through March 31, 1992; 8.6% effective February 1, 1991 through June 30, 1991; 9.6% effective July 1, 1990 through January 31, 1991; and 10.25% effective January 1, 1988 through June 30, 1990.

Effective July 1'6, 1984, pursuant to PSC authorization, the Company discontinued accruing AFUDC on $ 50 million of construction work in progress related to its investment in Nine Mile Two for which a cash return was being allowed through its inclusion in rate base. The PSC also ordered that amounts be 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 would be available to reduce future 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 balances of $ 20.5 million at December 31, 1992, if not used by mid-1994, may be offset against each other pursuant to PSC directives. In connec-tion with the Company's 1992 rate case decision, $ 2.5 million willbe amortized through the Statement of Income during the year commencing July 1, 1992.

Federal Income Tax.

For income tax purposes, depreciation is computed using the most liberal methods permitted.

The resulting tax reductions are offset by provisions for deferred income taxes only to the extent ordered or permitted by regulatory authorities. The cumulative balance of tax deductions not offset by provisions for deferred income taxes through 1992 is approximately $ 415 million.

The Company uses the separate-period approach in calculating the interim quarterly tax provision.

SFAS-109, Accounting for Income Taxes, has not yet been adopted by the Company.

SFAS-109 requires adoption in calendar year 1993 and 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. The Company presently believes the impact from adopting SFAS-109 to be immaterial.

Retirement Health Care and Life Insurance Benetlts.

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 ifthey reach retirement age while working for the Company. These and similar benefits for active employees are provided through insur-ance policies whose premiums are based upon the experience of benefits actually paid.

In December 1990, the FASB issued SFAS-106 entitled "Accounting for Postretirement Benefits Other than Pensions" effective for fiscal years beginning after December 15, 1992.

Among other things, SFAS-106 requires accrual accounting by employers for postretirement benefits other than pensions reflecting currently earned benefits. The Company adopted this accounting practice in the first quarter of 1992 for financial reporting purposes.

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 up'on 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.

(Thousands of Dollars) 1992 1991 1990 Charged to operating expense:

Current $ 36,101 $ 28,766 i $ 20,660 Deferred 7,490 5,493 13,830 Total 43,591 34,259 34,490 Charged (Credited) to other income:

Current Deferred (7,171), (8,211) (5,311) 2,976 3,631 2,852 Total (4,195) (4,580) (2,459)

Total Federal income tax expense $ 39,396 $ 29,679 $ 32,031 The following is a reconciliation of the difference between the amount of Federal income tax expense reported in the Statement of Income and the amount computed by multiplying the income by the statutory tax rate.

(Thousands of Dollars) 1992 1991 1990

%of %of %of Pretax Pretax Pretax Amount Inc'ome Amount Income Amount Income Net Income $ 57,997 $ 59,881 Add: Federal'income tax expense 29,679 32,031 Income before Federal income tax $ 87,676 $ 91,912 Computed tax expense $ 29,810 34.0 $ 31,250 34.0 Increases (decreases) in tax resulting from:

Difference between tax depreciation and amount deferred 6,775 6.2 5,606 6.4 4,127 4.5 Investment tax credit (2,426) (2.2) (2,432) (2.8) '(2,752) (3.0)

Miscellaneous items, net (2,297) (2.1) (3,305) (3.7) (594) (0.7)

Total Federal income tax expense $ 39,396 39.9 $ 29,679 33.9 $ 32,031 34.8 A summary of the deferred amounts charged or (credited) to income is as follows:

(Thousands of Dollars) 1992 1991 1990 Investment tax credit $ (3,284) .$ (4,235) $ (2,414)

Depreciation 25,553 24,158 22,906 Fuel costs (2,442) 205 1,180 Sterling abandonment 512 (796)

Deferred ice storm charges (3,147) 9,666 Accrued revenue 342 (353) 1,596 Demand Side Management 2,977 1,348 708, Alternative Minim'um Tax (13,768) (2,475)

'4,839 Revenues Deferred Nine Mile Two (2,013 (2,413) 1,028 Pension (2,264) (2,721) (2,729)

Other items (417 (3,275) (2,322)

Total $ 10,466 $ 9,124 $ 16,682

Mote 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:

(Millions) 1992 1991 Accumulated benefit obligation, including vested benefits of

$ 249.6 in 1992 and $ 237.4 in 1991 $ $ 251.9*

$ 359.7*

268.1'378.0'49.9 Projected benefit obligation for service rendered to date Less Plan assets at fair value, primarily listed stocks and bonds 433.3 (71.9) (73.6)

Unrecognized net gain from past experience different from that assumed and

, effects of changes in assumptions 102.4 98.0 Less Prior service cost not yet recognized in net periodic pension cost 5.4 5.5 Less Unrecognized net obligation at December 31 4.8 5.4 Pension liabilityrecognized on the balance sheet $ 20.3 $ 13.5

• Actuarial present value Net pension cost included the following components:

(Millions) 1992 1991- 1990 Service cost benefits earned during the period $ 8.8 $ ,7.1 $ 7.3 Interest cost on projected benefit obligation 27.9 26.4 25.3 Actual return on plan assets (35.1) (58.6) (9.0)

Net amortization and deferral 5.5 33.1 ~ (15.1)

Net periodic pension cost $ 7.1 $ 8.0 $ 8.5 The projected benefit'obligation at December 31, 1992 and 1991 assumed a discount rate of 7~/i percent and a long-term rate of increase in future compensation levels of 6~/a percent.

The assumed long-term rate of return on plan assets at December 31, 1992 and 1991 was 8/a percent. The unrecognized net obligation is being amortized over 15 years beginning January, 1986.

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 1992, the health c'are benefit consisted of a contribution of up to

$ 160 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 one times the employee's December 31, 1982 pay (frozen). The out-of-pocket cost of providing these benefits was approximately $ 3.0 million in 1991 and $ 2.5 million in 1990, and with the adoption of SFAS-106 in 1992, the total cost of these benefits increased by approximately $ 4.5 million.

The Company adopted SFAS-106, "Accounting for Postretirement Benefits Other than Pensions" as of January 1, 1992 for financial accounting purposes. The Company has elected to amortize the unrecognized, unfunded Accumulated Postretirement Benefit-Obligation (APBO) at January 1, 1992 over twenty years as provided by SFAS-106. The Company intends to continue funding these benefits on a pay-as-you-go basis. The pro-forma impact of the adoption of SFAS-106 on years prior to 1992 was not determinable.

The plan's funded status reconciled with the Company's balance sheet is as follows:

(Millions) 1992 Accumulated postretirement benefit obligation (APBO):

Retired employees $ (35.3)

Active employees (23.6)

$ (58.9)

Less Plan assets at fair value 0.0 Accumulated postretirement benefit obligation (in excess of) less than fair value of assets (58.9)

Unrecognized net gain from past experience different from,that assumed and effects of changes in assumptions 0.0 Less Prior service cost not yet recognized in net periodic pension cost 0.0 Less Unrecognized net obligation at December 31 53.6 Accrued postretirement benefit cost 5 (5.3)

Net periodic postretirement benefit cost included the following components:

(Millions) . 1992 Service cost benefits attributed to the period $ 0.7 Interest cost on accumulated postretirement benefit obligation 4.3 Actual return on plan. assets 0.0 Net amortization and deferral 2.8 Net periodic postretirement benefit cost 5 7.8 The APBO at December 31, 1992 assumed a discount rate of 7~/. percent and a long-term rate of increase in future compensation levels of 6'ercent.

The PSC has allowed the Company revenues in rates equal to $ 7.0 million in 1992 in recognition of these benefits. The Company has filed a petition with the PSC for deferral accounting treatment for the balance of the expense to be accrued.

The staff of the New York Public Service Commission has proposed a "Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other Than Pensions". The Statement recommends certain accounting procedures for ratemaking purposes. The Statement has not been presented to nor approved by the Public Service Commission; however the. Company believes that the Statement, when ultimately issued, will not adversely impact the financial statements.

gi

Note 4. Departmental Financial Information The Company's records are maintained by operating departments, in accordance with PSC accounting policies, giving effect to the ratemaking process. The following is the operating data for each of the Company's departments, and no interdepartmental adjustments are required to arrive at the operating data included in the Statement of Income.

(Thousands of Dollars) 1992 1991 1990 Electric Operating Information Operating revenues . S 633,808 $ 617,542 S 594,395

'perating expenses, excluding pro on for incom e taxes 482,968 478,101 464,478

, Pretax operating income 150,840 139,441 129,917 Provision for income taxes 38,046 31,390 30,670 Net operating income S 112,794 $ 108,051 S 99,247 Other Informatiori '

Depreciation and amortizati on $. 73,213 S 72,746 S 67,302 Nuclear fuel amortization S 18,803 S 23,606 S 25,573 Capital expenditures $ 100,974 S 97,294 S 101,024 Investment Information Identifiable assets (a) $ 1,671,492 $ 1,607,21 0 $ 1,557,176 8as Operating Information Operating revenues $ 261,724 $ 235,728 $ 236,496 Operating expenses, excluding provision for income taxes 235,029 216,151 214,505 Pretax operating income 26,695 19,577 21,991 Provision for income taxes 5,545 2,869 3,820 Net operating income $ 21,150 $ 16,708 S 18,171

'tlrer Information Depreciation and amortization $ 11,815 S 11,435 $ 10,465 Capital expenditures $ 24,231 S 26,763 S 25,752 Investment Information Identifiable assets (a) $ 354,528 $ 325,451 $ 291,088 (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 facilitie's in which the Company is participating. Both Oswego Unit No. 6 and Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are operated by Niagara Mohawk Power Corporation. Each participant must provide its own financing for any additions to the facilities. The Company's share of direct expenses associated with these two units is included in the appropriate operating expenses in the Statement

- of Income. Various modifications will be made throughout the lives of these plants to increase operating efficiency or reliability, and to satisfy changing environmental and safety regulations.

Nine Mile Oswego Point Nuclear Unit No. 6 Unit No. 2 Net megawatt capacity 850 1,080 RG&E's share megawatts 204

- Year of completion percent 24 151 14 1980 1988 Millions of Dollars at December 31, 1992 Plant In Service Balance $ 98.6 $ 867.6 Accumulated Provision For Depreciation $ 30.9 $ 428.9 Plant Under Construction S 0.4 $ 9.4 The Plarit in Service and Accumulated Provision for Depreciation balances for Nine Mile Point Nuclear Unit No. 2 shown above have been increased by the disallowed costs of $ 374.3 million.

Such costs, net of income tax effects, were previously written off in.1987 and 1989.

Note 6. Long Term, Debt First Mortgage Bonds (Thousands)

Principal Amount December 31 Series Due 1992 1991 4N U Sept. 15, 1994 $ 16,000 $ 16,000 5.3 V May I, 1996 18,000 18,000 6Y4 W Sept. 15, 1997 20,000 20,000 6.7 X July I, 1998 , 30,000 30,000 8 Y Aug. 15, 1999 30,000 30,000 Z Sept. I, 2000 30,000, 30,000 9Y4 BB June 15, 2006 50,000 50,000 85/5 CC Sept. 15, 2007 ~

50,000 50,000 9.5 DD Dec. I, 2003 40,000 40,000 6Y2 EE (a) Aug. I, 2009 10,000 10,000 10.95 FF Feb. 15, 2005 5,500 27,500 12Y4 HH May 15, 2012 10,500 132/5 JJ June 15, 1999 17,500 4 20,000 8.6 LL (b) Aug. I, 1993 75,000 75,000 82/5 MM May I, 1992 75,000 85/5 Oo(a) Dec. I, 2028 25,500 25,500 95/i PP Apr. 1, 2021 100 000 100 000 8Y4 QQ (b) Mar. 15, 2002 100,000 6.35 RR (a) May 15, 2032 10,500 6.50 SS (a) May 15, 2032 50,000 678,000 627,500 Net bond discount (770) (328)

Less: Due within one year 110,250 96,750 Total 5566,550 6530,422 (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 tfie 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 participation agreements 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 I, 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 LL and QQ First Mortgage Bonds are generally not redeemable prior to maturity.

The First Mortgage provides security for the bonds through a first lien on substantially all the property owned by the Compariy (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 1991 and 1992 requirements were met by certification of additional property.

In October 1992 the Company established a $ 200 million medium-term note program entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series A" with maturities that may range from one year to thirty years. At December 31, 1992 there were no medium-term notes outstanding. On January 14, 1993 the Company issued $ 30 million of the medium-term notes at an interest rate of 7.00% with a maturity date of January 14, 2000. The issue is generally not redeemable before maturity.

(Note 6 continued on page 42)

(continued fiom fund requirements and bond maturities for the next five years are: 'inking page 4I) 1994 1995 1996 1997 (Thousands) 1993 Series Z (c) $ 30,000 Series FF (d) 2,750 $ 2,750 Series JJ (e) 2,500 2,500 $ 2,500 $ 2,500 $ 2,500 Series LL 75,000 Series U 16,000 Series V 18,000 Series W 20,000

$ 110,250 $ 21,250 $ 2,500 $ 20,500 $ 22,500 (c) On January 15, 1993 the Company exercised its option to redeem $ 30 million principal amount of Series Z Bonds at a price of 102.21%.

(d) The Series FF First Mortgage Bonds are subject to a mandatory sinking fund of $ 2.75 million annually each February 15.

(e) The Series JJ First Mortgage Bonds are subject to a mandatory sinking fund of $ 2.5 million annually each June 15.

Promfssory Notes (Thousands)

December 31 Issued Due 1992 1991 November 15, 1984 (f) October 1, 2014 $ 51,700 $ 51,700 December 5, 1985 (g) November 15, 2015 40,200 40,200 July 22, 1987, (h)

Cancelled See Note Below 50,000 Total 091,900 $ 141,000 (f) The $ 51.7 million Promissory Note was issued in connection with NYSERDA's Floating Rate Monthly Demand Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), Series 1984.

This obligation is supported by an irrevocable Letter of Credit expiring October 15, 1994. The interest rate on this note for each monthly interest payment period willbe 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 2.74% for 1992, 4.32% for 1991 and 5.55% for 1990. The interest rate willbe adjusted monthly unless converted to a fixed rate.

(g) The $40.2 million Promissory Note was issued in connection with NYSERDA's Adjustable Rate Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project),Series 1985. This obligation is supported by an irrevocable Letter of Credit expiring November 30, 1994. The annual interest rate was adjusted to 5.70% effective November 15, 1990, to 4.50% effective November 15, 1991 and to 3.10% effective November 15, 1992. The interest rate willbe adjusted annually unless converted to a fixed rate.

(h) The $ 50.0 million Promissory Note was issued in connection with NYSERDA's Adjustable Rate Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), Series 1987. The annual interest rate was adjusted to 6.30% effective July 15, 1990 and to 5.50% effective July 15, 1991. On June 15, 1992 the Series 1987 Bonds were redeemed at a price of 100% and the Promissory Note was cancelled.

The Company is obligated to make payments of principal, premium and interest on each Promissory Note which correspond to the payments of principal, premium, ifany, 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 1992 of 7.64% for long term debt withj.

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 $ 787 million at December 31, 1992.

Rochc0000 G00 0490 Bcccric ~

Note 7. Preferred and Preference Stock Type, by Order of Seniority Par Value Shares Authorized Shares Outstanding Preferred Stock (cumulative) $ 100 2,000,000 1,270,000*

Preferred Stock (cumulative) 25 4,000,000 Preference Stock 1 5.000.000

'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:

(Thousands)

Shares Optional Outstanding December 31 Redemption'per Series December 31,1992 1992 1991 share)f 4 F 120,000 $ 12,000 $ 12,000 $ 105 4.10 H 80,000 8>000 8,000 101 45/ I "60,000 6,000 6,000 101 4.10 J 50,000 5,000 5,000 102.5 4.95 K 60,000 6,000 6,000 102 4.55 M 100,000 10,000 10,000 101 7.50 N 200,000 20,000 20,000 ~

102

, Total 070,000 667,000 $ 67,000

¹May be redeemed at any time at the option of the Company on 30 days mini mum notice, plus accrued dividends in all cases B. Preferred Stock, subject to mandatory redemption:

(Thousands)

Shares Optional Outstanding December 31 Redemption Series December 31 1992

~ 1992 1991 (per share) 8.25 R 300,000 $ 30,000 $ 30,000 $ 104.00 Before 3/1/93+

7.45 S 100,000 10,000 10,000 Not applicable

'.55 T 100,000 10,000 10,000 Not applicable 7.65 U 100,000 10,000 10,000 Not applicable 600,000 $ 60,000 $ 60,000 Less: Due within one year 60,000 6,0PO Total 540,000 554,000 $ 60,000

+Thereafter at lesser rates Mandatory Redemption Provisions.

In the event the Company should be in arrears in the sinking fund requirement, the Company may not redeem or pay dividends on any stock subordinate to the Preferred Stock.

Series R. Mandatory redemption of 60,000 shares per year at $ 100 per share commences on March 1, 1993 for Series R and on each March 1 thereafter, so long as any shares remain outstanding. In addition, the Company has the non-cumulative right to redeem up to an additional 60,000 shares'on the same terms and dates applicable to the mandatory sinking fund redemptions.

Series S, Series T, Series U. All of the shares are subject to redemption pursuant to mandatory sinking funds on September 1, 1997 in the case of Series S, September 1, 1998 in the case of Series T and September 1, 1999 in the case of Series U; in each case at $ 100 per share.

Based on an estimated dividend rate at year-end 1992 of 6.00% for Preferred Stock, subject to mandatory redemption, with similar teims and average maturities (3.5 years), the fair value of the Company.'s Preferred Stock, subject, to mandatory redemption, is approximately

$ 65 million at December 31, 1992.

Note 8. Common Stock At December 31, 1992, there were 50,000,000 shares of $ 5 par value Common Stock autho-rized, of which 34,796,659 were outstanding. No shares of Common Stock are reserved for options, warrants, conversions, or other rights. There were 208,649 shares of Common Stock reserved and unissued for shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan and 52,660 shares reserved and unissued for employees under the RG8cE Savings Plus Plan.

Common Stack:

Shares Amount Per Share Outstanding (Thousands)

Balance, January 1, 1990 31,257,968 $ 513,560 .

Automatic Dividend Reinvestment and Stock Purchase Plan $ 1 8.600-$ 19.288 134,828 2,513 Savings Plus Plan $ 1 8.62M19.750 28,472 545 Capital Stock Expense (230)

Balance, December 31, 1990 31,421,268 $ 516,388 Automatic Dividend Reinvestment and Stock Purchase Plan $ 18.750-$ 23.1,63 571,669 11,252 Savings Plus Plan '$19.375-$ 23.563 108,202 2,194 Capital Stock Expense 7 (495)

Balance, December 31, 1991 32,101,139 $ 529,339 Sale of Stock $ 24.000 2,000,000 48,000 Automatic Dividend Reinvestment and Stock Purchase Plan $ 21.325-$ 24.850 584,854 13,338 Savings Plus Plan $ 22.063-$ 25.1 88 110,666 2,590 Capital Stock Expense (1,735)

Balance, December 31, 1992 34,796,659 6591.532 Note 9. Short Term Oebt At December 31, 1992 and December 31, 1991, the Company had short term debt outstand-ing of $ 50.8 million and $ 59.5 million, respectively. The weighted average interest rate on short term debt outstanding at year end 1992 was 3.99% and was 4.28% for borrowings during the year. For 1991, the weighted average interest rate on short term debt outstanding at year end was 5.09% and was 6.43% for borrowings during the year.

On December 1, 1988 the Company renewed its $ 90 million revolving credit facility for a period of three years. In January of 1993 the Company was grante'd a one-year extension of the commitment termination date to December 31, 1995. Commitment fees related to this facility amounted to $ 169,000 in 1992, $ 149,000 in 1991 and $ 164,000 in 1990.

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, 1992, the Company would be able to incur $ 45.2 million of additional unsecured debt under this provi-sion. In order to be able to use its revolving credit agreement, the Company has created a subor-dinate mortgage which secures borrowings under its revolving credit agreement that might otherwise be restricted by this provision of the Company's Charter.

Since June 1990 the Company has had a credit agreement with a domestic bank providing for up to $ 20 million of short term debt Borrowings under this agreement, which has been extended to December 31, 1993, are. secured by the Company's accounts receivable.

Also, beginning in August 1992, additional unsecured short term borrowing capacity of up to

$ million is available from a domestic bank, at its discretion.

25 Rocbcaccc Gaa near Bccccic ~ion

Mote 10. Commitments and Other Matters Capital Expenditures.

The Company's 1993 construction expenditures program is currently estimated at

$ 143 million, including $ 4 million of carrying charges. The Company has entered into certain commitments for purchase of materials and.equipment in connection with that program.

Nuclear-Belated Matters.

Decommissioning Trust. Under accounting procedures approved by the PSC, the Company has been collecting in,its electric rates amounts for the eventual decommissioning of its Ginna Plant and for its 14% share of the decommissioning of Nine Mile Two. The Company has col-lected approximately $ 52.4 million through December 31, 1992.

In June 1988 the Nuclear Regulatory Commission (NRC) issued new regulations establishing-criteria for various facets of decommissioning including acceptable alternative methods, planning, funding and environmental review. The NRC regulations establish a minimum external funding level-determined by formula. The NRC minimum represents only the cost of removing the radioactive plant structures. The Company's depreciation rates reflect a 5% cost of removal factor for Ginna non-radioactive plant structures; however, they do not currently reflect a cost of removal factor for the Company's 14% share of Nine Mile 7wo non-radioactive plant structures. Since March 1990, the Company has deposited $ 28.3 million into an external decommissioning trust fund. In July 1990 the Company, in compliance with the NRC regulations, submitted a funding plan to the NRC.

In connection with the Company's rate case completed in June 1992, the PSC approved the

- collection during the rate year ending June 30, 1993 of an aggregate $ 8.9 million for decommis-sioning, covering both nuclear unig. The amount allowed in rates is based on estimated ultimate decommissioning costs of $ 145.8 million for Ginna and $ 33.5 million for the Company's 14%

share of Nine Mile 7wo (1991 dollars). The Company intends to fund the external decommis-sioning trust in th'e amount of the NRC minimum funding requirement, The difference between the amount to be collected and the NRC minimum willbe held m an internal reserve.

Uranium,.Enrichment Decontamination and Decommissioning Fund. As a result of the National Energy Act (Act) passed in October 1992, U.S. Utilities with Nuclear generating facil-ities willbe assessed an annual Decontamination and Decommissioning fee payable to the DOE. This annual fee willbe in place for 15 years and could be assessed as early as 1993. The Company's annual fee is approximately $ 1.8 million for the Ginna Nuclear Plant and the esti-mated amount for its share of Nine Mile 7wo is approximately $ .1 million. Although a noncash transaction, the aggregate amount of $ 28.6 million (see Note 1) has been recognized as a liability at December 31, 1992, together with a corresponding deferred debit based on the language of the Act. The Company believes it willreceive the ultimate recovery of this deferral through its fuel adjustment clause.

Insurance Program. The Price-Anderson Act establishes a federal program, providing indemnification and insurance against public liability, applicable in the event of a nuclear accident at a licensed U.S. reactor. Amendments to the Act in 1988 increased the public liability limit to approximately $ 7.4 billion, expanded coverage to include precautionary evacuations and extended the Act's effectiveness until the year 2002. Under the program, claims would first be met by insurance which licensees are required to carry in the maximum amount available (currently $ 200 million). Ifclaims exceed that amount, licensees are subject to a retrospective assessment up to $ 63 million per licensed facility for each nuclear incident, payable at a rate not to exceed $ 10 million per year. Those assessments are subject to periodic inflation-indexing and to a 5% surcharge iffunds prove insufficient to pay claims. The Company's interests in two nuclear units could thus expose it to a current potential payment for each accident of

$ 71.8 million through retrospective assessments of $ 11.4 million per year in the event of a suAiciently serious nuclear accident at its own or another U.S. commercial nuclear reactor.

(Note 10 continued on page 46)

(continued fiont Beginning in 1988, coverage for claims alleging radiation-induced injuries to some workers page 45) at nuclear reactor sites was removed from the nuclear liability insurance policies purchased by the Company. Coverage for workers first engaged in nuclear-related employment at a nuclear site prior to 1988 continues to be provided under then-existing nuclear liability insurance policies. Those workers first employed at a nuclear facility in 1988 or later are covered under a separate, industry-wide insurance program. That program contains a retrospective premium assessment feature whereby participants in the program can be assessed to pay incurred losses that exceed the program's reserves. Under the plan as cu'rrently established, the Company could be assessed a maximum of $ 3.1 million over the life of the insurance coverage.

The Company is a member of Nuclear Electric Insurance Limited, which provides insurance coverage for the cost of replacement power during certain prolonged accidental outages of nuclear generating units and coverage for property losses in excess of $ 500 million at nuclear generating units. As of December 31, 1992, the Company is purchasing a weekly indemnity limit of $ 3.5 million in the NEIL I replacement power expense program and full policy limits of

$ 1.325 billion in the NEIL II.Property Insurance Program for the Ginna Nuclear Power Plant.

Coverage, under the Property Insurance Program includes the shortfall in the NRC required external trust fund resulting from the premature decommissioning of a nuclear power plant fol-lowing an accident with property damage in excess of $ 500 million. The Company currently has designated $ 169 million as a sublimit for this coverage at the Ginna Nuclear Power Plant.

For its share in the generation of Nine Mile Two, the Company purchases a weekly indemnity limitof $ .5 million in the NEILI replacement power expense program. The owners at Nine Mile Two purchase the full policy limit of $ 1.325 billion in the NEIL II Property Insurance Program and the Company pays its proportionate share of those premiums. The owners at Nine Mile Two have selected the maximum available sublimit of $ 200 million for premature decom-missioning. Ifan 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 approxi-mately $ 5.2 million and $ 13.7 million in the event of losses under the replacement power and property damage coverages, respectively.

Environmental Matters.

On November 15, 1990 the Federal Clean Air Act Amendments of 1990 (Amendments) became law. The Amendments will affect air emissions and quality control measures primarily at the Company's fossil-fueled electric generating facilities. The Amendments consist of several Titles. Three of them are of particular importance to the Company. Title IV addresses Acid Deposition and incorporates a two-phased emissions reduction program for sulfur and nitrogen oxides. The first phase becomes effective in 1995, while the second phase, which contains more stringent provisions, will become effective in the year 2000. The Company is not affected by the first phase of Title IV of the Act. Title I addresses ambient ozone non-attainment and is also divided into two phases. Rochester is included in the Northeast Ozone Transport Region which is required to reduce nitrogen oxide emissions significantly in order to assist downwind receptors in achieving their ozone standards. The first phase of Title I becomes effective in 1995 and willrequire the installation of low nitrogen oxide burners on the Company's fossil-fuel plants. Phase Two of Title I has not yet been defined, but could require flue gas cleanup for nitrogen oxide removal. Title IIIof the Act has not yet been defined but could require the control of various air toxics of the Comply's fossil-fuel plants ifEnvironmental Protection Agency studies to be completed by 1994 show that these substances are present in specific concentrations. Capital costs between $30 million and $ 50 million (1992 dollars) have been estimated for the implementation of several potential compliance scenarios under the Amendments. Such capital costs would be incurred between 1993 and 2000, ifthe Company elected to go forward with any such scenario.

1-In 1985, the New York State Department of Etivironmental Conservation (AYSDEC) identi-fied property in the vi'cinity of the Lower. Falls of the Genesee River (the Lower Falls) in Rochester as an'inactive hazardous waste disposal site. The Company owns, and was the prior operator of a number of locations within the Lower Falls. In mid-1991, NYSDEC 'wner'r advised the Company that it had delisted theLower Falls Site, i.e., removed it from its-Registry of Inactive Hazardous Waste Sites. The effect of delisting is to terminate the Company's status's 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, and to'efer (and perhaps end) the prospect of remedial action and any Company

.sharing of the cost the'reof. However, NYSDEC also stated its intention to consider listing indi--

vidual coal gasification sites within the larger, original site once the State of New York adopts new federal procedures under which such individual sites will be, compared to new hazardous waste criteria. There is at least some material at one of the individual coal gasification sites that

=could trigger relisting. The Company is unable to predict what further listing action NYSDEC'ay take, but regards the announced delisting as a positive development..

The Company and its predecessors formerly owned and operated coal gasification facilities

. within the Lower Falls. In'eptember 1991 the Company proactively initiated a study of sub-surface conditions in the vicinity of retired facilities at its West Station property and has since commenced interim remedial measures there in order to minimize any potential long-term exposure risks.

-. On'a portion of the Company's property >n the Lower Falls, 'and elsewhere in the general "area, the County of Monroe has installed and operates sewer lines. During sewer installation, the County constructed over Company propert/, pursuant to an easement the Company granted the County, certain retention ponds which were reportedly used to.recover from the sewer con-struction 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 intehds to peek reimbursement for its additional costs in.

recovering 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'xcavation, treatment and disposal and with effecting a regulatorily.-approved closure of the retention pond area. The Company could incur costs

, as yet undetermined ifit were to be found liable for such closure and materials handling, althou'gh provisions of the easement afford the Company rights, which may serve to offset all or a portion of any such County claim.

In the letter announcing the delisting of the Lower Falls Site, NYSDEC indicated an intention

'to pursue appropriate closure of the County's former retentionpond area, suggesting that it will be evaluated separately to determine whether it meets the criteria of a hazardous waste site. The Compa'ny is unable to assess what implications the NYSDEC letter may have for the County's claim against it..

At another location along the River where the Company owns property, a boring taken)'n Fall 1988 for a sewer system project showed a layer containing a black viscous material. The Company undertook an investigation to determine the extent of contamination. The study found that some soil and ground water contamination existed on-site; but evidence was inadequate fo

'determine whether the contamination had migrated off-site. The matter was reported to the NYSDEC and, in Septeinber 1990, the Company also provided the agency with a risk assess-ment for its review. Ifthe NYSDEC requires remediation of this location', the Company may be fully or-partially responsible for the costs of investigation and any site remediation. The

. Company cannot at this time predict what may result'from the NYSDEC review of informa-tion on the material from the boring, what future studies may be performed,'and what remedia-tion.measures may be directed.

(Note l0 continued on page 48)

Rochrsta Gas aad Bccaic ~on

L (eorm'nued fionI Gas'Cost Recovery.

page 47)

Throughout the late 1970's and early 1980's, many interstate natural gas pipelines signed long-term gas sales cbiItracts with producers under which the pipelines were obligated to take delivery of a specified percentage of maximum contract volumes of natural gas or, ifsuch quan-tities were not taken, to pay for them (take-or-pay). As a result of reduced demand, many pipelines subsequently experienced a significant reduction in sales, leading to substantial take-

'o or-pay liabilit$ their producers. The FERC has adopted an approach which requires pipelines to absorb substantial portions of their take-or-pay costs and requires the pipelines'ustomers to develop consensus methodologies to allocate the remaining costs among customers.

The PSC instituted a proceeding in October 1988 to determine the extent to which the gas distribution companies in New York State would be permitted tonecover in rates the take-or-pay costs imposed upon them. That proceeding is ongoing, and the issues raised include the legal authority of the PSC to d'eny recovery of such costs.'However, in October 1989, the PSC approved a settlement between the Staff of the PSC end the Company providing for the Company to recover in rates 87.5% of the first $ 12 million of the pipeline take-or-pay costs imposed upon it. The recovery, of any take-or-pay costs-incurred in excess of $ 12 million would be subject to future determination.

In March 1992 the Company began providing for recovery, on. an interim basis, of 65% of take-or-pay costs in excess of $ 12 million, subject to refund pending permanent disposition of such costs. In November 1992 the Company and the Staff of the PSC entered into, and subse-quently filed with the PSC, a supplemental settlement under which the Company would recover all take-or-pay costs imposed upon it in excess of $ 12 million, except for an amount which would not exceed $ 562,500. The PSC must approve the supplemental settlement for it to become effective.

The Company is presently unable to estimate the amount of take-or-pay costs which ultimately may be included in its pipeline suppliers'harges. As of December 31,-1992 the Company had been billed for $ 16.4 million.of take-or-pay costs and has thus far recovered

$ 10.6 million from its customers. In addition, $ 4.1 million has been deferred for recovery.

The FERC is in the process of developing policies and rules which will enable natural gas, purchasers, such as the Company, to choose their gas suppliers and tp receive non-discrimiriatory services from interstate pipelines. A major component of this policy permits natural gas pur-chasers to convert their purchase contracts with interstate pipelines into transportation contracts.

'These contract conversions will require the pipelines to reduce their purchase commitments to natural-gas producers. The costs of such conversions will be allocated among the pipelines'us-tomers. The allocation methodologies are being developed in individual rate cases at this time.

The Company cannot predict the dollar cost of such conversions to its customers or what action the PSC may ultimately take regarding this matter.

Other Matters.

Regulatory Disallowances. In December 1991, the Company recognized a non-cash charge-against earnings of $ 10 million for refunds to be made to customers in connection with a PSC fuel procurement audit. The refund was made in 1992. In June 1992, the company recorded a charge to earnings of $ 8.2 million in connection with ice storm restoration costs disallowed by the PSC.

Nuclear Fuel Enrichment Services. The Company=has a contract with the DOE for nuclear fuel enrichment services which assures provision of 70% of the Ginna Nuclear Plant's require-ments throughout its service life or 30 years, whichever is less. No payment obligation accrues unless such enrichment services are needed. Annuallyi the Company is permitted to decline DOE-furnished enrichment for a future year upon giving ten years'otice.,Consistent with that provision, the Company has terminated its commitment to DOE for the years 2000, 2001 and 2002. The Company has secured the remaining 30% of its Ginna requirements for the reload

years 1993 through 1995 under different arrangements with DOE. The Company plans to meet its enrichment requirements for years beyond those already committed by making further arrangements with DOE or by contracting with third parties. The cost of DOE enrichment service's utilized for the next seven reloadyears (priced at the most current rate) ranges from

$ 4 million to $ 7 million per year.

Anticipated Assertion of Tax Liability. The Company's federal income tax returns for 1987 and 1988 have been examined by the Internal Revenue Service,(IRS). Based on the progress of the examination to date, in the first half of 1993, the Company anticipates receiving proposed.

adjustments which, ifsustained, could significantly increase its tax liability. '. "

The adjustments at issue generally pertain to the ch'aracterization and treatment of events and relationships at the Nine Mile Two project and to the appropriate tax treatment of investments made and expenses incurred at the project by the Company and the other co-tenants. A principal issue appears to be the year in which the plant was placed in service.

The Company expects to protest adjustments the IRS may propose to its 1987-88 tax liability and to pursue the protest vigorously. The Company believes it has sound bases on which to make such a challenge, but cannot predic't 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.

IIGiggP ljxiiimgj'rice P~aterh,ouse 1900 Lincoln First Tower Rochester, New York 14604 January 22, 1993 To the Shareholders and Board of Directors of Rochester Gas and Electric Corporation

=

In our opinion, the accompanying balance sheets and the related statements of income, retained earnings and cash flows present fairly, in all material respects, the financial position of Rochester Gas and Electric Corporation at December 31, 1992 and 1991, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1992 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 presehtation. 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 Standard No. 106,"'Accounting for Postretirement Benefits Other than Pensions" in 1992.

The management of Rochester Gas and Electric Corporation has prepared and is responsible for the financial statements and related financial information contained in this Annual Report.

Management uses its best judgements and estimates to ensure that the financial statements reflect fairly the financial position, results of operations and cash flows of the Company in accordance with generally accepted accounting principles. Management maintains a system of internal accounting controls over the preparation of its financial statements designed to provide reasonable assurance as to the integrity and reliability of the financial records.

This system of internal control includes documented policies and guidelines and periodic evalua-tion and testing by the internal audit department.

The Company's financial statements have been examined by Price Waterhouse, independent accountants, in accordance with generally accepted'auditing standards. Their examination includes a review of the Company's system of internal accounting control and such tests and other procedures necessary to express an opinion as to whether the Company's financial statements are presented fairly in all material respects in conformity with generally accepted accounting principles. The report of Price Waterhouse is presented on page 49.

The Audit Committee of the Board of Directors is responsible for reviewing and monitoring the Company's financial reporting and accounting practices. The Audit Committee meets regularly with management and the independent accountants to review auditing, internal control and financial reporting matters. The indeperident accountants have direct access to the Audit Committee, without management present, to discuss the results of their examinations and their opinions on the adequacy of internal accounting controls and the quality of financial reporting.

Management believes that, at December 31, 1992, the Company maintained an effective system of internal control over the preparation of its published financial statements.

Roger N Kober RobertC. Henderson Chairman of the Board, President and Chief Executive Officer Senior Vice President, Controller and Chief Financial Officer January 22, 1993 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.

(Thousands of Oollars)

Earnings per Quarter Ended December 31, 1992 September 30, 1992 June 30, 1992*>>

March 31, 1992 Operating Revenues

$ 244,290 198,341 195,154.

257,747 Operating Income

$ 41,744 33,066 16,460 42,735

'et Income

$ 29,146 17,507 (4,579) 28,365 Earmngs on Common Stock

$ 27,073 15,435 (6,651) 26,293 Common Share (in dollars)

$ .77

.45

(.20)

.81, December 31, 1991>> $ 229,331 $ 38,578 $ 14,911 $ 12,467 $ .38 September 30, 1991 195,629 31,752 17,262 15,756 .49 June 30, 1991 182,637 17,230 1,538 32 March 31, 1991 245,673 37,198 24,286 22,780 .72 December 31, 1990 $ 220,360 $ 32,878 $ 18,136 $ 16,630 $ .53 September 30, 1990 187,508 30,218 15,593 14,087 .45 June 30, 1990 182,216 16,541 2,068 562 .01 March 31, 1990 240,807 37.781 24,084 22,578 .72 Includes tccognition of $ 6 6 million net of tus fuels audit disallowance.

• • Includes recognition of $ 5.4 million net-of-tax ice storm disallowance.

.Earnings 1992 1991 1990 Slm res 1992 '991

-1990 Earnings per weighted Number of shares (000's) average share $ 1.86 $ 1.60 Q.72 Weighted average 33,268 31,794 31,293 Actual number at December 31 34,797 32,101 31,421

. Tax Status of Cash Dividends Cash dividerids paid in 1992, 1991 and 1990 were 100 percent taxable for Federal income tax purposes.

'Dividend Policy The Company has paid cash dividends quarterly on its Common Stock without interruption since it became publicly held in 1949. The level of future cash dividend payments willbe dependent upon the Company's future earnings, its financial requirements and other factors.

The Company's Certificate of Incorporation provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company.

Quarterly dividends on Common Stock are generally paid on the twenty-fifth day of January, April, July and October. In January 1993, the Company paid a cash dividend of $ .43 per share on its Common Stock, up $ .01 from the prior quarterly dividend payment of $ .42.'The January 1993 dividend payment is equivalent to $ 1.72 on an annual basis.

Commori Stock Trading Shares of the Company's Common Stock are traded on the New York Stock Exchange under ge symbol "RGS".'990

~

1991 1992 RANGE OF RANGE oF RANGE OF CohdhfON STOCK PRICE. CohthtoN STOCK PRICE CohahtoN STocK PRtca (In Dollars) (In Dollars) (In Dollars) 26 '26 25.25 24.75 23.88 24.00 2325 23-23.13 21.75 '2 22 22.75 20.75 . 2088 21 21 20.50 20.88 2 25 19.88 20 00 20 20 20 19.25 20.1tt

'19.50 19 19 19.00 19.00-18 '8 18 17.88 17.50 17.75 17 17 16.88 16 16 16 1st 2nd -3rd 4th 1st 2nd 3rd 4th 1st 2nd 3rd 4th Quarter, ~ Q(sarler Quaner DIYIDENDs PAID per SHARE, DiviDENDS PAID per SttARB, DtvIDENDs PAID per SHARF 1990 per QGARIER 1991 per QOARrER 1992 per QUARTER (In Dollars) (In Dollars) (In Dollars) 0.39 0.39 0.39 0.39 0.405 0.405 0.405 -

0.405 0.42 0.42 0.42 0.42 Rocbesus Gss saa Bocsaa ~

(Thousands of Dolfars) Year Ended Oecember 31 1992 1991 1990 1989 1988 1987 Summary of Operations Operating Revenues Electric $ 608,267 $ 588,930 $ 5511930 $ 543,096 $ 514,637 $ 489,366 Gas 261,724 235,728 236,496 264,573 231,217 218,408 869,991 824,658 788,426 807,669 745,854 707,774 Electric sales to other utilities 25,541 28,612 42,465 38,028 29,966 26,215 Total Operating Revenues 895,532 853,270 830,891 845,697 775,820 733,989 Operating Expenses Fuel Expenses /

Electric fuels 1 . 48,376 65, 105 76,420 75,873 65,787 61,443 Purchased electricity 29,706 27,683 34,264 39,645 30,299 26,467 Gas purchased for resale 4 141,291 129,779 132,512 152,623 129,596 124,086 Total Fuel Expenses 219,373 222,567 243,196 268,141 225,602 211,996 Operating Revenues Less Fuel Expenses 676,159 630,703 587,695 577,556 550,138 521,993 Other Operating Expenses Operations excluding fuel expeoses 226,624 208,440 194,594 173,764 159,689 159,'l70 Maintenance 62,720 65,415 62,391 64,316 52,575 46,124 Depreciation and Amortization 85',028 84,181 77,767 75,063 69,703 55,530 Taxes local, state and other 124,252 113,649 101,035 95,341 88,635 82,869 Federal income tax current 35,299 28,766 20,661 20,509 =

20,363 32,781 deferred 8,292 5,493 13,829 17,330 20,299 23,144 Total Other Operating Expenses 542,215 505,944 470,277 . 446,323 411,264 399,618 Operating Income 133,944 124,759 117,418 131,233 138,874 122,375 Other Income and Deductions Allowance for other funds used during construction 164 675 2,689 2,261 2,047 5,030 Federal income tax 4,195 4,580 2,459 1,439 1,683 17,520 Regulatory disallowances (8,'215) (10,000) (2,100) (55,860)

Other, net 6,155 6,078 4,062 8,328 6,901 8.831 Total Other Income and Deductions 2,299 1,333 9,210 9,928 10,631 (24,479)

Income Before Interest Clrarges 136,243 126,092 126,628 *141,161 149,505 97,896 Interest Charges Long term debt 60,810 63,918 64,873 68,628 72,270 73,489 Short term debt 1,950 2,623 1,070 129 Other, net 5,228 4,459 3,523 3,115 2,898 2,685 Allo'wance for borrowed funds used during construction (2, 184) (2,905) . (2,719) (2,026) (1,777) (2,696)

Total Interest Charges 65,804 68,095 66,747 69,717 73,391 73,607 Income from Continuing Operations, Before Cumulative Effect ofAccounting Change 70,439 57,997 59,881 71,444 76,114 24,289 Cumulative Effect for Years Prior to 1987 of Accounting Change for Disallowed Costs (193,000)

Net Income (Loss) 70,439 57,997 59,881 71,444 76,114 (168,711)

Dividends on Preferred at Required Rates I'tock, 8,290 6,963 6,025 6,025 7,348 8,147 Earnings (Loss) Applicable to Common Stock 0 62,149 3 51.034 6 53,856 $ 65,419 $ 60,766 $ (176,850(

A Weighted Average Nuinber of Shares Outstanding in Each Period (000's) 33,258 31,794 31,293 31,090 30,513 29,728 Earnings (Loss) per Common Share Total $ 1.86 $ 1.60 $ 1.72 $ 2.10 '$2.25 $ (5.95),

Earnings per Common Share Continuing Operations $ 1.86 $ 1.60 $ 1.72 $ 2.1 0 '$2.25 6 0.54 Cash Dividends Paid per Common Share $ 1.60 $ 1.62 $ 1.56 $ 1.50 $ 1.50 $ 2.025

Condensed Balance Sheet (Thousands of Dollars) At December 31 1992 1991 1990 1989 1987 Assets UtilityPlant $ 2,798,581 $ 2,706,554 $ 2,310,294 $ 2,208,158 $ 2,122,922 $ 1,559,848 Less: Accumulated depreciation and amortization 1,253,117 1,178,649 812,994 730,621 653,876 586,840 1,545,464 1,527,905 1,497,300 1,477,537 1,469,046 973,008 Construction work in progress 83,832 76,848 82,663 68,784 41,044 501,738

'et utilityplant 1,629,296 1,604,753 1,579,963 1,546,321 1,510,090 1,474,746 Current Assets 209,621 189,009 176,045 190,321 21346267 184I472 Deferred Debits 210,525 160,034 108,45'1 102,729 102,015 131,526 Total Assets $ 2,049,442 $ 1,953,706 $ 1,864,459 $ 1,839,371 $ 1,825,731 $ 1,790,74'4 Capitalization and Liabilities Capitalization Long term debt $ 658,880 $ 672,322 $ 721,61 2 $ 764,627 $ 792,976 $ 845,326 Preferred stock redeemable at option of Company 67,000 67,000 67,000 67,000 67,000 67,000 Pieferred stock subject to mandatory redemption 54,000 60,000 ', 30,000 30,000 30,(00 50,797 Common shareholders'quity "

'ommon stock 591,532 529,339 516,388 513,560 504,907 494,018 Retained earnings 66,968 61,515 62,542 57,983 '9,710 17,617 Total common shareholders'quity 658,500 590,854 578,930 571,543 . 544,61 7 511,635 Total Capitalization 1,438;380 1,390,176 1,397,542 1,433,170 1,434,593',474,758 Long Term Liabilities (Department of Ln'ergy) 94,602 63,626 59,989 55,502 51,016 47,773 Current Liabilities 267,277 267,601 183,720 137,899 126,661 89,308 Deferred Credits and Otlier Liabilities 249,183 232,393 223,208 212,800 213,461 178 905 Total Capitalization and Liabilities $ 2,049,442 $ 1,953,796 $ 1,864,459 $ 1,839,371 $ 1,825,731 $ 1,790,744 Financial Data At December 31 1992 1991 1990 1989 1988 1987

,Capitalization Ratios(a) (percent)

Long term debt, 48.2 50.6 53.6 55.1 56.8 58.7 Preferred stock 8.0 6.7 6.5 6.5 7.7 Common shareholders'quity 43.8 40.7 39.7 '.7 38.4 36.7 33.6 Total 100.0 100.0 100.0 100.0 100.0 100.0 Book Value per Common Share Year End,. $ 18.92 $ 18.41 $ 18.42 $ 18.28 $ 17.69 $ 16.98 Rate of Return on Average Common Equity, (percent), 9.98 8.60 9.29 11.56(b) 12.68 12.45(b)

Lmbedded Cost ofSenior Capital (percent)

Long term debt I 7.91 8.32 8.59 8,74 8.71, 8.90 Preferred stock. '.98 6.97 6.72 6.72 6.72 7.09 Effective Federal Income Tax Rate (percent) 35.9 33.9 34.8 339 33.9 61.3 Depreciation Rate (percent) Electric 2.69 3.05 3.33 3.25 3.56 3.50 Gas 2.78 '.94 2.94 2.96 2.96 2.98 Interest Coverages(b)(c)

Before federal income taxies (incld. AFUDC) 2.74 2.38 2.32 2.53 2.53 2.55 (excld. AFUDC) -2.70 2.33 " 2.25 2.47 2.45 After federal income taxes (incld. AFUDC)

(excld. AFUDC) '.08 2.12 1.91 1.86

~ 1.86 1.78

~

'.02 1.96 (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 rcdcemable within one year.

2.48'.01 1.96 1.93 1.83 (b)Excludes disallowed Nine Mile Two plant costs written off in 1989 and 1987.

(c)The recognition by the Company in 1991 of a fuel procurement audit approved by the New York State Public Service Commission (PSC) has been excluded from 1991 coverages. Likewise, recognition by the Company in 1992 of disallowed ic'e stornt costs as approved by the PSC has been excluded from 1992 coverages.

/

Year Ended December 31 1992 1991 1990 1989 1988 1987 Electric Revenue (000's)

Residential $ 220,866 $ 212,327 $ 197,612 $ 191,732 $ 188,451 $ 178,933 Commercial 184,815 181,56'l 165,445 155,076 149,663, 146,138 Industrial 142,392 141,001 130,012 124,634 -

120,490 118,479 Other (Includes Unbilled Revenue) 60,194 54,041 58,861 71,654 56,033 45,816 Electric revenue from our customers 608,267 588,930 551,930 543,096 514,637 489,366 Other electric utilities 25,541 28,612 42,465 38,028 29,966 26,215 Total electric revenue 633,808 617542 594,395 581,124 544,603 515581 Electric Expense (000's)

Fuel used in electric generation 48,376 65,105 76,420 75,873 65,787 61,443 Purchased electricity 29,706 27,683 34,264 39,645 30,299 26,467 Other operation 183,118 168,610 155,289 137,458 124,871 126,320 Maintenance 53,714 57,032 53,880 55,9)5 44,060 37,641 Depreciation and Amortization 73.'213 72,746 67,302 65,287 60,444 46,776 Taxes local, state and other 94,841 86,925 77,323 71,361 66,426 61,504 Total electric expense 482,968 478,101 464,478 445,539 391,887 360,151 Operating Income before Federal Income Tax 150,840 139,441 129,917 135,585 152,716 155,430 Federal income tax 38,046 '1,390 30,670 29,887 34,093 48,788 Operating Income from Electric Operations (000's) $ 112,794 $ 108,051 $ 99,247 $ 105,698 $ 118,623 $ 106,642 Electric Operating Ratr'o % 49.7 51.6 53.8 53.2 48.7 48.9 Electric Sales IAVH(000's)

Residential 2,084,466 2,085,429 2,075,072 2,072,047 2,051,808 1,970,345 Commercial 1,937,950 1,928,730 1,897,583 1,832,521 1,792,162 1,732,939 Industrial 1,929,498 1,917,796 1,931,633 1,9066429 1,869,417 1,782,223 Other 503,330 507,765 490,077 491,905 483,730 463,256 Total billed 6,455,244 6,439,720 6,394,365 6,302,902 6,197,117 5,948,763 Unbilled sales 742 7,657 (25,421) 33,406 Total customer sales 6,455,986 6,447,377 6,368,944 6,336,308 6,197,117 5,948,763

'ther electric utilities 1,062,738 ',034,370 1,316,379 1,255,282 1,149,900 1,047,654 Total electric sales 7,518,724 7,481,747 7,685,323 7,591,590 7,347,017 6,996,417 Electric Customers at December 31 Residential 300,344 298,440 296,110 293,418 290,037 285,988 Commercial 29,339 28,856 28,804 28,386 27,888 27,383 Industrial 1,386 1,388 1,428 1,422 1,392 1,381 Other- 2,605 2,558 2,553 2,512 2,326 2,281 Total electric customers 333,674 331,242 328,895 325,738 321;643 317,033 Electricity Generated and Purchased lAVH(000's)

Fossil 2,197,757 2,146,664 2,505,110 2,578,006 2,214,588 1,877,922 Nuclear 4,191,035 4,391,480 4,016,721 3,659,185 3,884,884 3,793,021 Hydro ~ 278,318 174,239 244,539 175,085 169,002 223,958 Pumped storage 226,391 240,206 269,966 290,582 292,305 246,925 Less energy for pumping ~ (344,245) (364,520) (405,966) (429,895) (430,401) (387,546)

Other 811 1,269 20,408 54,893 2,195 . 4,554 Total generated Net 6,550,067 6,589,338 6,650,778 6,327,856 6,132,573 5,758,834 Purchased 1,389,875 1,451,208 1.498,089 ',757,413 1,705,755 1,703,411 Total electric energy 7,939,942 8,040,546 8,148,867 8,085,269 7,838,328 7,462,245 System Net Capability-IAVat December 31 Fossil 541,000 541,000 541,000 541,000 541)000 541,000 Nuclear 617,000 622,000 621,000 =

621,000 621,000 470,000 Hydro 47,000 47,000 47,000 ~

47,000 47,000 47,000 Other- 29,000 29,000 29,000 29,000 29,000 29,000 Purchased 348,000 354,000 356,000 369,000 360,000 363,000 Total system net capability 1,582,000 1,593,000 1,594,000 1,607,000 1,598,000 1,450,000 Net Peak Load KW 1,252,000 1,297,000 1,208,000 1,249,000 1,275,000 1,205,000 Annual Load Factor Net % 62.5 61.7 64.6 62.4 59.7 60.8

Year Ended December 31 1992 1991 1990 1989 1988 1987 Gas Revenue (000's)

Residential $ 6,456 $ 6,354 $ 6,508 $ 6,770 $ 6,439 $ 6,436 Residential spaceheating 183,405 157,458 s159,501 165,832 150,383 138,552 Commercial 44,274 40,196 43,534 46,897 44,781 s43,311 Industrial 6,418 6,761 9,674 9,371 9,859 10,842 Municipal and other (Includes Unbilled Revenue) 21,171 24,959 17,279 35,703 19,755 19,267 Total gas revenue 261,724 '235,728 236,496 264,573 231,217 218,408 Gas Expense (000's)

Gas purchased for resale- 141,291 129,779 132,512 152,623 129,596 124,086 Other operation 43,506 39;830 39,307 36,306 34,818 32,850 Maintenance 9,006 8,383 8,510 8,401 8,515 8,483 Depreciation 11,815 11,435 9,776 9,259 8,754

'0,465 Taxes local, state and other 29,411 26,724 23.711 23,980 22,209 21,365 Total gas expense 235,029 216,151 214,505 231,086 . 204,397 195,538 Operating Income before Federal Income Tax 26,695 19,577 21,991 33,487 26,820 22,870 Federal income tax 5,545 2,869 3,820 7,952 6,569 ',137 Operating Income from Gas Operations (000's) $ 21,150 $ 16,708 $ 18,171 $ 25,535 $ 20,251 $ 15,733-Gas'Operating Ratio % 74.1 75.5 76.3 74.6 74.8 75.7 Gas Sales Tiierms (000's)

Residential 8,780 9,068 9,644 10,321 10,374 10,255 Residential spaceheating 287,614 253,655 262,458 277,267 267,697 244,655 Commercial 78,993 71,509 77,617 84,152 86,413 83,167 Industrial 12,437 13,000 18,536 17,873 20,174 22,033 Municipal 11,410 10,580 13,350 12,319 15,514 17,985

- Total billed 399,234 357,812 381,605 401,932 400,172 378,095 Unbilled sales 13 3,291 (22,840) 20,320 Total gas sales 399,247 361,103 358,765 ~ 422,252 400,172 378,095 Transportation of customer-owned gas 127,196 109,835 101,985 105,303 83,594 67,496 Total gas sold and transported 526,443 470,938 460,750 527,555 483,766 445,591 Gas Customers at December 31 Residential 19,114 21,448 22,410 23,321 24,139 24,834 "Residential spaceheating 228,096 222,918 219,242 215,120 210,710 206,458 Commercial 18,378 18,151 17,920 17,677 17,213 16,771 Industrial 932 921 960 1,095 1,042 1,035 Municipal 1,010 983 984 1,067 1,039 1,026 Transportation 424 423 401 367 270 147 Total gas customers 267,954 264,844 261,917 258,647 254,413 250,271.

. Gas Therms (000's)

Purchased for resale 360;493 384,643 366,684 426,941 408,0444 381,632 Gas from storage 53,757 16,755 Other 1,059 1,140 2,525 1,764 1,967 2,317 Total gas available 415,309 402,538 369,209 428,705 410,011 383,949 4

Cost of gas per therm (excluding gas from storage) 32.67t! 33.43) 36.03) =

35.74t6 31.7616 32.51l!

Total Daily Capacity-Therms at December 31~ 4,485,000 4,485,000 4,485,000 4,485,000 4,485,000 4,485,000 Maximum daily throughput Therms 3,768,470 3,539,260 3,539,820 3,719,050 3,744,500 3,443,240 Degree Days (Calendar Month)

For the period 6,981 6,146 5,924 7,109 6,862 6,423 Percent colder (warmer) than, normal 3.4 (8.4) (1 1.8) 5.9 1.6 (4.3) 6'Method for determining daily capacity, based on current ssiwork sssiysis, reflects the maximum dsmssd which ihe transmission systems can accept without a deficiency.

l3ttot Cttt Gttllttl (as ofJanuary 1, 1993)

Keith W. Amish Hatacha P. Dykman Constance M. Mitchell Former Vice Chairman of the Board, Former Chairman of the Former Program Director, Rochester Gas and Electric Corporation Board of Trustees, Industrial Management Council of Center for Governmental Research, Inc. Rochester, New York, Inc.

Nlllam Balderston ill Executive Vice President, Nlliam F. Fowble Cornelius J. Nurilhy The Chase Manhattan Corporation Senior Vice President and Senior Vice President, Executive Vice President, Imaging, Goodrich & Sherwood Company Paul N Brlggs Eastman Kodak Company Chairman of the Executive and Arthur N. Richardson Finance Committee, Jay T. Holmes President, Rochester Gas and Electric Corporation Senior Vice President-Corporate Richardson Capital Corporation Angelo J. Chlarella Affairs and Secretary, N. Richard Rose Bausch & Lomb Incorporated President and Chief Executive Officer, Former President, Midtown Holdings Corp. Roger N Kober Rochester Institute of Technology Allan E. Dugan Chairman of the Board, President Harry G. Saddock and Chief Executive Officer, Senior Vice President, Former Chairman of the Board and Rochester Gas and Electric Corporation . Chief Executive Officer, Corporate Strategic Services, Xerox Corporation Theodore t.. Levlnson Rochester Gas and Electric Corporation Former President and Chief Executive Officer, Star Supermarkets, Inc.

Committees of the Board of Directors Execurtve An+ FiNANce Avnrr Coatillrrree 0'r MANACLE!ENr Keiih W. Amish Paul W. Bilges William Balderston III William Baldcrsion III Angelo J. Chiarella Paul W. Briggs*

Paul W. Briggs~ Allan E. Dugan William F. Fowb!e Allan F Dugan Naiacha P. Dykman* Comelius J. Murphy

~ Roger W. Kober William F." Fowble Arthur M. Richardson Cornelius J. Murphy Theodore L Levinson M. Richard Rose Arthur M. Richardson Constance M. Mitchell Hany G. Saddock M. Richard Rose NOMrNATING William Baldersion III Naiacha P. Dykman Jay T.Holmes p Constance M. Mitchell Arthur M. Richardson* "

'Chairman Harry G. Saddock

'.(ttmall (as ofJanuary 1, 1993)

Roger R Keber David C. Helllgman Daniel J. Baler Chairman of the Board, President and Vice President, Assistant Controller Chief Executive Officer Secretary and Treasurer Age 46, Years of Service, 9 Age 59, Years of Service, 27 Age 52, Years of Service, 29 John M. Kuebel RobertC. Henderson Robert C. Mecredy Auditor Senior Vice President, Vice President, Age 57, Years of Service, 28 Controller and Chief Financial Officer Ginna Nuclear Production Age 52, Years of Service, 29 Age 47, Years of Service, 21 Thomas S. Richards David K. Lanlak lYilfredJ. Schrouder, Jr. General Counsel Senior Vice President, Gas, Electric Vice President, Age 49, Years of Service, 1 Distribution and Customer Services Employee Relations, Public Affairs and Age 57, Years of Service, 38 Materials Management Age 51, Years of Seivice, 30 Robert E. Smith Senior Vice President, Production and Engineering Age 55, Years of Service, 33 El Prioredooreeyeledpoper. ~mj

Requests for Information Duplicate Mailings Investors and security analysts Shareholders with more than one seeking information about the accou'nt generally receive duplicate Company should contact David C. mailings of annual and other reports.

Heiligman, Vice President, Secretary To eliminate additional mailings, and Treasurer. write to our transfer agent. Enclose labels or label information, where Form fD.ffAnnual Report possible. Separate dividend checks Shareholders may obtain a copy of and proxy material will continue to be the Company's 1992 annual report sent for each account of record.

on Form 10-K, as filed with the Securities and Exchange Commis- Stock Listings sion, without charge, by writing to RG&E's Common Stock is listed on the Secretary. the New York Stock Exchange and is identified by the stock symbol RGS.

Shareholder Services The Preferred Stock issues are traded Shareholders with questions about on the over-the-counter market.

dividend payments, address changes, missing certificates, ownership Corporate Office changes and other account informa- Rochester Gas and tion should contact our transfer Electric Corporation agent. 89 East Avenue Rochester, NY 14649 Dividend Payment Dates RG&E's Board of Directors meets (716) 546-2700 quarterly to consider the payment of Agent for Automatic dividends. Dividends on Common Dividend Reinvestment and Stock are normally paid on or about Stock Purchase Plan the 25th of January, April, July and The First National Bank of Boston October. Dividends on the Preferred Dividend Reinvestment Unit Stocks are payable, as declared, on Mail Stop: 45-01-06 or about the 1st of March, June, P.O. Box 1681 September and December. Boston, MA 02105-1681 (800) 442-2001 Dividend Direct Deposit Shareholders can elect to have their Transfer Agent and Registrar quarterly cash dividends electroni- The First National Bank of Boston cally deposited into their personal Shareholder Services Division bank accounts. Deposits are made on Mail Stop: 45-02-09 the date the dividend is payable. If P.O. Box 644 you would like to take advantage of Boston, MA 02102-0644 this service, contact our transfer (800) 442-2001 agent. Mortgage Bond Trustee

'irst Dividend Reinvestment and Paying Agent Common Stock shareholders who Bankers Trust Company wish to acquire additional shares free Attn: Security Holder Relations of brokerage commissions or service P.O. Box 9006 charges are invited to join RG&E's Church Street Station Automatic Dividend Reinvestment New York, NY 10249 and Stock Purchase Plan. Under the (800) 735-7777 plan, shareholders authorize an inde-pendent agent to purchase shares of RG&E Common Stock with their cash dividends. Shareholders may also participate in the plan by making optional cash payments, even ifthey decide not to reinvest their dividends.

For further information, contact our transfer agent.

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