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:
Shared Package
ML17058B768	List: ML17058B767 ML17058B769 ML17058B770 ML17058B771 ML17058B772 ML20036B498
References
NUDOCS 9305240313
Download: ML17058B772 (64)

Text

ROCHESTER GAS ANDELECTRIC CORPORATION ANNUAL REPORT 1992

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

The Company's territory, which has a population ofapproximately 920,000, is well diversified among residential, commercial and indus-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 oflight from RG&E's laser show at the recently restored High Falls area'f downtown Rochester. As part ofa hydroelectric relicensing community improvement program, RG&E created the spectacular lightshowin 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 ofperformances 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 ofthe elaborate visual display are controlled from here.

(SHOWN RIGHT)A look out ofthe control room.

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

Statement of Cash Flows 32 33 Notes to Financial Statements 34-49 Report of Independent Accountants 49 Report of Management

, Interim Financial Data Common Stock and Dividends 50 50 Selected Financial Data 0

8 Electric Department Statistics 52-53 Gas Department Statistics

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llse of 1992 Revenue Dollar Taxes Other Operations Purchased Gas 18C 17C 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 Financial Reports Directors and Officers 30 31 Investor Information Inside Back Cover

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

Operating revenues: Electric Gas Operating expenses Operating income Net income Earnings applicable to common stock Rate ofreturn on average common equity Common Stock Data Weighted average number of shares outstanding (thousands)

Per common share:

Earnings Dividends Book Value (year end)

Year-end market price Operating Data Sales (thousands)

Kilowatt-hours to customers Kilowatt-hours to other utilities Therms of gas sold and transported Customers (year end)

Electric Gas Construction expenditures, less allowance for funds used during construction (thousands)

Employees (year end)

$633,808

$261,724

$761,588

$133,944 S 70,439 S 62,149 9.98%

$617,542 i

$235,728

$728,511

$124,759

$ 57,997

$ 51,034 8.60%

33,258 31,794

$1.86

$1.68

$18.92

$24.50

$1.6t)

$1.62

$18.41

$23.25 333,674 267,954

$125,205 2,702 331,242 264,844

$124,057 2;755 6,455,986 6,447,377 1,062,738 1,034,370 526,443 470,938 3

11 5

7 21 22 16 16 4

3 5

3 12 1

(2)

Rochester Gas erat Bcctrie Corporation a

ast year Iwrote 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 ofcompetitiveness, streamlining ofoperations, and eliminating layers ofbureaucracy." To improve the way we do business, I said our most important short-term goal is to fortifyour pledge to customer satisfaction. We want to become partners with our customers. As the partner-ships take place, the balance ofour ambi-tious business plan willcome into reach.

We want RG&E to be a leader in the new competitive environment.

Well, we'e on our way. We met most of our 1992 objectives in the new Corporate Business Plan. But, to me, that achievement is not nearly as important or revealing as the reform in management philosophy that is taking place here. We had talked about breaking out ofthe obsolescent "utility mentality" mold. It's no longer talk; we'e doing it!

PROFITABILITY Let's start with financial performance; probably your main concern as a share-holder. Ifyou'e read our 1992 fourth-quarter and year-end fiscal report you already know our reported earnings are up from 1991. That's a good result when we consider the write-offfor some disallowed costs stemming from the 1991 ice storm and a cool summer that drew down heavily on air conditioning electric revenues.

Roger 0 Koher, Chairman ofthe Board, President and ChiefExecotint Officer Revenues were offat mid year. I called for expense reductions and asked our people to try to offset what the ice storm write-offand unfavorable weather were taking away. They came through for us. Their efforts made the difference. While I and the Executive Management Team take credit for aggres-sively promoting thoughtful change in the way we do business, itwas the determination ofRG&E people that really turned things around in 1992.

When you think about it, that call to action was a corporate milestone. You see, we assumed responsibility within the company forunpredictable, adverse events and still managed to increase shareholder earnings.

That management strategy has not too often been applied in the natural monopoly envi-ronment ofthe utilitybusiness.

The strategy is consistent with our intent to break away from the old, more vulnerable utilitybusiness mentality. This is a driving force in the new thinking that is moving Rochcarcr Gaa araa Breccia Corporarroo

RGB to the leading edge ofutilityreform, ensuring our place in the rapidly shifting utilitybusiness climate.

We are more competitive. We are looking for more ways to work with customers who willhave a choice ofenergy supplier.

We are building partnerships with our customers and our regulators to help us run a solvent business.

RESOURCE PLANNING In this report last year I described our Corporate Business Plan and its major objec-tives. In 1992 we constructed a companion landmark plan that is the basis forcharting the successful future ofour operations.

Our Integrated Resource Plan gRP) is one ofthe most comprehensive and innovative approaches to long-range electric supply strategies.

In our IRP we applied exhaustive study to the components ofour operations. Each ofour owned-and-operated electric gener-ating facilities was subjected to intense cost-benefit analyses based on projected lifetimes, fuel, operating expenses, capital costs and environmental considerations.

Other potential sources ofpower were factored in, such as electric load control through our energy management efforts that can control energy requirements and fore-stall power plant construction. Electric power potential from cogenerators in the private sector was calculated as well.

Afterclosely examining all the individual pieces, we assembled more than a dozen comprehensive scenarios. The idea was to minimize costs to the customer while providing an attractive rate ofreturn for investors and producing environmental benefits for the communities. We'e saying "that's being competitive!"

We'e not the only power company with an IRP, but there is at least one wrinkle that Ithink sets us apart. Ifit's unusual for a power company to consider embracing potential competitors in energy supply, then our IRP is unusual. We are seeking active partnerships with industrial and commercial customers in workable energy-producing projects.

...it was the determination of RG&Epeople that really turned things around in 1992.

Partnerships with customers may result in RGkE operating customers'lectric gener-ating or cogenerating equipment. We may become part owners with customers in energy-producing projects or even own the whole facilityunder a contractual relation-ship with an industrial, commercial or insti-tutional customer. Another example is our partnership in the Empire State Pipeline that willoffer an alternative natural gas supply in upstate New York.

This all has to do with new ways of thinking. To prepare for the new utilityenvi-ronment and remain competitive we'e finding ways to do things better. Where other gas and electric companies may see obsta-cles, we see opportunities. It's all part ofour commitment to the goals ofthe Corporate Business Plan that center largely on price of product, customer satisfaction and financial reward forshareholders.

WHERE DO WE DRAWTHE LINE?

In line with our departure from traditional utilitythinking, we are taking a critical look at the components ofour business. Ifa component is shown not to be competitive we willdo one oftwo things. Either we will make that operation competitive, or we'l get Roeheeeee Gee ood Becuie Cceteeeeioo

rid ofit. The principle is simple; ifa unit can't continue to contribute to a company's success, it's no longer an asset; it's a liability.You keep assets and get rid ofliabilities.

CASE IN POINT Our Ginna nuclear power plant is more than 20 years old. It has served our customers well since itfirstwent into commercial operation in 1970, economically and competitively producing halfofour customers'lectric power needs. I said our IRP closely studied the useful futures ofour power plants. The IRP examined the remaining operating lifeofthe Ginna plant to the expiration ofits license in the year 2009.

The strategy is consistent with ourintent to break away from the oM, more vulnerable utility business mentality...

Three options were open forthe Ginna plant. One was to shut the plant down.

Another was to continue to operate the plant with the existing and aging steam generators until 2009 at reduced efficiencies. Replacing the steam generators was the third.

No scenario showed any benefit for the customers in shutting the plant down, so that option was set aside. Continuing to operate the plant with the original steam generators showed, under close examination, that there would be no cost saving, and that declining generating capacity would likely require replacement power from fossil-fired stations with attending air-quality impact.

In contrast, replacement ofthe steam genera-tors could restore declining electric capacity at the plant, better ensure reliability, reduce planned shutdowns forrefueling and maintenance and save our customers

$30 millionby the year 2009.

Applying the criterion ofinsisting that an asset remain an asset, we decided to replace the steam generators. Preliminary work began this year with actual replace-ment scheduled for 1996. The project willcost $ 115 millionover four years.

Here's some further evidence ofour redirected thinking. Our contracts for the steam generator replacement call forthe contractors to absorb any cost overruns, and set incentives to complete the job on h

schedule. That's become the corporate policy in dealing with vendors. We'e running our place like a business and we expect the same from our suppliers.

ONE-STOP SHOPPING Customer satisfaction is at the root ofour business reform at RGAE. In 1992, we further obligated our corporate culture to improve customer service. Customer contact training programs have been intensified.

Acustomer satisfaction communications program was started so that employees can track measurable results. We look forbetter ways to accommodate our customers residential, commercial, industrial, institu-tional and municipal alike.

We ask ourselves tough questions. Why, for example, should itbe that a gas and electric company performs customer services on its own schedule? How about thinking about the customer's schedule and the customer's convenience? And, why should itbe that a customer sometimes has to make several calls or be shuffled from one service department to another to get what they want? And, where is itwritten that our connection with our customers ends at the meter? We have to minimize what has to be

done to serve customers and offerbetter ways forcustomers to do business with us.

Here's one thing we came up with. We'e designing a customer service concept that

'we call "One-Stop Shopping." Anew orga-nizational structure, drawn from existing departments and personnel, is being set into place so that an RG&E customer can always make just one call or visit us and get their business taken care right there and then.

Our One-Stop Shopping plan starts this year. We have leased a commercial complex in Rochester that willhouse the One-Stop resources under one roof. We think meshing the components ofcustomer service into a new structure at a common location will produce impressive results. The new facility is expected to be fullystaffed and functional this year.

WHERE IT'S ALLGOING This business is changing fast, and we'e trying to place RG&E in the best position to take advantage ofthe opportunities out there. Innovation, action and employee commitment are key to our progress.

We'e separating ourselves from the old utilitybusiness that too often relied on regu-lators to help cover costs and not often enough on effective, strategic thinking. We are moving beyond regulation so that we willbecome what weplan to do, not what we'e told to do.

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-tive ofjoining the interests ofthe company and our customers by improving ser vice and controlling costs.

To help shape RG&Eforthe future, Iestablished a nine-member Executive Management Team reporting directly to me.

This group ofexecutives represents a depar-ture from the more traditionally narrow scope ofutilitymanagement in the old marketplace that was free from competition.

Itis a team concept in which the members have accepted a willingness to change business operations; to constantly reinvent the way we do business. We believe good performance breeds good business, and we Where other gas and electric companies may see obstacles, ve see opportllnities.

believe we'e on the way to becoming a gas and electric company that willflourish in the new world ofutilityoperations. To sum up our real success in 1992, I say this. "In 1992 RG&E got hold ofits future."

And, as for the immediate future as we see it, we are responding to three critical areas in our business. We willincrease customer satisfaction, become more cost competitive, and we willgrow this business.

In the theme section ofthis report that follows this letter we describe and illustrate some progress in energy management and employee achievement that is putting us in the lead ofthe changing gas and electric business. Following the theme section is our Management's Discussion and Analysis report where you'l find our 1992 operations and results covered in detail.

(ul/

Roger W. Kober Chairman ofthe Board, President and Chief Executive Officer February 3, 1993 Rochester Gaa teat Etectric Corpcratioa

Customer satisfactionis at the core ofour vision. Satisfied customers are the best guarantee fora healthy corporate future that advances public acceptance, competitive prices, employee effectiveness and attractive financial performance. Our f993 Corporate Business Plan plainlystates the corporate direction.

"Ourfirstpriorityisproviding as the supplier ofchoice 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 fortheir energy dollar.

COMMERCIAL& INDUSTRIAL 0

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ase-Hoyt operates a large printing complex in the Rochester area. The company was planning an expansion ofthe facilitybut there was some thought on the part ofthe 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-ment. Afteran energy audit, we made recommendations and provided technical support and cash incentives forenergy-efficient equip-ment and lighting that are substan-tiallycutting Case-Hoyt's energy bills. The reduced costs ofoperating, due to RGEcE's energy management programs, allow Case-Hoyt to put the savings into other prograiils 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&Eforchillers, motor drives and lighting. Energy savings are substantial here, too.

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

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ur partnerships with institutional customers brought more efficient lighting, motors and special energy-efficient equipment to many schools such as Greece Athena High School pictured in this report. AtGreece Athena RG&Eprovided engineering and incentives for state-of-the-art, natural-gas-fueled equipment that offers cost-saving building air condi-tioning while heating the school's swimming pool.

n a smaller scale, a family-owned bike repair shop received added energy product value from us in the form ofimproved, energy-efficient lighting. More than 2,000 commercial and industrial customers benefited from RGBs energy utilization programs in 1992.

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

Greece Athena High School found energy savings witha natural-gas-fueled chillerthat helps aircondition 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 second refrigerator operating in the basement or garage. The older models are neither energy efficient nor often used for much. People hang on to them because it's not easy to get rid ofthem. You have to pay a company to pick them up and dispose ofthem in an environmen-tally acceptable manner. ~ In an advertising campaign we call these second refrigerators "energy hogs,"

and we offer our residential electric 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 ofthem in an environmentally approved manner. As ofyew-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

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

Last year, 2,573 customers took advantage ofthe offers. ~ We are giving rebates forqualifying high-efficiency central air conditioning systems, heat pumps and electric water heaters. More than 1,000 residential customers took advantage ofthese offers last year.

~ In all, energy partnerships with customers are producing annual energy savings of69,745,000 kilowatt-hours. That's enough elec-tricityto power 10,000 homes for a year. And, that's better value forour customers'nergy dollar, a key part ofcustomer service, and another step forward in controlling the higher costs ofenergy.

4-Residential electric customers take advantage ofincentives to switch from electric appliances to gas appliances. Picturedis a customer whois switching from electric coi% to gas burners.

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IDEAS THATARE PAYING OFF ooking forbetter ways to do things is another key to success.

Our Employee Suggestion Program offers a formal channel where employees can contribute ideas that may reduce costs and improve productivity. While working on a scheduled refueling, maintenance and inspection outage at the Ginna nuclear power plant, some RG&E people thought ofa way to improve the steam generator tube sleeving process. Sleeving restores tube strength and helps maintain steam generator efficiency. In that process, technicians enter the steam generators to operate sleeving equipment. They are exposed to very low levels of radiation. The exposure is closely monitored, and as workers approach the conservative, safe limit ofaccumulated dose, they have to be replaced. ~ Three inventive RG&Eemployees working at the plant came up with a special fitting gC 1

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II for a sleeving mechanism that cuts the time technicians spend inside the steam generators, increasing their productive time on the job.

They fabricated the tool in an RG&Emachine shop.

~ Another idea is saving nearly $70,000.

Afew electric substa-tion people thought they could make barrier board gaskets right at RG&Erather than ordering them from a supplier. These gaskets, costing more 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&Efor 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 ideas adopted are saving the company more than $500,000 a year. And 1993 is offto 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 forour customers, and better ways ofdoing things are moving us along well in our goal ofimproved customer satisfaction as their energy supplier ofchoice.

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 fornuclear plant contractors to take placeinjust three days, producing a potential annual savings ofmore 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 picturedj was the thirdin this team of inventors. (page 12)

he followingis Management's assessment of significant factors which have affected the Company's financial condition and operating results.

Liquidityand Capital Resources During 1992 cash flowfrom operations, together with proceeds from external financing activity (see Statement of Cash Flows, page 33) provided the funds for construction expenditures and the retirement and refinancing of long-term debt. Addi-tional external financing during 1993 is anticipated by the Company to satisfy capital requirements, including security maturities and sinking fund obligations.

Projected Capital and Other Requirements.

The Company continues to make gener-ating plant modifications and its construction program focuses on the need to serve new customers, to provide for the replacement of obsolete or inefficient utilityproperty and to modify facilities consistent with the most current environmental and safety regulations.

Nuclear plant expenditures to meet the Company's commitment to maintain a high level of nuclear safety and performance and to satisfy regulatory requirements and industry standards are reflected in its projected construction program. Construction requirements also include additional expen-ditures to be made at the Company's fossil-fueled and hydro generating plants.

The Company has no current plans to install additional baseload generation. The Company has accepted bids and is contin-uing negotiations for the addition of approxi-mately 24 megawatts ofcapacity savings to be phased-in over the 1993-1995 period and, beginning in 1994, expects approximately 55 megawatts of capacity to be supplied by a cogenerator under contract with the Company.

In June 1992 the Company filed with the New York State Public Service Commission (PSC) an Integrated Resource Plan (IRP) which is a long-range plan used to examine options for the future with regard to gener-ating resources and alternative methods of meeting electric capacity requirements. The plan covers a 15-year period, beginning in 1992, and provides current strategies and alternatives for meeting the Company's customers'nergy requirements in a changing business and technological envi-ronment. The IRP takes into account antici-pated capacity requirements and available resource options, as well as factors such as reliability, price of product, public accep-tance, financial integrity, environmental issues, the competitive marketplace, demand side management and potential new technologies.

One result of the IRP was the decision made by the Company in December 1992 to replace the two steam generators at the Ginna nuclear plant in 1996. Like similar plants, the Ginna nuclear plant has experienced degra-dation in some of the tubes that make up each steam generator. About 30 percent of these tubes have required repair. In addition, a chemical buildup in some of the tubes has reduced their heat transfer capability. Both conditions would continue to erode the plant's performance ifthe existing steam generators were left in place. Installation of new steam generators was the most cost-effective, reliable and environmentally compatible option for the plant evaluated as part of the IRP. The new steam generators should result in reduced maintenance costs and help sustain a high level of plant avail-ability. Cost of replacement is estimated at

$ 115 million, with preparation to begin during the plant's routine 1993 fuel outage.

Outlined below are other results of the IRP process to date:

~ The plan calls for evaluating the possibility ofusing either alternative generation or current generating equipment in partnership with certain large industrial customers.

~ The Company willcontinue to use demand side management programs to reduce the need for generating capacity.

~ The Company willconsider phasing out our coal-fired Beebee Station by the year 2000, unless it is converted to natural gas and operated under a partnership arrangement with a large customer.

~ Two of the four units at the Company's coal-fired Russell Station are expected to be converted to burn low-sulfur coal by the year 2000. The remaining two units will either be converted to burn low-sulfur coal or natural gas, or willbe phased out by that same year.

The Company has four hydroelectric generating facilities (aggregate capability of 49 megawatts) operating under licenses issued by the Federal Energy Regulatory Commission (FERC), all for terms expiring December 31, 1993. In December 1991 the Company submitted final license renewal applications to FERC for these facilities. At the expiration of the licenses, FERC may issue new licenses to the Company or, in the alternative, may issue licenses to new licensees or recommend to the United States Congress takeover of the stations by the Federal government. In the event of a takeover of a station by the Federal govern-ment or the issuance of a license to a new licensee, the Federal Power Act (FPA) provides that the Company may be compen-sated for the loss of the station in an amount to be determined by FERC. There are no competing applications. After the Company provided supplemental information, FERC accepted all four renewal applications for filingand commenced its environmental review. As a part of the FERC licensing process under the FPA, the New York State Department of Environmental Conservation (NYSDEC) recently issued certifications for each of these four hydro stations. The certifi-cations contain a wide array of conditions, some of which could be difficultand/or expensive for the Company to meet. Several ofthe conditions appear to be beyond NYSDEC's ability to impose, under present law, in such certifications. NYSDEC has requested FERC to require the same or similar measures as conditions of the FERC renewal licenses, which request the Company intends to oppose. Upon the expi-ration of its current extensions of time in which to respond to these conditions, the Company plans to request a NYSDEC hearing on them and to negotiate with the NYSDEC for their amicable resolution.

Unless so resolved or vacated through litigation, certain of the conditions would negate economic operation ofone or more of the stations and may require the Company to abandon efforts to relicense the stations so affected.

Construction is expected to begin in 1993 on the Empire State Pipeline Project (Empire), an intrastate natural gas pipeline subject to PSC regulation which is proposed to be constructed between Grand Island and Syracuse, New York. The Company is partic-ipating as an equity owner of Empire, along with subsidiaries of Coastal Corporation and Union Enterprises, LTD. In June 1991 the PSC authorized the Company to invest up to

$20 millionin Empire subject to certain conditions, notably that the investment not be included in rate base. This project will provide capacity for up to 50 percent of the Company's gas requirements by its second year of operation. The construction of Empire was approved by the PSC in March 1991 and proceedings in October 1991 for State judicial review of the PSC decision were dismissed in July 1992.

The Canadian National Energy Board in June 1992 granted authorization for TransCanada, a gas transmission company, to construct the Blackhorse extension to its existing main line in order to connect with Empire at Grand Island. The only remaining major regulatory requirements for Empire involve Corps of Engineers permits to cross navigable waters and federally-regulated wetlands and that process is underway. An inservice date for Empire ofNovember 1993 is currently anticipated. In 1992 the Company formed a wholly-owned subsidiary, Energyline Corporation, to Rochccrcr Gac arci Bccaic iArporarioo

acquire its ownership interest in Empire.

During 1992 approximately $ 10 million was invested by the Company in the Energyline Corporation, and up to an additional

$ 10 millionis expected to be invested during 1993. The Company's share of ownership in Empire willbe dependent upon final project costs and the timing and method of financing selected by the Company.

The Company's capital expenditures program is under continuous review and will be revised depending upon the progress of construction projects, customer demand for energy, rate relief, government mandates and other factors. In addition to its projected construction requirements, the Company may consider, as conditions warrant, the redemption or refinancing of certain long-term securities.

Capital Requirements and Electric Operations. Electric production plant expenditures in 1992 included $35 million of expenditures made at the Company's Ginna nuclear plant and $3 millionfor its 14 percent share of expenditures at the Nine Mile7wo nuclear facility,exclusive of fuel costs. Nuclear fuel expenditures of

$9 millionwere incurred at Ginna in 1992 and expenditures of $2 millionwere made for nuclear fuel at Nine Mile7wo. On March 4, 1992 Nine Mile7wo was taken out of service for a scheduled refueling outage.

Refueling was completed and Nine Mile7wo resumed operation on July 4, 1992. The prior refueling outage occurred from early September 1990 to month-end January 1991.

The next refueling outage for Nine Mile7wo is anticipated to begin in September 1993.

A refueling outage at Ginna normally occurs annually for a period of approximately 40 to 50 days.

Electric transmission and distribution expenditures, as presented in the table below, totaled $35 millionin 1992, of which

$30 millionwas for the upgrading ofelectric distribution facilities to meet the energy requirements of new and existing customers.

In 1992 the Company also recognized

$3.9 millionof transmission and distribution improvements, a portion of the Company's Capital Requfrements Type of Facilities Actual Projected 1990 1991 1992 1993 1994 1995 (Millionsof Dollars)

Electric Property:

Production Transmission and Distribution Street Lighting and Other Subtotal Nuclear Fuel Total Electric Gas Property Common Property Total Carrying Costs:

Allowance for Funds Used During Construction (AFUDC)

Deferred Financing Charges Included in Other Income Total Construction Requirements Securities Redemptions, Maturities and Sinking Fund Obligations*

Total Capital Requirements

<<Excludes prospective refinancings.

$ 47

$ 44

$ 47 31 29 35 2

2 2

80 75 84 7

12 11 87 87 95 20 22 19 15 13 15 122 122 129 5

4 2

3 5

3 130 131 134 28 92 160

$158

$223

$294

$ 55

$ 59

$ 60 32 35 36 2

2 2

89 96 98 15 19 14 104 115 112 17 19 24 18 12 19 139 146 155 3

3 4

1 143 149 159 116 27 9

$259

$176

$168

cost associated with a severe March 1991 ice storm (see followingparagraph).

In early March 1991, the City of Rochester, New York and surrounding counties were hit by a severe ice storm, the worst storm in the history of the Company's service territory. Pending a review at the time by the PSC of storm-related costs, as well as the Company's performance during the storm, $36.4 millionof storm-damage repair costs were reflected under deferred debits on the Company's December 31, 1991 Balance Sheet. The Company had estimated that approximately 20 percent of these deferred costs were related to capital improvements (with operating and maintenance expenses comprising the balance). In the Company's June 1992 rate decision, the PSC accepted the Company's estimated capital improve-ments and, accordingly, in 1992 the Company commenced recognizing those storm-related capital costs. The final deter-mination of the amount to be capitalized has not yet been made by the Company. Addi-tional details of the Company's June 1992 rate decision, including recovery of the 1991 storm-damage repair costs, are discussed on page 21 under the heading New York State Public Service Commission (PSC).

Capital Requirements and Gas Operations. In the Gas Department, the replacement of older cast iron mains with longer-lasting and less expensive plastic and coated steel pipe, the relocation of gas mains for highway improvement, and the installa-tion of gas services for new load resulted in construction expenditures of $ 19 millionin 1992. Following its construction during 1991 at a cost of approximately $3.3 million, a new 5.0 mile, 24-inch gas pipeline was placed in service in January 1992. This new gas connection has helped the Company improve supply reliabilityin the north-western quadrant of the Company's gas franchise area.

Environmental Issues.

The production and delivery of energy results in the emission of pollutants that may be harmful to the environment. In recogni-tion of the Company's responsibility to preserve the quality of the air, water, and land it shares with the community it serves, the Company has taken a variety of measures (e.g., self-auditing, recycling and waste mini-mization, training of employees in hazardous waste management) to reduce the potential for environmental damage from its energy operations and, specifically, to manage and appropriately dispose of wastes currently being generated. The Company, nevertheless, has been contacted, along with numerous others, concerning wastes it has sent off-site to licensed treatment, storage and disposal sites where authorities have later questioned the handling of such wastes. In such instances, the Company typically seeks to cooperate with those authorities and with other site users to develop cleanup programs and to fairly allocate the associated costs.

As a part of our commitment to environmental excellence, the Company is conducting voluntary Site Investigation and Remediation (SIR) efforts at Company-owned sites where past contaminant handling and disposal may have occurred.

The purpose of these investigations is to determine ifremedial measures are appropriate. The Company estimates spending $ 10 millionover the next 5 years on SIR initiatives.

On November 15, 1990 the Federal Clean AirAct Amendments of 1990 (Amendments) became law. The Amendments willaffect air emissions and quality control measures primarily at the Company's fossil-fueled electric generating facilities (see Note 10 of the Notes to Financial Statements). A Clean AirAct Task Force has been formed within the Company to review compliance with these requirements and is in the process of identifying the optimum mix of control measures and associated potential technology changes that willallow the fossil-fuel based

portion of the generation system to fully comply with state and federal environmental requirements. Although work is continuing, the compliance control options have not as yet been determined for the entire fossil-fueled system. More detailed compliance decisions are expected to be made by mid-1993. Capital costs, however, between

$30 million and $50 million(1992 dollars) have currently been estimated for the imple-mentation of several potential compliance scenarios. Such capital costs would be incurred between 1993 and 2000 ifthe Company elected to go forward with any such scenario. The Company currently estimates that it could also incur up to

$ 1.5 million(1992 dollars) of additional annual operating expenses, excluding fuel, to comply with the Amendments. The use of scrubbing equipment is not presently being considered. Likewise, the purchase or sale of "emission allowances", as allowed by the Amendments, is not currently being consid-ered. The Company anticipates that the costs incurred to comply with the Amendments willbe recoverable through rates based on previous rate recovery of environmental costs required by governmental authorities.

Redemption ofSecurities.

A $75 million first mortgage bond maturity and $5 millionof sinking fund obli-gations were a part of the Company's capital requirements in 1992. In addition, discre-tionary first mortgage bond redemptions totaled $79.5 millionduring 1992.

Capital requirements in 1991 included

$28 millionof sinking fund redemptions, a

$ 15 millionfirst mortgage bond maturity, and a discretionary first mortgage bond redemption of $49.3 million.

Capital Requirements Summary.

The Company's capital program is designed to maintain reliable and safe electric and natural gas service and to meet future customer service requirements. Capital requirements for the three-year period 1990 to 1992 and the current estimate ofcapital requirements through 1995 are summarized in the table on page 16.

For the period 1993 to 1995, the Company anticipates construction requirements to total approximately $450 million. Expenditures made at the Company's nuclear facilities to improve operating efficiency and reliability and to comply with regulatory requirements are a significant component of electric production plant costs over the period. Such projected plant costs include an allowance by the Company of $ 14 millionin 1993,

$20 million in 1994 and $ 15 million in 1995 for the replacement of the steam generators at the Ginna nuclear plant.

In addition to its construc-tion expenditures, the Company has security maturities and sinking fund obligations totaling

$ 152 millionover the Projected Capital Repotrements (millionsoldolloroi three-year period 1993 to 1995 as shown by the graph to the right.

Excluded from the capital requirements table on page 16 are expenditures associated with the Empire project and the Company's obligations to the United States Department of Energy for 93 94 95 0

Mandatory retirement of securities 0

Carrying costs Cl Cash expenditures for construction nuclear waste disposal and uranium enrichment decommissioning (see Notes 1 and 10 of the Notes to Financial Statements).

The AFUDC amounts included in the table on page 16 are the financing costs associated with major projects under construction. This carrying cost becomes part of the capitalized cost of the related project. The Company begins to earn a cash return on its invest-ment, including this carrying cost, when the cost of the project is included in rate base, which generally is at the time the project Roersessee Gas aan Beeseie eerrssesatess

enters service. In addition to AFUDC, carrying charges include the recognition of certain customer prepaid financing costs, as further discussed on page 23.

Embedded (Annual)

Cost of Long-Term Debt - Year End

$67

$65 8.9'/o

$63 8.7%

85%

1%

7.9'/o 7.7'/o 90 91 92 liquidity, Financing and Capital Structure.

Capital requirements in 1992 were satis-fied by a combination of long-term debt and equity issues, internally generated funds, and short-term borrowings. The Company during 1992 continued to take advantage of favorable market rates and security provisions which allow early redemption to refinance

$50 millionof its higher cost long-term debt. Such refinancing activity over the past two years has helped to reduce the annual cost

$59 a of long-term debt by approx-imately $4.5 million and ss7 contributed to a drop in the Company's embedded cost of long-term debt from 8.6% at year-end 1990 to 7.9% at the end of 1992, as illustrated by the graph to the left. Common share-holders equity increased during 1992 as the result of a public issue of two million shares of Common Stock in August.

The Company believes that an average of approximately 80 percent to 85 percent of the funds required per year for its 1993 through 1995 construction program willbe generated internally and the balance willbe obtained through the sale of securities and short-term borrowings. The Company also anticipates that the sale of securities and short-term borrowings willbe required to satisfy security maturities and sinking fund obliga-tions over the three years 1993 through 1995.

Although the Company expects to issue securities during 1993, it is the Company's intention to utilize its credit agreements to meet any interim external financing needs prior to the issue of such securities. As finan-cial market conditions warrant, the Company may, from time to time, issue securities to permit the early redemption of higher-cost senior securities. The Company's financing program is under continuous review and may be revised depending upon the level of construction, financial market conditions, rate relief, cost ofcapital and other factors.

Financing. Interim financing is available from certain domestic banks in the form of short-term borrowings under a $90 million revolving credit agreement which continues until December 31, 1995 and may be extended annually. Borrowings under this agreement are secured by a subordinate mortgage on substantially all property except cash and accounts receivable. Additional borrowing capability for up to $20 millionof short-term debt is also available under a separate credit agreement with a domestic bank. Borrowings under this agreement, which can be renewed annually, are secured by the Company's accounts receivable. Also, beginning in August 1992, additional unse-cured short-term borrowing capacity of up to

$25 million is available from a domestic bank, at its discretion. AtDecember 31, 1992 the Company had short-term borrowings outstanding of $50.8 million, consisting of

$20.8 millionof unsecured short-term debt and $30.0 millionof secured short-term debt.

Under provisions of the Company's Certificate of Incorporation (Charter), the Company may not issue unsecured debt if immediately after such issuance the total amount of unsecured debt outstanding would exceed 15 percent of the Company's total secured indebtedness, capital, and surplus without the approval of at least a majority of the holders of outstanding Preferred Stock.

Under this restriction, the Company as of December 31, 1992 was able to issue

$45.2 millionof additional unsecured debt.

Additional interim financing capability remains available with secured borrowings under the Company's credit agreements, as discussed above.

gi

In March 1992 the Company completed the public sale of $ 100 millionprincipal amount ofFirst Mortgage 8Y% Bonds, due 2002, Series QQ. Proceeds from this financing were used to repay certain of the Company's outstanding short-term debt and to finance a portion ofthe Company's capital requirements.

In June 1992 the Company refinanced

$60.5 millionof long-term debt when it completed a public offering of $ 10.5 million First Mortgage 6.35% Bonds, Series RR, and

$50 millionFirst Mortgage 6Ya% Bonds, Series SS, both due 2032, in connection with the issuance of a like amount ofNew York State Energy Research and Development Authority Pollution Control Refunding Revenue Bonds. The proceeds were used for the early redemption of$ 10.5 millionof First Mortgage 12N% Bonds, Series HH, and a

$50 millionAnnual Adjustable Rate Promissory Note. Redemption ofthis unse-cured Promissory Note has given the Company additional financing flexibility under the terms of its Charter to issue unse-cured debt.

In August 1992 the Company issued 2,000,000 shares of new Common Stock.

The shares were offered to the public at a price of $24 per share. The offering raised

$46,460,000 in net proceeds, which were used to retire short-term debt incurred in the Company's construction program.

In September 1992 the Company filed a shelf registration with the Securities and Exchange Commission to issue up to

$200 million.of First Mortgage Bonds, Designated Secured Medium-Term Notes, on terms to be determined at the time ofsale.

This registration statement became effective October 8, 1992 and allows the Company financing flexibilityregarding the timing of new issues. The Company plans to use the net proceeds from the sale of these notes to'inance a portion of its capital requirements or to discharge or refund outstanding indebt-edness. In January 1993, the Company issued

$30 millionof such Medium-Term Notes at an annual interest rate of7.00% to refinance related costs. Likewise, 1,600 the Company recorded the effect of a fuel audit settlement with the PSC of $ 10.0 million

($6.6 millionafter tax) in December 1991. As shown by the graph to the right, common equity 400 (including retained earnings) comprised 43.8 percent of the Company's capitalization at December 31, 1992, with the balance being comprised of 8.0 percent preferred equity and 48.2 percent long-term debt. AtDecember 31, 1992 the Company had y s.o" S.

90 91 92 0

Common Equity 0

Preferred Stxk G LonpTerm0ebt

'Excludes amounts due or redeemab!e within one year.

its outstanding First Mortgage 9Ye% Bonds, Series Z.

During 1992 the Company received

$ 13.3 millionto help finance its capital expenditures program from the sale of approximately 585,000 new shares of Common Stock through its Automatic Dividend Reinvestment and Stock Purchase Plan (ADR Plan). New shares issued in 1991 and 1992,through the ADR Plan were purchased from the Company at a market price above the book value per share at the time of purchase.

Capital Structure. The Company improved its ratio ofcommon equity to total capitalization during 1992 primarily through the public sale of Common Stock as discussed earlier. The Company's retained earnings at December 31, 1992 were

$67.0 million, an increase of approximately

$5.5 millioncompared with December 31, 1991. As discussed on page 21 under the heading New York State Public Service Commission, earnings were reduced in June 1992 when the Company recorded an $8.2 million

($5.4 millionafter tax) rhoe write-offofice storm-f45

$ 110.3 millionof long-term debt due within one year and $6.0 millionof preferred stock redeemable within one year which, if included in capitalization, would increase the long-term debt component ofcapitalization at 1992 year-end to 51.5 percent, reduce the preferred equity to 7.9 percent and reduce common equity to 40.6 percent of capitaliza-tion. As presented, these percentages are based on the Company's capitalization inclu-sive of its long-term liabilityto the United States Department of Energy (DOE) for nuclear waste disposal as explained in Note 1

of the Notes to Financial Statements.

Excluded from the capitalization percentages

~i is the DOE long-term liabilityfor uranium enrichment decommissioning. It is the Company's long-term objective to move to a less leveraged capital structure and to increase the common equity percentage of capitalization toward the 45 percent range.

To improve its capital structure, the Company willconsider the redemption of higher-cost senior securities and the issuance of new shares of common stock.

Rate Base and Regulatory Policies.

The Company is subject to regulation of rates, service, and sale of securities, among other matters, by the PSC. The Company was granted authority in June 1992 to increase its rates for electric and gas service effective July 1992. These new rates were based on a forecasted test year for the twelve months ending June 30, 1993. The Company has filed a request with the PSC to increase base rates for electric and gas service effective July 1993. On January 29, 1993 the Company, the PSC Staff and other interested parties filed a proposed Settlement Agreement with the PSC. Such Settlement Agreement, ifapproved by the PSC, would determine the Company's rates through June 30, 1996 and includes certain incentive arrangements providing for both rewards and penalties. Ifoperation and maintenance costs are below projected levels, the Company will share up to 50% of the savings with its customers. Ifsuch costs exceed projections, the Company must absorb 50% to 100% ofthe additional costs. The Settlement. Agreement provides for a return on equity of 11.50% for each rate year, with the Company allowed to retain any earnings up to 14.5%. Earnings above 14.5% willbe refunded to customers.

Should earnings fall below 8.5%, or cash interest coverage fall below 2.2 times, the Settlement Agreement provides that the Company can seek relief by petitioning the PSC for a review of the settlement terms.

The Company is unable to predict whether the Settlement Agreement willbe approved by the PSC. A decision is not likely until mid-1993.

New York State Public Service Commission (PSC). Recent PSC rate deci-sions and the Company's pending rate requests are summarized in the table on page 22. The PSC concluded that the July 1992 rate increases should, for the twelve months ending June 1993, allow the Company to achieve approximately a 2.88 times pretax interest coverage, exclusive of AFUDC and the amortization of deferred Nine MileTwo customer prepaid financing costs, discussed on page 23. In addition to the amounts indicated in the table on page 22, the June 1992 PSC rate order authorized the amortization ofcertain non-cash rate moderators (primarily deferred Nine MileTwo customer prepaid financing costs) totaling $5.1 millionin the Electric Department.

In its June 1992 rate decision, the PSC allowed the Company to defer and recover through rates over a period of ten years approximately $21.3 millionof non-capital incremental storm-damage repair costs which the Company had incurred as a result of a March 1991 ice storm (see Capital Require-ments and Electric Operations). The PSC has permitted the unamortized balance of these allowed costs to be included in rate base. An additional $8.2 millionof non-capital storm-damage costs incurred by the Company were disallowed rate recovery by the PSC and the Company accordingly recorded in the second quarter of the year a charge to earnings in the RoAcs<a Cur a+i Bccuic Coqeiarion

Hate Increases Granted Class of Service Electric Gas Pending Class of Service Effective Date of Increase July 12, 1990 July 1, 1991 July 1, 1992 July 12, 1990 July 1, 1991 July 1, 1992 Date of Filing Amount of Increase (Annual Basis)

(000's)

$ 36,059 33,133 32,220 4,250 1,148 12,316 Amount oflncrease'Annual Basis)

(000's)

Percent Increase 6.6%

5.5 5.2 1.7 0.4 4.1 Percent Increase'uthorized Rate of Return on Rate Base Equity 9.91%

12.10%

9.66 11.70 9.31 11.00 9.91 12.10 9.66 11.70 9.31 11.00 Requested Rate of Return on 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

• Asamended, 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 approximately $.17 per share, net of tax.

After issuance ofthe two million shares of stock in August 1992, the net-of-tax effect for the year was $.15 per share. As previ-ously discussed, Company-estimated capital costs resulting from the ice storm were allowed rate recognition by the PSC.

Following the March 1991 ice storm, electric rates which the PSC authorized for the Company in June 1991 were made subject to a refund of $4 millioncontingent upon the filingwith the PSC of a revised storm emergency plan. In an order issued June 10, 1992, the PSC determined that this plan-filing contingency had been met and that the $4 million was no longer subject to refund.

In late July 1992 the Company filed rate requests with the PSC as summarized under the heading "Pending" in the table above.

The higher rates were requested to cover those increases in capital and operating costs projected for the rate year ending June 30, 1994 that are neither adequately provided for in present rates nor expected to be offset by increased revenues from sales.

As discussed earlier, the Company has negotiated a multi-year settlement agreement with the PSC Staff and other interested parties regarding this filing,but a final PSC decision on this filingmay not be made before June 1993.

In March 1991 the PSC issued an order regarding a settlement agreement among the Nine MileTwo owners, the PSC Staff and other intervenors resolving all open ratemaking issues with respect to the construction of the unit and its operation through January 19, 1990. Under the provi-sions of this settlement, a Nine MileTwo commercial operation date ofApril5, 1988 was recognized by the PSC with respect to the rates and accounts of the Company.

Accordingly, final accounting entries reflecting recognition of this agreement in conformity with the Uniform Systems of Accounts of the PSC were made in the first quarter of 1991 increasing electric utility plant together with a corresponding increase in accumulated depreciation. Supplemental agreements approved by the PSC in early 1992 and 1993, respectively, have estab-lished for each Nine MileTwo owner an allowed level of shared costs for ratemaking purposes through December 31, 1993.

In a series of rate orders preceding the commercial operation of Nine MileTwo, the

Company was allowed to include certain Nine MileTwo plant costs in rate base prior to commercial operation. AFUDC was not accrued on these amounts. Instead, the Company accumulated a similarly calculated amount until commercial operation and recorded it on the Balance Sheet as a deferred credit (liability),with an equivalent amount recorded as a deferred debit (asset).

The deferred credit represents customer prepaid financing costs, while the deferred debit represents financing cost (or AFUDC).

The latter is expected to be recovered over the life of the facilitythrough amortization if the PSC chooses to utilize these prepaid financing costs to moderate customer rates.

For the rate year beginning July 1992, the Company started amortizing $2.5 millionof these deferred credits to Other Income as permitted by the PSC's June 1992 rate order.

Amortization of these deferred credits to Other Income has aggregated

$21.4 million through December 31, 1992. The June 1992 rate order also authorized the Company to write off$2.5 millionof deferred and other expenses as an offset to these deferred credit balances. In the pending multi-year Settlement Agreement discussed above, no additional amounts of such deferred credits are proposed to be used through the period ending June 30, 1996.

Pursuant to an order issued by the PSC in November 1991, the Company started refunding $ 10 millionto its electric customers through adjustments to their energy bills over a twelve-month period beginning in January 1992. The PSC order approved a settlement agreement between the PSC Staff and the Company relating to the Staff's audit of the Company's fuel procure-ment practices. The Company recognized the settlement agreement in December 1991 and accordingly recorded a $6.6 millionnet-of-tax reduction to net income, thereby reducing earnings per share by approximately $.21 for the fourth quarter of 1991.

National Energy Policy Actof1992. In October 1992 the National Energy Policy Act of 1992 (Energy Act) was signed into law.

This legislation changes the Federal regula-tion of utilities in a number of ways. One provision of the Energy Act provides that United States utilities with nuclear gener-ating facilities be assessed an annual decon-tamination 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 approxi-mately $ 1.8 million for the Ginna nuclear plant and the estimated amount for its share of Nine MileTwo is approximately

$.1 million.This obligation has been reflected on the Company's December 31, 1992 Balance Sheet, together with a corresponding deferred debit based on the language of the Energy Act. The Company believes it will receive the ultimate recovery of this deferral through its fuel adjustment clause. The Company is currently reviewing other provi-sions of the Energy Act as they relate to the Company.

Results of Operations The followingfinancial review identifies the causes of significant changes in the amounts ofrevenues and expenses, comparing 1992 to 1991 and 1991 to 1990. The Notes to Financial Statements on pages 34 to 49 of this report contain additional information.

Operating Revenues and Sales.

Compared with a year earlier, operating revenues rose five percent in 1992 after increasing three percent in 1991. Gains in retail customer electric and gas revenues offset a decline in electric revenues from the sale of electric energy to other utilities.

Customer revenue increases due to rate relief were partially offset by lower gas unbilled revenues and the impact ofcolder weather on air conditioning usage. Operating revenues adjusted to exclude fuel expense were also up in 1992 as shown by the graph on page 24. Details of the revenue changes are presented in the table on page 24.

Unbilled revenues are the estimated revenues attributable to energy which has

Operating Revenues Less Fuel Expense (miiiioosor dorrsrs J Primarily as a result of the seasonal nature of gas revenues, unbilled revenues willnormally be near their maximum around January and at their minimum near the end ofJune.

The Company's fuel clause provisions currently provide that customers and share-holders willshare, generally on an 80%/20% basis, respec-tively, the benefits and detri-ments realized from actual electric fuel costs, generation mix, sales of gas to dual-fuel customers and sales ofelectricity to other utilities compared with PSC-approved forecast amounts. As a result of these sharing arrangements, discussed further in Note 1 of 90 91 92 0

Gas Revenues 0

Electric Revenues been delivered to customers but for which the metered amount has not been read and recorded on the Company's books. Such revenues do not enhance the Company's cash position. The Company records monthly accruals for unbilled revenues.

The Company's Statement of Income reflects net unbilled revenues of $5.0 millionin 1990, $2.6 millionin 1991, ar6 and $(0.8) millionin 1992.

the Notes to Financial Statements, pretax earnings were increased $2.4 millionin 1991 and increased $4.4 millionin 1992, primarily reflecting actual experience in both electric fuel costs and generation mix compared with rate assumptions. In addition, beginning in September 1990, fuel clause revenues include the recovery of margins (revenues less incremental cost of fuel) not currently provided for in base rates and which are not collected due to the implementation of the Company's energy efficiency programs (discussed below in this section). For the 1992 comparison period, fuel clause reve-nues also reflect a revenue matching adjust-ment resulting from a refund to electric customers as described in the last paragraph under the heading New York State Public Service Commission.

The effect of weather variations on oper-ating revenues is most measurable in the Gas Department, where revenues from space heating customers comprise about 85 to 90 percent of total gas operating revenues.

Variation in weather conditions can also have a meaningful impact on the volume of gas delivered and the revenues derived from the transportation ofcustomer-owned gas since a substantial portion of these gas deliveries is ultimately used for spaceheating.

As displayed by the graph to the left on page 25, Operating Reuenues 1rrcrease or (Decrease) from Prior Year (Thousands ot Dollars)

Electric Department 1992 1991 Gas Deparimenl 1992 1991 Customer Revenues (Estimated) from:

Rate Increases Unbilled Revenues, Net Fuel Clause Adjustments Weather Effects (Heating)

Customer Consumption Transportation Gas, Net Effect Other Total Change in Customer Revenues Electric Sales to Other Utilities Total Change in Operating Revenues

$30,108 2,559 (14,258) 1,636 (7,572) 6,864 19,337 (3,071) s16,266

$ 33,666 (9,894) 2,236 (204) 7,197 3,999 37,000 (13,853)

S23,1 47

$ 4,437 (5,943) 906 20,372 8,412 (6,828) 4,640 25,996

$25,996

$3,106 7,557 (4,052)

(3,333)

(3,181)

(4,036) 3,171 (768)

$ (768)

Raehouor Oas ooo Ekorric Carpororioo

after experiencing unseasonably mild weather during the 1990 and 1991 heating

seasons, weather in the Company's service area during 1992 was 3.4 percent colder than normal and 13.6 percent colder compared with 1991. While this cooler weather during 1992 enhanced gas sales, unseasonably cold summer weather during the year limited electric energy sales to meet the demand for air conditioning usage, compared with the hot, Oegree Day Variations From Normal dry 1991 summer weather conditions. Overall, 1991 was 8.4 percent warmer than normal, but 3.7 percent cooler than 1990.

As part of the June 1992 rate decision, customers who use gas for spaceheating and are provided service under Service Classification No.

1 (primarily residential customers) are subject to 4OO mP 92 9O 9'2 0 Cooling Degree Days'May-sept.)

0 Heating Degree Days'Jan..Dec.)

'Each degree olmean daily temperature above 65 degreesis considered to be one cooling degree day; below65 degreesis considered to be one heating degree day.

Normal a weather normalization adjustment to reflect the impact 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 if the actual heating degree days are lower than 97.5 percent or higher than 102.5 percent of the normal heating degree days. Weather normalization Heating Degree Days 6,713 Cooling Degree Days 63i adjuStmentS 1OWered gaS revenues in 1992 by approxi-mately $ 1.8 million.

Afterclimbing one percent in 1991, growth in kilowatt-hour sales of energy to retail customers was nearly flat in 1992 as illustrated by the graph to the right. Growth in electric energy sales in 1992 was inhibited by the impact of cooler weather during the summer months on air conditioning usage.

Electric sales to industrial customers led the increase in sales to all major customer groups in 1992; but, like 1991, the combined growth in electric sales to commercial and industrial customers was limited to approximately one percent as these customers continued to feel the constraints of the national economy.

Strengthening kilowatt-hour sales ofenergy in 1992 was the impact of nearly 2,400 new electric customers, which follows the addition of approximately 2,350 customers a

year earlier.

Like many other electric utilities, the Company is encouraging energy efficiency through demand side management (DSM) programs. Objectives of the DSM programs include increasing the efficiency with which electricity is used and shifting electric load from peak to non-peak times, thus helping to save energy and delay the need to add new gener-ating capacity. DSM programs include rebates for energy-efficient equip-et9 ment, audits which focus on potential techniques e,ooo r ass Electric Market Profile (raoosoods ormwh soldi for saving energy, consumer information and outreach, and design assistance to encourage energy-efficient new con-struction. In general, the Company is being allowed to amortize major DSM program expenditures over a five-year period.

An incentive allowance 2,000 Other Utilities Other Industrial Commercial Residential (award) of approximately 9O 91 92

$ 1.1 million was provided for in the Company's June H

1992 rate decision based on the Company's DSM 0

performance through December 31, 1991. The reduction in margins (revenues less incremental cost of fuel) resulting from the implementation of DSM projects is estimated and is recovered in rates.

Fluctuations in revenues from electric sales to other utilities are generally related to

Gas Market Profile rmillioooor raonoo sold ood rroosporrod J art the Company's customer energy requirements, New York Power Pool energy market and trans-mission conditions and the availability ofelectric genera-tion from Company facilities.

Such revenues in 1992 also reflect the sale of energy at a lower rate per megawatt hour and the impact of lower contract sales of energy. A decline in these contract sales, together with generally lower New York Power Pool requirements, led to lower kilowatt-hour sales to 90 91 92 0

Transported 0

Other 0

industrial 0

Commercial 0

Residential other utilities in 1991.

The transportation of gas for large-volume customers who are able to purchase natural gas from sources other than the Company remains an important component of the Company's marketing mix. Company facili-ties are used to transport this gas, which amounted to 12.6 million dekatherms in 1992 and 10.9 million dekatherms in 1991. These purchases have caused decreases in customer revenues, as shown in the table on page 24, with offsetting decreases in fuel expenses, but do not adversely affect earnings because trans-portation customers are billed at rates which, except for the cost of gas, approximate the rates charged the Company's other gas service customers. Gas supplies transported in this manner are not included in Company therm sales, depressing reported gas sales to non-residential customers.

Therms of gas sold and transported, including unbilled sales, were up 11.8 percent in 1992, following a 2.2 per-cent increase in 1991 as illustrated by the graph to the upper left. These increases reflect, primarily, the effect of weather variations on therm sales to customers with spaceheating. Ifadjusted for normal weather conditions, residential gas sales would have increased about 2.3 percent in 1992 over 1991, while nonresidential sales, including gas transported, in 1992 would have increased approximately 4.0 percent. The average use per residential gas customer, when adjusted for normal weather conditions was up in 1992, followinga decrease in 1991. Total therms of gas transported increased in 1992 and 1991, primarily as a result of higher sales to certain large indus-trial and municipal transportation customers.

Fluctuations in "Other" customer revenues shown in the table on page 24 for both comparison periods is largely the result of revenues associated with a New York State tax enacted in 1991 (see Taxes Charged to Operating Expense), and, variations in miscellaneous revenues and consumption (billing)days.

Operating Expenses.

Compared with the prior year, operating expenses were up 4.5 percent in 1992 following a two percent increase in 1991, as summarized in the table on page 27 and as illustrated by the graph on page 28.

Excluding the effect of higher taxes and the 1992 recognition ofcertain postretirement benefits discussed on page 28, operating expenses were up only 1.4 percent in 1992 and a modest one-half percent in 1991.

Operating expenses were increased approxi-mately $ 1.0 millionin 1992 as the Company began in July to recognize over a ten-year period the deferred March 1991 ice storm costs as allowed by the PSC (see New York State Public Service Commission).

Energy Costs Electric. For the 1992 comparison period, fuel expense for electric generation was lower by $ 16.7 milliondue, in part, to a revenue matching adjustment resulting from a refund to electric customers as described in the last paragraph under New York State Public Service Commission.

Although the Company generated less electric power in 1992, the decrease in electric fuel expense was more than the decrease in electric generation as the average cost of coal and nuclear fuel declined. For g

the 1991 comparison period, less generation from the Company's fossil-fueled units was largely responsible for the decrease in fuel expenses for electric generation.

The Company purchased fewer kilowatt-hours ofenergy in 1992 and 1991 compared with the prior year. The variation in purchased electricity expense for both comparison periods was primarily caused by a fluctuation in the average rates for purchased electricity.

Energy Costs and Supply Gas. The Company receives gas supply and related transportation services under a series of contracts with CNG Transmission Corporation (CNG). These contracts provide for a combination of unbundled services (storage and transmission of Company-purchased gas) for approximately 30% of the Company's annual gas purchases, and bundled sales services (including gas supply, storage and transmission) for the remainder of the Company's annual supplies that will not otherwise be purchased for transport to the Company via the proposed Empire project (see Projected Capital and Other Requirements). The Company expects that it willannually purchase a quantity of gas equal to 25% of the CNG bundled sales service gas supply from other sources under short-term contracts when: 1) those supplies are available at prices lower than CNG's commodity price and 2) the acquisition of those short-term supplies would not jeopar-dize the reliabilityof the Company's long-term supply or unduly increase its cost.

Under the contracts with CNG, the Company has obtained rights to 4.2 million dekatherms of CNG storage capacity. With underground natural gas storage capability, the Company is in a better position to take advantage of off-peak season purchases of gas and enhance its supply reliability to serve projected peak day requirements. Also, in connection with the Empire project, addi-tional transportation agreements have been entered into with pipelines upstream of Empire that permit the Company to directly access U.S. and Canadian natural gas supplies and storage facilities once Empire becomes operational.

ln April 1992 FERC issued Order No. 636 with the intention of fostering competition and improving access of customers to gas supply sources. In essence, FERC Order No. 636 "divests" the natural gas pipelines of sole ownership of transportation capacity rights, transfers those capacity rights, in part, to the pipelines'ustomers, and requires the pipelines to offer their services so that the reliabilityof service associated with gas from any source is equal and terminates the Operating Expenses Increase or (Decrease) from Prior Year (Thousands of Dollars)

Fuel for Electric Generation Purchased Electricity Gas Purchased for Resale Other Operation Maintenance Depreciation Amortization of Other Plant Taxes Charged to Operating Expenses Local, State and Other Taxes Federal Income Tax Total Change in Operating Expenses 1992

$(16,729) 2,023 11,512 18,184 (2,695) 478 369 10,603 9,332

$ 33,077 1991

$ (11,315)

(6,581)

(2,733) 13,846 3,024 8,346 (1,932) 12,614 (231) 8 15,038

Operating Expenses rrrdrrlrrrrrrddollars]

res SOO rrs pipelines'onopoly in providing gas merchant services. The Company's gas procurement strategy, as discussed above, has pursued such rights; therefore, FERC Order No. 636 enhances the Company's ability to imple-ment this strategy by estab-lishing a regulatory basis for its rights, rather than requiring it to negotiate for such rights in indi-vidual pipeline rate cases.

The cost of gas purchased for resale increased in the 1992 90 91 92 C3 Depreciation rt Amortization Cl Taxes 0

Fuel Expenses 0

Other Operating 8 Iitatntenance Costs comparison period primarily due to higher residential and commercial spaceheating

sales, reflecting colder weather. In contrast to 1991, however, when lower average rates led to a drop in the cost of gas purchased for resale, a decline in 1992 average rates could not offset the effect of the higher volume of gas required for sales during the year.

Operating Expenses, Excluding FueL Other operation expenses rose over both comparison periods as shown by the table on page 27. The recording ofcertain postretire-ment benefits other than pensions, as required by Statement of Financial Accounting Standards No. 106 (SFAS-106) and discussed in the followingparagraph, increased other operation expenses in 1992 by $4.9 million. Compared with a year earlier, other operation expenses in 1992 also reflect an increase of $3.0 millionfor trans-mission wheeling charges and additional expenses of about $ 1.6 million associated with the Company's share ofNine Mile Two operation expenses. The increase in other operation expenses for the 1991 comparison period primarily resulted from higher payroll costs, increased regulatory assessments, and higher transmission wheeling charges.

During the first quarter of 1992, the Company adopted the Financial Accounting Standards Board's (FASB) SFAS-106 for financial reporting purposes. Among other things, SFAS-106 requires accrual account-ing for postretirement benefits other than pensions. The Company estimates that the net periodic cost for postretirement benefits, excluding pensions, willbe approximately

$7.8 millionbased on accrual accounting required by SFAS-106. The net periodic cost includes approximately $2.8 million amortization of the unrecognized transition obligation (the accumulated postretirement benefit obligation at adoption), currently estimated at $56.4 millionto be amortized over twenty years. The PSC allowed the Company revenues in rates equal to

$7.0 millionin 1992 in recognition of this obligation. The Company has filed a petition with the PSC for deferral accounting treatment for the balance of the expense to be accrued.

Fluctuation of maintenance expense in both comparison periods was largely due to increased activity in 1991 associated with electric distribution facilities; and, for the 1992 comparison period, lower maintenance expense at nuclear production facilities.

Depreciation expense in the 1992 compar-ison period was basically unchanged as the effect of an increase in depreciable plant was nearly offset by a decrease in the depreciation related to the Ginna nuclear plant due to a three-year extension of its operating license. The amortization of the Sterling property abandonment was completed in July 1992. An increase in accrued decommissioning expenses and additional depreciable plant caused depreciation expense to increase in the 1991 comparison period.

Taxes Charged to Operating Expenses.

The increase in local, state and other taxes for both comparison periods resulted from increases in revenue taxes. These were impacted by a one-half percent increase in the New York State gross revenue tax, the accounting for which began in October 1991

retroactive to January 1, 1991. Also, higher assessments and tax rates on property increased these taxes.

In February 1992, FASB issued SFAS-109 entitled "Accounting for Income Taxes",

superseding SFAS-96. SFAS-109 requires the Company to adjust certain of its deferred tax assets and liabilities to reflect periodic changes in tax rates. In addition, the Company willalso be required to provide deferred taxes for the effect of tax benefits previously flowed through to the Income Statement. The Company willadopt SFAS-109 in the first quarter of 1993. The Company has proposed in its current rate filingwith the PSC that, upon adoption of SFAS-109, any charge or credit to earnings that might result from the change in accounting method be deferred and subse-quently amortized with carrying charges.

Since the Company's deferred taxes have been adjusted for regulatory purposes to the current statutory rate where permissible, the impact of SFAS-109 is believed to be immaterial. See Note 2 of the Notes to Financial Statements for an analysis of Federal income taxes.

Other Statement of Income Items AFUDC variances are generally related to the amount ofutilityplant under construction and not included in rate base. AFUDC levels also reflect decreases in the gross rate to 4.50 percent effective September 1992 from earlier rates of5.50 percent, 7.10 percent, and 8.60 percent.

Variations in non-operating Federal income tax reflect mainly June 1992 accounting adjustments related to the March 1991 ice storm and a 1991 accounting adjust-ment in connection with the Nine Mile7wo settlement agreement.

Recorded under the caption "Other Income and Deductions" is the recognition of the 1991 PSC order associated with the Company's fuel procurement practices (see page 23) and the 1992 PSC order related to the March 1991 ice storm (see page 21).

For the 1991 comparison period, the fluctuation in Other Income is primarily associated with the amortization ofcustomer prepaid Nine Mile7wo financing costs which had been deferred, as discussed under the heading New York State Public Service Commission. Such non-cash earnings were

$3.3 millionin 1990, $4.8 millionin 1991, and $2.5 millionin 1992. Other income in 1992 also includes $3.5 millionofproceeds received in settlement of lawsuits filed against certain contractors involved in the construction of the Nine Mile7wo nuclear plant.

Both mandatory and optional redemptions ofcertain higher-cost first mortgage bonds have helped to reduce long-term debt expense interest over the three-year period 1990-1992, despite the issuance of addi-tional long-term debt in 1991 and 1992. In 1992, the effect of lower interest rates on debt expense was partially offset by increased short-term borrowings.

Earnings/Summary Presented on page 30 is a table which summarizes the Company's Common Stock earnings in total and on a per-share basis.

As previously explained, Common Stock earnings per share in the second quarter of 1992 were reduced by approximately

$.17 per share, net of tax, following recognition of the disallowance of

$8.2 millionof deferred ice storm-related costs. After issuance of the two million additional shares ofstock in August 1992, the net-of-tax effect for the year was

$.15 per share. In the fourth quarter of 1991, earnings were reduced by $.21 per share when the Company recorded the effects of the fuel procurement settlement approved by the PSC as discussed earlier. Also, the Company estimates that a loss ofrevenues as a result of the 1991 ice storm reduced

earnings by $.07 per share, net of tax, for calendar year 1991.

In December 1991 the Company announced a quarterly dividend increase from $.405 to $.42 per share of Common Stock payable in January 1992.

Subsequently, in December 1992 the Company announced a new quarterly dividend rate of$.43 per share payable in January 1993. The Company's Charter provides for the payment ofdividends on Common Stock out of the surplus net profits (retained earnings) of the Company.

Accordingly, dividend payments are depen-dent on future earnings, in addition to finan-cial requirements and other factors.

Earnings Summary 1992 1991 1990

• Weighted average shares outstanding Earnings tThousands of Dollars)

$62,149

$51,034

$53,856 Shares (Thousands) 33,258 31,794 31,293 Earnings per Share

$1.86

$1.60

$1.72 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 executive officer, Midtown Holdings Corp.

He replaces Theodore J. Altier, former chairman and chief executive officer, Altier8 Sons Shoes, Inc. who served on the board formore than 12 years.

Jay T. Holmesis senior vice president corporate affairs and secretary of Bausch 8 Lomb Incorporated. He replaces William G. vonBerg, executive director, Executive Service Corps of Rochester, Inc. who served on the board formore than 20 years.

(Thousands of Dollars)

Year Ended December 31 1992 1991 1990 Operating Revenues Electric Gas Electric sales to other utilities t

Total Operating Revenues Dperatlng Expenses Fuel Expenses Fuel for electric generation Purchased electricity Gas purchased for resale Total Fuel Expenses Operating Revenues Less Fuel Expenses Other Operating Expenses Operations excluding fuel expenses Maintenance Depreciation and amortization Taxeslocal, state and other

~

Federal income tax Total Other Operating Expenses Operating Income Other Income and Deductions Allowance for other funds used during construction Federal income tax Regulatory disallowances (Note 10)

Other, net Total Other Income and Deductions Income Before Interest Charges Interest Charges Long term debt Other, net Allowance forborrowed funds used during construction Total Interest Charges Net Income Dividends on Preferred Stock Earnings Applicable to Common Stock Weighted Average Nuimber ofShares for Period (000's)

Earnings per Common Share

$ 608,267 261,724 869,991 25,541 895,532

$ 588,930

'35,728 824,658 28,612 853,270 48,376 29,706 141,291 219,373 65,105 27,683 129,779 222,567 226,624 62,720 85,028 124,252 43,591 208,440 65,415 84,181 113,649 34,259 542,215 505,944 133,944 124,759 164 4,195 (8,215) 6,155 2,299 136,243 675 4,580 (10,000) 6,078 1,333 126,092 60,810

~7,178 (2,184) 63,918 7,082 (2,905) 65,804 68,095 70,439 8,290 62,149 33,258 1.86 57,997 6,963

~ 51,034 31,794 1.60 676,159 630,703

$ 551,930 236,496 788,426 42,465 830,891 76,420 34,264'32,512 243,196 587,695 194, 594 62,391 77,767 101,035 34,490 470,277 117,418 2,689 2,459 4,062 9,210 126,628 64,873 4,593 (2,719) 66,747 59,88'1 6,025 53,856 31,293 1.72 55XXKK(N(BRllKDtM3$M (Thousands of Dollars)

Year Ended December 31 1992 1991 1990 Balance at Beginning ofPeriod Add Net Income Total Deduct Dividends declared on capital stock Cumulative preferred stock Common stock Total Balance at End ofPeriod The accompanying notes are an integral part ofthe financial statements.

61,515 70,439 131,954 62,542 57,997 120,539 6,963 52,061 8,290 56,696 59,024 64,986 66,968 61,515 57,983

- 59,881 117,864 6,025 49,297 55,322 62,542 I

(Thousands of Dollars)

Assets UtilityPlant Electric Gas Common Nuclear fuel At December 31, 1992

$ 2,175,255 341,466 123,034 158,826 1991

$ 2,122,248 320,385 116,858 147,063 Less: Accumulated depreciation Nuclear fuel amortization Construction work in progress Net'UtilityPlant Current Assets Cash and cash equivalents Accounts receivable, net of allowance for doubtfu 1992$500; 1991$411 Unbilled revenue receivable Materials and supplies, at average cost Fossil fuel Construction and other supplies Gas stored underground Prepayments Total Current Assets Deferred Debits Unamortized debt expense Deferred finance charges Nine MileTwo Deferred ice storm charges Uranium enrichment decommissioning deferral Nuclear generating plant decommissioning funds Nine MileTwo deferred costs Other Total Deferred Debits Total Assets 1 accounts; 2,798,581 1,125,502 127,615 1,545,464, 83,832 1,629,296 1,759

'2,292 60,184 12,273 13,130 9,998 19,985 209,621 2,706,554 1,067,471 111,178 1,527,905 76,848

-1,604,753 1,488 84,053 55,921 10,766 12,539 7,057 17,185 189,009 13,553 20,492 24,197 28,613 29,549 34,300 59,821 210,525 9,611 25,586

,36,431 19,221 30,121 39,064 160,034 3 2.049.442 3

1,953.796 Capttallzatlon and Liabilities Capitalization Long term debt mortgage bonds promissory notes Preferred stock redeemable at option of Company Prefened stock subject to mandatory redemption Common shareholders'quity Common stock Retained earnings Total Common Shareholders'quity Total Capitalization Long Term Liability(Department ofEnergy):

Nuclear waste disposal Uranium enrichment decommissioning Total Long Term Liabilities Current Liabilities Long term debt due within one year Preferred stock redeemable within one year Short term debt Accounts payable Dividends payable Taxes accrued Interest accrued Other Total Current Liabilities Deferred Credits and Other Liabilities Accumulated deferred income taxes Deferred finance charges Nine MileTwo Pension costs accrued Other Total Deferred Credits and Other Liabilities Commitments and Other Matters (Note 10)

Total Capitalization and Liabilities

'Die accompanying notes are an integral part ofthe financial statements.

566,980 91,900 67,000 54,000 591,532 66,968 658,500 1,438,380 65,989 28,613 94,602 110,250 6,000 50,800 40,579 17,035 13,743 15,461 13,409 267,277 171,673 20,492 20,278 36,740 249,183 0 2,049.442 530,422 141,900 67,000 60,000 529,339 61,515 590,854 1,390,176 63,626 V

63,626 96,750 59,500 53,983 15,555 12,050 16,313 13,450 267,601 162,955 25,586 13,515 30,337 232,393 6 1,953,706

(Thousands of Dollars)

Year Ended December 31 1992 1991 1990 Cash Flow from Dperatlons iVetincome Adjustments to reconcile net income to net cash provided from operating activities:

Depreciation and amortization Amortization of nuclear fuel Deferred fuelelectric Deferred income taxes Allowance for funds used during construction I

Unbilled revenue, net Ice storm costs Nuclear generating plant decommissioning Changes in certain current assets and liabilities:

Accounts receivable Materials and supplies fossil fuel construction and other supplies Taxes accrued Accounts payable Interest accrued Other current assets and liabilities, net Other, net

~

Total Operating Cash, Flow from Investing Activities UtilityPlant Plant additions

'uclear fuel additions Less: Allowance for funds, used during construction Additions to UtilityPlant Other, net Total Investing Cash Flow from Financing Activities Proceeds from:

Sale/Issue ofcommon stock Sale ofpreferred stock Sale oflong term debt, mortgage bonds Short term borrowings Retirement oflong term debt Capital stock expense Discount and expense ofissuing, long term debt Dividends paid on preferred and common stock Other, net Total Financing Increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning ofyear Cash and cash equivalents at end ofyear 70,439 57,997 S

59,881 85,028 18,803 2,543 10,466 (2,348)

(6,631).

"12,234 (10,328) 84,181 23,606 4,122 9,124 (3,580)

(8,931)

(36,431)

(15,581) 77,767 25,573 (477) 16,682 (5;408)

(2,818)

(3,640)

(8,239)

(1,507)

(591) 1,693 (13,404)

(852)

(2,528)

(13,726)

(4,773) 7,506 (315) 1,444 6,914 1,722 (592)

(6,966)

$ 141,052

$ 119,447 1,519 (5,183)

(1,246)

(2,805)

(6,077)

(690)

(6,602) 5,616

$ 152,092

$ (115,790)

(11",763) 2,348 (125,205) 490 S (114,579)

(13,058) 3,580

(,124,057)

(685)

S (1 23,887)

(8,297) 5,408 (126,776)

(98) 5 (124,715) 5 (124,742)

$ (126,874) 63,928 160,500 (8,700)

(160,000)

(1,735)

(6,368)

(63,506)

(185) 13,446 30,000 100,000 17,100 (92,334)

(495)

(3,310)

(57,704)

(464)

S 3,058 42,400 (28,000)

. (230)

(54,787) 908 271 1,488 S

944 S

544 (11,433) 11,977 1,759 1,488 544

$ '16,066)

S 6,239 (36,651)

~IIIIIIIIIIIIIIIIIIIRIIIIIIIIIII (Thousands of Dollars)

Cash PaId During the Year Interest paid (net ofcapitalized amount)

Income taxes paid Year Ended December 31 1992 64,431 22,911 1991 S

63,848 20,399 1990 S

64,851 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 utilityunder the Federal Power Act. The Company's accoun'ting policies conform to generally accepted accounting principles as applied to New YorkState public utilities giving effect to the rate-making and accounting practices and policies ofthe PSC.

In June 1988, the Board ofDirectors authorized the creation ofUtilico'm, Inc. as a wholly owned subsidiary. Utilicomdevelops 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 ofoperation.

In April 1990, the Board of Directors authorized the creation ofEnergyline Corporation, a wholly owned subsidiary, which was incorporated in July 1992. Energyline was formed as a gas

'ipeline corporation to fund the Company's investment in the Empire State Pipeline project.

The Company has invested approximately $ 10 millionin Empire as ofDecember 31, 1992.

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

A description ofthe 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 ofthe accounting period.

Pursuant to rate orders, $2.4 million, $2.2 million and $ 13.8 millionwas amortized to earnings in lieu of cash rate reliefin 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 offuels. The electric fuel adjustment provides that ratepayers and the Company willshare the effects ofany variation from forecast monthly unit fuel costs'on an 80%/20% basis up to a $2.6 millioncumulative, after-tax', annual gain or loss to the Company. Thereafter, 100 percent ofadditional 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 (primarilyresidential customers) are subject to a weather normalization adjustment to reflect theimpact ofvariations from normal weather on a billingcycle month basis for the months ofOctober 1992 through May 1993, inclusive. The weather normalization adjustment for a billingcycle willapply only ifthe actual heating degree days are lower than 97.5 percent or higher than 102.5 percent ofthe 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 tariffschedules 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 ofunbilled revenues.

Kochnev Gas sal Bccpie~

UtilityPlant, Depreciation and Amortization.

The cost of additions to utilityplant and replacement ofretirement units ofproperty 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 forfunds used during construction approximately equivalent to the cost ofcapital devoted to plant under construction that is not included in its rate base. Replacement ofminor items of

.property is included in maintenance expenses.

Costs ofdepreciable units ofplant retired are eliminated from utilityplant 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 ofproperty, which have resulted in provisions of2.9%, 3.3% and 3.5% per annum ofaverage 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 ofthe 3t/~ year extension ofGinna's license term and generally lengthening estimated useful lives. Amortization includes $.7 millionin 1992, $.3 millionin 1991 and $2.2 millionin 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 ofEnergy (DOE) to establish a nuclear. waste disposal site and to take title to nuclear waste. Apermanent 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 facilitywhich may allow it to take title to and possession ofnuclear 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 ofnuclear fuel irradiated prior to April7, 1983 and for three payment options. The option of a single payment to be made at any time prior to the first delivery offuel to the DOE was selected in June 1985,. The Company estimates the fees, including accrued interest, owed to the DOE to be $66.0 millionat 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 liabilityand 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 April6, 1983, for a charge ofone mill($.001) per KWHof 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 facilityis operational.

Nuclear Decommissioning Costs.

Decommissioning costs (costs to take the plant out ofservice 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 ofNine MileTwo'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 millionfor this purpose and is currently accruing for de'commissioning costs at a rate of approximately $8.9 millionper year based on the use of a combination ofinternal and external sinking funds. (See Note 10.)

The decommissioning costs, which form the basis for current accruals, were derived from the record ofthe 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 ofFederally owned uranium enrichment facilities. The assessments for Ginna and Nine Mile.Two are estimated to total $28.6 million,excluding inflation and interest. A liabilityhas been recognized on the financial, statements along with an offsetting regulatory asset. The Company believes that this amount willbe recoverable in rates as described in the Act.

((Vote I continued on page 36)

8888 (continued from page 35)

Allowance forFunds llsed During Construction.

The Company capitalizes an Allowance for Funds Used During Construction (AFUDC) based upon the cost ofborrowed 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 ofIncome 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 ofcomputing 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 millionofconstruction 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 ofAFUDC 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 ofNine MileTwo, 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 millionat 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 millionwillbe amortized through the Statement ofIncome 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 ofenactment 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 LifeInsurance Benetlts.

The Company provides certain health care and life insurance benefits for retired employees and health care coverage for surviving spouses ofretirees. 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 ofcommon 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 1990 1991 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 (7,171),

(8,211)

(5,311)

Deferred 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 ofFederal income tax expense reported in the Statement ofIncome and the amount computed by multiplyingthe income by the statutory tax rate.

(Thousands of Dollars) 1992

%of Pretax Amount Inc'ome

%of Pretax Amount Income

%of Pretax Amount Income

$57,997 29,679

$87,676

$29,810 34.0 Net Income Add: Federal'income tax expense Income before Federal income tax Computed tax expense Increases (decreases) in tax resulting from:

Difference between tax depreciation and amount deferred 6,775 6.2 5,606 6.4 Investment tax credit (2,426)

(2.2)

(2,432)

(2.8)

Miscellaneous items, net (2,297)

(2.1)

(3,305)

(3.7)

Total Federal income tax expense

$ 39,396 39.9

$29,679 33.9 A summary of the deferred amounts charged or (credited) to income is as follows:

(Thousands of Dollars) 1992 1991

$59,881 32,031

$91,912

$31,250 34.0 4,127 4.5

'(2,752)

(3.0)

(594)

(0.7)

$32,031 34.8 1990 Investment tax credit Depreciation Fuel costs Sterling abandonment Deferred ice storm charges Accrued revenue Demand Side Management Alternative Minim'um Tax Revenues Deferred Nine MileTwo Pension Other items Total

$ (3,284) 25,553 (2,442)

(3,147) 342 2,977

'4,839 (2,013 (2,264)

(417

$10,466

.$ (4,235) 24,158 205 512 9,666 (353) 1,348 (13,768)

(2,413)

(2,721)

(3,275)

$ 9,124

$ (2,414) 22,906 1,180 (796) 1,596

708, (2,475) 1,028 (2,729)

(2,322)

$16,682

Mote 3. Pension Plan and Other Retirement Benefits 1992 1991 The Company has a defined benefit pension plan covering substantially all of its employees.

The benefits are based on years ofservice and the employee's compensation during the last three years ofemployment. The Company's funding policy is to contribute annually an amount consistent with the requirements ofthe 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)

Accumulated benefit obligation, including vested benefits of

$249.6 in 1992 and $237.4 in 1991 Projected benefit obligation for service rendered to date Less Plan assets at fair value, primarily listed stocks and bonds 268.1'378.0'49.9 (71.9)

$251.9*

$359.7*

433.3 (73.6)

Unrecognized net gain from past experience different from that assumed and

, effects ofchanges in assumptions LessPrior service cost not yet recognized in net periodic pension cost Less Unrecognized net obligation at December 31 Pension liabilityrecognized on the balance sheet

• Actuarial present value Net pension cost included the followingcomponents:

(Millions) 1992 102.4 98.0 5.4 5.5 4.8 5.4

$ 20.3

$ 13.5 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 ofreturn 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 ofthe Company's employees are eligible provided that they retire as employees ofthe Company. In 1992, the health c'are benefit consisted of a contribution ofup 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 Lifebenefit, 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 Lifebenefit providing a death benefit equal to one times the employee's December 31, 1982 pay (frozen). The out-of-pocket cost ofproviding these benefits was approximately $3.0 millionin 1991 and $2.5 millionin 1990, and with the adoption of SFAS-106 in 1992, the total cost of these benefits increased by approximately $4.5 million.

1992 The Company adopted SFAS-106, "Accounting for Postretirement Benefits Other than Pensions" as ofJanuary 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 ofSFAS-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)

Accumulated postretirement benefit obligation (APBO):

Retired employees Active employees Less Plan assets at fair value Accumulated postretirement benefit obligation (in excess of) less than fair value of assets Unrecognized net gain from past experience different from,that assumed and effects of changes in assumptions LessPrior service cost not yet recognized in net periodic pension cost Less Unrecognized net obligation at December 31 Accrued postretirement benefit cost Net periodic postretirement benefit cost included the followingcomponents:

(Millions).

$(35.3)

(23.6)

$(58.9) 0.0 (58.9) 0.0 0.0 53.6 5 (5.3) 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 ofincrease in future compensation levels of6'ercent.

The PSC has allowed the Company revenues in rates equal to $7.0 millionin 1992 in recognition of these benefits. The Company has filed a petition with the PSC for deferral accounting treatment for the balance ofthe 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, willnot adversely impact the financial statements.

gi

Note 4. Departmental Financial Information 1990 The Company's records are maintained by operating departments, in accordance with PSC accounting policies, giving effect to the ratemaking process. The followingis 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 ofIncome.

(Thousands of Dollars) 1992 1991 Electric Operating Information Operating revenues

'perating expenses, excluding pro on for incom

, Pretax operating income Provision for income taxes Net operating income Other Informatiori Depreciation and amortizati Nuclear fuel amortization Capital expenditures Investment Information Identifiable assets (a) 8as

'tlrer Information Depreciation and amortization Capital expenditures Investment Information Identifiable assets (a)

(a) Excludes cash, unamortized debt expense and other common items.

S 633,808 e taxes 482,968 150,840 38,046 S

112,794 on 73,213 S

18,803 100,974

$1,671,492

$ 11,815

$ 24,231

$354,528 Operating Information Operating revenues

$261,724 Operating expenses, excluding provision for income taxes 235,029 Pretax operating income 26,695 Provision for income taxes 5,545 Net operating income

$ 21,150 617,542 478,101 139,441 31,390 108,051 S

72,746 S

23,606 S

97,294

$ 1,607,21 0

$ 235,728 216,151 19,577 2,869 16,708 S

11,435 S

26,763

$ 325,451 S

594,395 464,478 129,917 30,670 S

99,247 S

67,302 S

25,573 S

101,024

$1,557,176

$ 236,496 214,505 21,991 3,820 S

18,171 10,465 S

25,752

$ 291,088 Note 5. Jointly-Owned Facilities The followingtable sets forth the jointly-owned electric generating facilitie's in which the Company is participating. Both Oswego UnitNo. 6 and Nine MilePoint Nuclear Plant UnitNo. 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 ofdirect expenses associated with these two units is included in the appropriate operating expenses in the Statement

- ofIncome. Various modifications willbe 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 RG&E's share megawatts

percent

-Year ofcompletion Plant In Service Balance Accumulated Provision For Depreciation Plant Under Construction 850 1,080 204 151 24 14 1980 1988 Millionsof Dollars at December 31, 1992

$98.6

$867.6

$30.9

$428.9 S 0.4 9.4 The Plarit in Service and Accumulated Provision for Depreciation balances for Nine MilePoint 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 offin.1987 and 1989.

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

Principal Amount December 31 1992 1991 Sept. 15, 1994 May I, 1996 Sept. 15, 1997 July I, 1998 Aug. 15, 1999 Sept. I, 2000 June 15, 2006 Sept. 15, 2007

~

Dec. I, 2003 Aug. I, 2009 Feb. 15, 2005 May 15, 2012 June 15, 1999 Aug. I, 1993 May I, 1992 Dec. I, 2028 Apr. 1, 2021 Mar. 15, 2002 May 15, 2032 May 15, 2032 4N U

$ 16,000

$ 16,000 5.3 V

18,000 18,000 6Y4 W

20,000 20,000 6.7 X

, 30,000 30,000 8

Y 30,000 30,000 Z

30,000, 30,000 9Y4 BB 50,000 50,000 85/5 CC 50,000 50,000 9.5 DD 40,000 40,000 6Y2 EE (a) 10,000 10,000 10.95 FF 5,500 27,500 12Y4 HH 10,500 132/5 JJ 17,500 4 20,000 8.6 LL(b) 75,000 75,000 82/5 MM 75,000 85/5 Oo(a) 25,500 25,500 95/i PP 100 000 100 000 8Y4 QQ (b) 100,000 6.35 RR (a) 10,500 6.50 SS (a) 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 ofprincipal, 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 willbe made to the sinking fund, with the balance of$6.8 millionprincipal amount of the bonds becoming due August 1, 2009; (b) The Series LLand 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 ofadditional 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 millionmedium-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. AtDecember 31, 1992 there were no medium-term notes outstanding. On January 14, 1993 the Company issued $30 millionofthe medium-term notes at an interest rate of7.00% with a maturity date ofJanuary 14, 2000. The issue is generally not redeemable before maturity.

(Note 6 continued on page 42)

(continued fiom page 4I)

(Thousands) 1993 1994 1995 1996

'inking fund requirements and bond maturities for the next five years are:

1997

$ 30,000 2,750 2,500 75,000 Series Z (c)

Series FF (d)

Series JJ (e)

Series LL Series U Series V Series W

$ 2,750 2,500 16,000

$ 2,500

$2,500

$ 2,500 18,000 (Thousands) 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 millionprincipal 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 millionannually each February 15.

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

Promfssory Notes Issued Due December 31 1992 1991 November 15, 1984 (f)

October 1, 2014 December 5, 1985 (g)

November 15, 2015 July 22, 1987, (h)

Cancelled See Note Below Total

$51,700

$ 51,700 40,200 40,200 50,000 091,900

$ 141,000 (f) The $51.7 millionPromissory 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 ofCredit expiring October 15, 1994. The interest rate on this note for each monthly interest payment period willbe based on the evaluation of the yields ofshort 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 millionPromissory 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 ofCredit 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 millionPromissory 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 ofprincipal, premium and interest on each Promissory Note which correspond to the payments ofprincipal, premium, ifany, and interest on certain Pollution Control Revenue Bonds issued by the New YorkState Energy Research and Development Authority (NYSERDA) as described above. These obligations are supported by certain Bank Letters ofCredit 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 of7.64% for long term debt withj.

similar terms and average maturities (13 years), the fair value ofthe Company's long term debt outstanding (including Promissory Notes as described above) is approximately $787 millionat 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 Preferred Stock (cumulative) 25 Preference Stock 1

'See below for mandatory redemption requirements 2,000,000 4,000,000 5.000.000 1,270,000*

No shares ofpreferred or preference stock are reserved for employees, or foroptions, warrants; conversions, or other rights.

A. Preferred Stock, not subject to mandatory redemption:

Shares (Thousands)

Outstanding December 31 Series December 31,1992 1992 1991 Optional Redemption'per share)f F

H I

J K

M N

4 4.10 45/

4.10 4.95 4.55 7.50

, Total

¹May be redeemed at any 120,000

$12,000 80,000 8>000 "60,000 6,000 50,000 5,000 60,000 6,000 100,000 10,000 200,000 20,000 070,000 667,000 time at the option ofthe Company on 30 days mini subject to mandatory redemption:

B. Preferred Stock,

$105 101 101 102.5 102 101

~

102

$12,000 8,000 6,000 5,000 6,000 10,000 20,000

$67,000 mum notice, plus accrued dividends in all cases Shares Outstanding Series December 31 ~ 1992 (Thousands)

December 31 1992 1991 Optional Redemption (per share) 8.25 7.45

'.55 7.65 R

S T

U Less: Due within one year Total

+Thereafter at lesser rates 300,000 100,000 100,000 100,000 600,000 60,000 540,000

$30,000 10,000 10,000 10,000

$60,000 6,0PO 554,000

$30,000 10,000 10,000 10,000

$60,000

$60,000

$104.00 Before 3/1/93+

Not applicable Not applicable Not applicable 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. Allofthe shares are subject to redemption pursuant to mandatory sinking funds on September 1, 1997 in the case ofSeries S, September 1, 1998 in the case of Series T and September 1, 1999 in the case ofSeries 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 ofthe Company.'s Preferred Stock, subject, to mandatory redemption, is approximately

$65 millionat December 31, 1992.

Note 8. Common Stock AtDecember 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 ofCommon 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:

Balance, January 1, 1990 Automatic Dividend Reinvestment and Stock Purchase Plan Savings Plus Plan Capital Stock Expense Balance, December 31, 1990 Automatic Dividend Reinvestment and Stock Purchase Plan Savings Plus Plan Capital Stock Expense Balance, December 31, 1991 Sale ofStock Automatic Dividend Reinvestment and Stock Purchase Plan Savings Plus Plan Capital Stock Expense Balance, December 31, 1992 Per Share

$1 8.600-$ 19.288

$1 8.62M19.750

$18.750-$ 23.1,63

'$19.375-$ 23.563

$24.000

$21.325-$ 24.850

$22.063-$ 25.1 88 Shares Outstanding 31,257,968 134,828 28,472 31,421,268 571,669 108,202 7

32,101,139 2,000,000 584,854 110,666 34,796,659 Amount (Thousands)

$513,560 2,513 545 (230)

$516,388 11,252 2,194 (495)

$529,339 48,000 13,338 2,590 (1,735) 6591.532 Note 9. Short Term Oebt AtDecember 31, 1992 and December 31, 1991, the Company had short term debt outstand-ing of $50.8 millionand $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 millionrevolving credit facilityfor a period ofthree years. In January of 1993 the Company was grante'd a one-year extension ofthe 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 ofDecember 31, 1992, the Company would be able to incur $45.2 millionofadditional 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 ofthe Company's Charter.

Since June 1990 the Company has had a credit agreement with a domestic bank providing for up to $20 millionofshort 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 ofup to

$25 millionis available from a domestic bank, at its discretion.

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 millionofcarrying 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 ofNine MileTwo. The Company has col-lected approximately $52.4 millionthrough December 31, 1992.

In June 1988 the Nuclear Regulatory Commission (NRC) issued new regulations establishing-criteria for various facets ofdecommissioning 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 ofremoving the radioactive plant structures. The Company's depreciation rates reflect a 5% cost ofremoval factor for Ginna non-radioactive plant structures; however, they do not currently reflect a cost ofremoval factor for the Company's 14% share ofNine Mile7wo 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 $8.9 millionfor decommis-sioning, covering both nuclear unig. The amount allowed in rates is based on estimated ultimate decommissioning costs of$ 145.8 millionfor Ginna and $33.5 millionfor the Company's 14%

share ofNine Mile7wo (1991 dollars). The Company intends to fund the external decommis-sioning trust in th'e amount ofthe 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 millionfor the Ginna Nuclear Plant and the esti-mated amount forits share ofNine Mile7wo is approximately $.1 million. Although a noncash transaction, the aggregate amount of$28.6 million(see Note 1) has been recognized as a liabilityat December 31, 1992, together with a corresponding deferred debit based on the language ofthe Act. The Company believes itwillreceive 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 limitto 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 millionper licensed facilityfor each nuclear incident, payable at a rate not to exceed $ 10 millionper 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 itto a current potential payment for each accident of

$71.8 millionthrough retrospective assessments of$ 11.4 millionper 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 page 45)

Beginning in 1988, coverage for claims alleging radiation-induced injuries to some workers at nuclear reactor sites was removed from the nuclear liabilityinsurance 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 liabilityinsurance policies. Those workers first employed at a nuclear facilityin 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 millionover the lifeofthe insurance coverage.

The Company is a member ofNuclear Electric Insurance Limited, which provides insurance coverage for the cost ofreplacement power during certain prolonged accidental outages of nuclear generating units and coverage for property losses in excess of $500 millionat nuclear generating units. As ofDecember 31, 1992, the Company is purchasing a weekly indemnity limitof $3.5 millionin the NEILI replacement power expense program and fullpolicy limits of

$ 1.325 billionin the NEILII.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 ofNine MileTwo, the Company purchases a weekly indemnity limitof$.5 millionin the NEILI replacement power expense program. The owners at Nine MileTwo purchase the fullpolicy limitof $ 1.325 billionin the NEILIIProperty Insurance Program and the Company pays its proportionate share ofthose premiums. The owners at Nine MileTwo have selected the maximum available sublimit of $200 millionfor 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 ofapproxi-mately $5.2 millionand $ 13.7 millionin the event of losses under the replacement power and property damage coverages, respectively.

Environmental Matters.

On November 15, 1990 the Federal Clean AirAct Amendments of 1990 (Amendments) became law. The Amendments willaffect 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 ofparticular importance to the Company. Title IVaddresses 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, willbecome effective in the year 2000. The Company is not affected by the first phase ofTitleIVof 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 firstphase ofTitleI becomes effective in 1995 and willrequire the installation oflow nitrogen oxide burners on the Company's fossil-fuel plants. Phase Two ofTitleI has not yet been defined, but could require flue gas cleanup for nitrogen oxide removal. TitleIIIofthe Act has not yet been defined but could require the control ofvarious 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 millionand $50 million(1992 dollars) have been estimated for the implementation ofseveral 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 YorkState Department ofEtivironmental Conservation (AYSDEC) identi-fied property in the vi'cinityof 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

'wner'r operator of a number of locations within the Lower Falls. In mid-1991, NYSDEC advised the Company that it had delisted theLower Falls Site, i.e., removed it from its-Registry ofInactive Hazardous Waste Sites. The effect ofdelisting 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 ofRochester proposal for a limited further investigation ofthe 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 ofNew York adopts new federal procedures under which such individual sites willbe, 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 vicinityof 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 itintehds 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 ofdiscussions'over this matter, the County has claimed,,without offering any evidence, that the Company was the original generator ofthe materials. It asserts

. that itwillhold 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 ofthe 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 ofcontamination. 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 ofthis location', the Company may be fullyor-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

(eorm'nued fionI page 47)

L Gas'Cost Recovery.

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 ofmaximum contract volumes ofnatural gas or, ifsuch quan-tities were not taken, to pay for them (take-or-pay). As a result ofreduced demand, many pipelines subsequently experienced a significant reduction in sales, leading to substantial take-or-pay liabilit$'o 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 ofsuch 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% ofthe first $ 12 millionofthe pipeline take-or-pay costs imposed upon it. The recovery, of any take-or-pay costs-incurred in excess of $ 12 millionwould be subject to future determination.

In March 1992 the Company began providing for recovery, on. an interim basis, of65% 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 ofthe 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 itin excess of $ 12 million, except for an amount which would not exceed $562,500. The PSC must approve the supplemental settlement foritto 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 ofDecember 31,-1992 the Company had been billed for $ 16.4 million.of take-or-pay costs and has thus far recovered

$ 10.6 millionfrom its customers. In addition, $4.1 millionhas been deferred for recovery.

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

'These contract conversions willrequire the pipelines to reduce their purchase commitments to natural-gas producers. The costs of such conversions willbe 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 ofsuch 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 millionfor 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 millionin 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% ofits 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 ofDOE enrichment service's utilized for the next seven reloadyears (priced at the most current rate) ranges from

$4 millionto $7 millionper year.

Anticipated Assertion ofTax 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 halfof 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 ofevents and relationships at the Nine MileTwo project and to the appropriate tax treatment ofinvestments 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 ithas 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 MileTwo 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 ofits 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 ofthese 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 ofFinancial 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 ofinternal accounting controls over the preparation ofits financial statements designed to provide reasonable assurance as to the integrity and reliabilityof the financial records.

This system ofinternal 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 ofinternal accounting control and such tests and other procedures necessary to express an opinion as to whether the Company's financial statements are presented fairlyin all material respects in conformity with generally accepted accounting principles. The report ofPrice Waterhouse is presented on page 49.

The AuditCommittee of the Board ofDirectors 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 AuditCommittee, without management present, to discuss the results oftheir examinations and their opinions on the adequacy ofinternal accounting controls and the quality offinancial reporting.

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

Roger N Kober Chairman ofthe Board, President and Chief Executive Officer January 22, 1993 RobertC. Henderson Senior Vice President, Controller and Chief Financial Officer In the opinion ofthe Company, the followingquarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results ofoperations for such periods. The variations in operations reported on a quarterly basis are a result ofthe seasonal nature ofthe Company's business and the availability ofsurplus electricity.

(Thousands of Oollars)

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

March 31, 1992 December 31, 1991>>

September 30, 1991 June 30, 1991 March 31, 1991 Operating Revenues

$244,290 198,341 195,154.

257,747

$229,331 195,629 182,637 245,673 Operating Income

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

$38,578 31,752 17,230 37,198

'et Income

$29,146 17,507 (4,579) 28,365

$14,911 17,262 1,538 24,286 Earmngs on Common Stock

$27,073 15,435 (6,651) 26,293

$12,467 15,756 32 22,780 Earnings per Common Share (in dollars)

$.77

.45

(.20)

.81,

$.38

.49

.72 December 31, 1990

$220,360

$32,878 September 30, 1990 187,508 30,218 June 30, 1990 182,216 16,541 March 31, 1990 240,807 37.781 Includes tccognition of $6 6 million net of tus fuels audit disallowance.

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

$18,136 15,593 2,068 24,084

$16,630 14,087 562 22,578

$.53

.45

.01

.72

.Earnings 1992 1991 1990 Slmres 1992 '991

-1990 Earnings per weighted average share

$1.86

$1.60 Q.72 Number ofshares (000's)

Weighted average Actual number at December 31 33,268 31,794 31,293 34,797 32,101 31,421 Tax Status ofCash 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 itbecame publicly held in 1949. The level offuture cash dividend payments willbe

- dependent upon the Company's future earnings, its financial requirements and other factors.

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

Quarterly dividends on Common Stock are generally paid on the twenty-fifthday ofJanuary, 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 ofthe Company's Common Stock are traded on the New York Stock Exchange under ge symbol "RGS".'990 RANGE OF CohdhfON STOCK PRICE.

(In Dollars)

~

1991 RANGE oF CohthtoN STOCK PRICE (In Dollars) 26 1992 RANGE OF CohahtoN STocK PRtca (In Dollars)

'26 23.88 2325 24.00 24.75 25.25 21 20 18 21.75

'19.50 19.88 20 00 19.25 23-

'2 20 19

'8 20.75 2088 20.50 19.00 19.00-20.1tt 22 21 20 19 18 20.88 2 25 22.75 23.13 17 17.50 16.88 17.88 17.75 17 16 1st 2nd -3rd 4th

Quarter, 16 1st 2nd 3rd 4th

~ Q(sarler 16 1st 2nd 3rd 4th Quaner DIYIDENDsPAID per SHARE, 1990 per QGARIER (In Dollars) 0.39 0.39 0.39 0.39 DiviDENDS PAIDper SttARB, 1991 per QOARrER (In Dollars) 0.405 0.405 0.405

- 0.405 DtvIDENDs PAID per SHARF 1992 per QUARTER (In Dollars) 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 Gas Electric sales to other utilities Total Operating Revenues Operating Expenses Fuel Expenses Electric fuels 1

Purchased electricity Gas purchased for resale 4

Total Fuel Expenses Operating Revenues Less Fuel Expenses Other Operating Expenses Operations excluding fuel expeoses Maintenance Depreciation and Amortization Taxes local, state and other Federal income taxcurrent deferred Total Other Operating Expenses Operating Income Other Income and Deductions Allowance for other funds used during construction Federal income tax Regulatory disallowances Other, net Total Other Income and Deductions Income Before Interest Clrarges Interest Charges Long term debt Short term debt Other, net Allo'wance for borrowed funds used during construction Total Interest Charges Income from Continuing Operations, Before Cumulative Effect ofAccounting Change Cumulative Effectfor Years Prior to 1987 of Accounting Change forDisallowed Costs Net Income (Loss)

Dividends on Preferred I'tock, at Required Rates Earnings (Loss) Applicable to Common Stock Weighted Average Nuinber ofShares Outstanding in Each Period (000's)

Earnings (Loss) per Common Share Total

, Earnings per Common Share Continuing Operations Cash Dividends Paid per Common Share

$608,267 261,724 869,991 25,541 895,532

$588,930 235,728 824,658 28,612 853,270

$5511930 236,496 788,426 42,465 830,891

. 48,376 29,706 141,291 219,373 676,159 226,624 62,720 85',028 124,252 35,299 8,292 542,215 133,944 65, 105 27,683 129,779 222,567 630,703 208,440 65,415 84,181 113,649 28,766 5,493 505,944 124,759

/

76,420 34,264 132,512 243,196 587,695 194,594 62,391 77,767 101,035 20,661 13,829 470,277.

117,418 164 4,195 (8,'215) 6,155 2,299 136,243 675 4,580 (10,000) 6,078 1,333 126,092 2,689 2,459 4,062 9,210 126,628 60,810 1,950 5,228 63,918 2,623 4,459 64,873 1,070 3,523 70,439 57,997 59,881 70,439 8,290 0 62,149 33,258

$1.86 57,997 6,963 3 51.034 31,794

$1.60 59,881 6,025 6 53,856 31,293

$1.72

$1.86

$1.60

$1.60

$1.62

$1.72

$ 1.56 (2, 184)

(2,905)

(2,719) 65,804 68,095 66,747

$543,096 264,573 807,669 38,028 845,697

$514,637 231,217 745,854 29,966 775,820 75,873 39,645 152,623 268,141 577,556 173,764 64,316 75,063 95,341 20,509

=

17,330 446,323 131,233 65,787 30,299 129,596 225,602 550,138 159,689 52,575 69,703 88,635 20,363 20,299 411,264 138,874 2,261 1,439 (2,100) 8,328 9,928

• 141,161 2,047 1,683 6,901 10,631 149,505 68,628 3,115 (2,026) 69,717 72,270 2,898 (1,777) 73,391 71,444 6,025

$ 65,419 31,090

$2.10

$2.1 0

$ 1.50 76,114 7,348

$ 60,766 A

30,513

'$2.25

'$2.25

$ 1.50 71,444 76,114

$489,366 218,408 707,774 26,215 733,989 61,443 26,467 124,086 211,996 521,993 159,'l70 46,124 55,530 82,869 32,781 23,144 399,618 122,375 5,030 17,520 (55,860) 8.831 (24,479) 97,896 73,489 129 2,685 (2,696) 73,607 24,289 (193,000)

(168,711) 8,147

$(176,850(

29,728

$ (5.95),

6 0.54

$2.025

Condensed Balance Sheet (Thousands of Dollars)

At December 31 1992 1991 1990 1989 1987 Assets UtilityPlant Less: Accumulated depreciation and amortization Construction work in progress

'et utilityplant Current Assets Deferred Debits Total Assets

$2,798,581 1,253,117 1,545,464 83,832 1,629,296 209,621 210,525

$2,049,442

$2,706,554 1,178,649 1,527,905 76,848 1,604,753 189,009 160,034

$1,953,706

$2,310,294 812,994 1,497,300 82,663 1,579,963 176,045 108,45'1

$1,864,459 1,477,537 68,784 1,469,046 41,044 973,008 501,738 1,546,321 190,321 102,729 1,510,090 1,474,746 21346267 184I472 102,015 131,526

$ 1,839,371

$1,825,731

$ 1,790,74'4

$2,208,158

$2,122,922

$1,559,848 730,621 653,876 586,840 Capitalization and Liabilities Capitalization Long term debt Preferred stock redeemable at option of Company Pieferred stock subject to mandatory redemption Common shareholders'quity

'ommon stock Retained earnings Total common shareholders'quity Total Capitalization Long Term Liabilities (Department ofLn'ergy)

Current Liabilities Deferred Credits and OtlierLiabilities Total Capitalization and Liabilities 67,000 54,000 591,532 66,968 67,000 67,000 60,000

', 30,000 529,339 61,515 516,388 62,542 67,000 30,000 67,000 30,(00 513,560 504,907 57,983 '9,710 67,000 50,797 494,018 17,617 658,500 1,438;380 590,854 1,390,176 578,930 1,397,542 571,543 544,61 7 511,635 1,433,170 1,434,593',474,758 94,602 267,277 249,183 63,626 267,601 232,393 59,989 183,720 223,208 55,502 137,899 212,800 51,016 126,661 213,461 47,773 89,308 178 905

$2,049,442

$1,953,796

$1,864,459

$ 1,839,371

$1,825,731

$ 1,790,744 658,880 672,322 721,61 2 764,627 792,976 845,326 Financial Data At December 31 1992 1991 1990 1989 1988 1987 55.1 6.5 38.4 53.6 6.7 39.7 100.0

$18.42

'.7 40.7 100.0

$18.41 8.60 100.0

$18.28 11.56(b) 9.29 8.59 6.72 34.8 3.33 2.94 8,74 6.72 339 3.25 2.96

,Capitalization Ratios(a) (percent)

Long term debt, 48.2 50.6 Preferred stock 8.0 Common shareholders'quity 43.8 Total 100.0 Book Value per Common Share Year End,.

$18.92 Rate ofReturn on Average Common Equity, (percent),

9.98 Lmbedded Cost ofSenior Capital (percent)

Long term debt I

7.91 8.32 Preferred stock.

'.98 6.97 Effective Federal Income Tax Rate (percent) 35.9 33.9 Depreciation Rate (percent) Electric 2.69 3.05

Gas 2.78

'.94 Interest Coverages(b)(c)

Before federal income taxies (incld. AFUDC) 2.74 2.38 2.32 2.53 (excld. AFUDC)

-2.70 2.33 2.25 2.47 After federal income taxes (incld. AFUDC) 2.12 1.91 1.86

'.02 (excld. AFUDC)

'.08 1.86 1.78 1.96

~ ~

56.8 6.5 36.7 100.0

$17.69 12.68 8.71, 6.72 33.9 3.56 2.96 2.53 2.48'.01 1.96 58.7 7.7 33.6 100.0

$16.98 12.45(b) 8.90 7.09 61.3 3.50 2.98 2.55 2.45 1.93 1.83 (a)Includes Company's long term liabilityto the Department ofEnergy (DOE) for nuclear waste disposal. Excludes DOE long term liabilityfor uranium enrichment decommissioning and amounts due or rcdcemable within one year.

(b)Excludes disallowed Nine MileTwo plant costs written offin 1989 and 1987.

(c)The recognition by the Company in 1991 ofa 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 ofdisallowed 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 Commercial Industrial Other (Includes Unbilled Revenue)

Electric revenue from our customers Other electric utilities Total electric revenue Electric Expense (000's)

Fuel used in electric generation Purchased electricity Other operation Maintenance Depreciation and Amortization Taxes local, state and other Total electric expense Operating Income before Federal Income Tax Federal income tax Operating Income from Electric Operations (000's)

Electric Operating Ratr'o %

Electric SalesIAVH(000's)

Residential Commercial Industrial Other Total billed Unbilled sales Total customer sales

'ther electric utilities Total electric sales Electric Customers at December 31 Residential Commercial Industrial Other-Total electric customers Electricity Generated and Purchased lAVH(000's)

Fossil Nuclear Hydro Pumped storage Less energy for pumping

~

Other Total generated Net Purchased Total electric energy System Net Capability-IAVat December 31 Fossil Nuclear Hydro Other-Purchased Total system net capability Net Peak LoadKW Annual Load Factor Net %

$220,866

$212,327 184,815 181,56'l 142,392 141,001 60,194 54,041

$197,612 165,445 130,012 58,861

$191,732

$188,451 155,076 149,663, 124,634 120,490 71,654 56,033

$178,933 146,138 118,479 45,816 608,267 25,541 588,930 28,612 551,930 42,465 543,096 38,028 514,637 29,966 489,366 26,215 633,808 617542 594,395 581,124 544,603 515581 48,376 29,706 183,118 53,714 73.'213 94,841 65,105 27,683 168,610 57,032 72,746 86,925 76,420 34,264 155,289 53,880 67,302 77,323 75,873 39,645 137,458 55,9)5 65,287 71,361 65,787 30,299 124,871 44,060 60,444 66,426 61,443 26,467 126,320 37,641 46,776 61,504 482,968 478,101 464,478 445,539 391,887 360,151 150,840 139,441 38,046 '1,390 129,917 30,670 135,585 29,887 152,716 34,093 155,430 48,788

$112,794

$ 108,051

$ 99,247

$105,698

$118,623

$106,642 49.7 51.6 2,084,466 2,085,429 1,937,950 1,928,730 1,929,498 1,917,796 503,330 507,765 53.8 2,075,072 1,897,583 1,931,633 490,077 53.2 2,072,047 1,832,521 1,9066429 491,905 48.7 2,051,808 1,792,162 1,869,417 483,730 48.9 1,970,345 1,732,939 1,782,223 463,256 6,455,244 6,439,720 742 7,657 6,394,365 6,302,902 6,197,117 5,948,763 (25,421) 33,406 6,455,986 6,447,377 1,062,738

',034,370 6,368,944 6,336,308 1,316,379 1,255,282 6,197,117 5,948,763 1,149,900 1,047,654 7,518,724 7,481,747 7,685,323 7,591,590 7,347,017 6,996,417 300,344 29,339 1,386 2,605 298,440 28,856 1,388 2,558 296,110 28,804 1,428 2,553 293,418 28,386 1,422 2,512 290,037 27,888 1,392 2,326 285,988 27,383 1,381 2,281 333,674 331,242 328,895 325,738 321;643 317,033 2,197,757 4,191,035

~

278,318 226,391 (344,245) 811 2,146,664 4,391,480 174,239 240,206 (364,520) 1,269 2,505,110 4,016,721 244,539 269,966 (405,966) 20,408 2,578,006 3,659,185 175,085 290,582 (429,895) 54,893 2,214,588 3,884,884 169,002 292,305 (430,401) 2,195 1,877,922 3,793,021 223,958 246,925 (387,546)

. 4,554 6,550,067 1,389,875 6,589,338 1,451,208 6,650,778 1.498,089 6,327,856 6,132,573 5,758,834

',757,413 1,705,755 1,703,411 7,939,942 8,040,546 8,148,867 8,085,269 7,838,328 7,462,245 541,000 617,000 47,000 29,000 348,000 541,000 622,000 47,000 29,000 354,000 541,000 621,000 47,000 29,000 356,000 541,000

= 621,000

~47,000 29,000 369,000 541)000 621,000 47,000 29,000 360,000 541,000 470,000 47,000 29,000 363,000 1,582,000 1,593,000 1,594,000 1,607,000 1,598,000 1,450,000 1,252,000 1,297,000 1,208,000 1,249,000 1,275,000 1,205,000 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 Residential spaceheating Commercial Industrial Municipal and other (Includes Unbilled Revenue)

Total gas revenue Gas Expense (000's)

Gas purchased for resale-Other operation Maintenance Depreciation Taxes local, state and other Total gas expense Operating Income before Federal Income Tax Federal income tax Operating Income from Gas Operations (000's)

Gas'Operating Ratio %

Gas SalesTiierms (000's)

Residential Residential spaceheating Commercial Industrial Municipal

- Total billed Unbilled sales Total gas sales Transportation ofcustomer-owned gas Total gas sold and transported Gas Customers at December 31 Residential "Residential spaceheating Commercial Industrial Municipal Transportation Total gas customers

. Gas Therms (000's)

Purchased for resale Gas from storage Other Total gas available Cost ofgas per therm (excluding gas from storage)

Total Daily Capacity-Therms at December 31~

Maximum daily throughput Therms Degree Days (Calendar Month)

For the period Percent colder (warmer) than, normal 6,436 138,552 s43,311 10,842 6,439 150,383 44,781 9,859 6,770 165,832 46,897 9,371 6,456 183,405 44,274 6,418 6,354 157,458 40,196 6,761 6,508 s159,501 43,534 9,674 19,267 218,408 21,171 24,959 35,703 264,573 19,755 231,217 17,279 236,496 261,724

'235,728 132,512 39,307 8,510

'0,465 23.711 214,505 124,086 32,850 8,483 8,754 21,365 129,596 34,818 8,515 9,259 22,209 129,779 39;830 8,383 11,435 26,724 152,623 36,306 8,401 9,776 23,980 141,291 43,506 9,006 11,815 29,411 235,029 216,151 231,086

. 204,397 195,538 26,820 6,569 33,487 7,952 19,577 2,869 21,991 3,820 26,695 5,545 22,870

',137

$ 25,535

$ 20,251 74.6 74.8

$ 15,733-75.7

$ 21,150

$ 16,708 75.5

$ 18,171 76.3 74.1 9,068 253,655 71,509 13,000 10,580 10,374 267,697 86,413 20,174 15,514 8,780 287,614 78,993 12,437 11,410 10,321 277,267 84,152 17,873 12,319 9,644 262,458 77,617 18,536 13,350 10,255 244,655 83,167 22,033 17,985 400,172 378,095 399,234 13 357,812 3,291 401,932 20,320 381,605 (22,840) 399,247 361,103 127,196 109,835 358,765

~

422,252 400,172 101,985 105,303 83,594 378,095 67,496 24,834 206,458 24,139 210,710 17,213 1,042 1,039 270 19,114 228,096 18,378 932 1,010 424 21,448 222,918 22,410 219,242 23,321 215,120 17,677 1,095 1,067 367 18,151 921 983 423 17,920 960 984 401 16,771 1,035 1,026 147 258,647 254,413 250,271.

264,844 261,917 267,954 381,632 2,317 408,0444 1,967 384,643 16,755 1,140 426,941 1,764 366,684 2,525 360;493 53,757 1,059 415,309 402,538 4

369,209 428,705 410,011 383,949 32.67t!

33.43) 36.03)

=

35.74t6 31.7616 32.51l!

4,485,000 4,485,000 3,744,500 3,443,240 4,485,000 3,719,050 4,485,000 3,539,820 4,485,000 3,768,470 4,485,000 3,539,260 6,981 3.4 6,146 5,924 7,109 6,862 6,423 (8.4)

(1 1.8) 5.9 1.6 (4.3) ssiwork sssiysis, reflects the maximum dsmssd which ihe 6'Method fordetermining daily capacity, based on current transmission systems can accept without a deficiency.

526,443 470,938 460,750 527,555 483,766 445,591

l3ttot CtttGttllttl

. (as ofJanuary 1, 1993)

Keith W. Amish Former Vice Chairman ofthe Board, Rochester Gas and Electric Corporation NlllamBalderston ill Executive Vice President, The Chase Manhattan Corporation Paul N Brlggs Chairman of the Executive and Finance Committee, Rochester Gas and Electric Corporation Angelo J. Chlarella President and Chief Executive Officer, Midtown Holdings Corp.

Allan E. Dugan Senior Vice President, Corporate Strategic Services, Xerox Corporation Hatacha P. Dykman Former Chairman ofthe Board ofTrustees, Center for Governmental Research, Inc.

NlliamF. Fowble Senior Vice President and Executive Vice President, Imaging, Eastman Kodak Company Jay T. Holmes Senior Vice President-Corporate Affairs and Secretary, Bausch &Lomb Incorporated Roger N Kober Chairman of the Board, President and Chief Executive Officer, Rochester Gas and Electric Corporation Theodore t.. Levlnson Former President and Chief Executive Officer, Star Supermarkets, Inc.

Constance M. Mitchell Former Program Director, Industrial Management Council of Rochester, New York, Inc.

Cornelius J. Nurilhy Senior Vice President, Goodrich &Sherwood Company ArthurN. Richardson President, Richardson Capital Corporation N. Richard Rose Former President, Rochester Institute ofTechnology Harry G. Saddock Former Chairman ofthe Board and

. Chief Executive Officer, Rochester Gas and Electric Corporation Committees of the Board of Directors Execurtve An+ FiNANce Keiih W. Amish WilliamBaldcrsion III Paul W. Briggs~

Allan F Dugan

~ Roger W. Kober Cornelius J. Murphy ArthurM. Richardson Hany G. Saddock

'Chairman Avnrr Paul W. Bilges Angelo J. Chiarella Allan E. Dugan Naiacha P. Dykman*

WilliamF." Fowble Theodore L Levinson Constance M. Mitchell M. Richard Rose Coatillrrree 0'r MANACLE!ENr WilliamBalderston III Paul W. Briggs*

WilliamF. Fowb!e Comelius J. Murphy ArthurM. Richardson M. Richard Rose NOMrNATING WilliamBaldersion III Naiacha P. Dykman Jay T.Holmes p

Constance M. Mitchell ArthurM. Richardson*

Harry G. Saddock

'.(ttmall (as ofJanuary 1, 1993)

Roger R Keber Chairman of the Board, President and Chief Executive Officer Age 59, Years of Service, 27 RobertC. Henderson Senior Vice President, Controller and Chief Financial Officer Age 52, Years of Service, 29 David K. Lanlak Senior Vice President, Gas, Electric Distribution and Customer Services Age 57, Years ofService, 38 Robert E. Smith Senior Vice President, Production and Engineering Age 55, Years of Service, 33 David C. Helllgman Vice President, Secretary and Treasurer Age 52, Years of Service, 29 Robert C. Mecredy Vice President, Ginna Nuclear Production Age 47, Years ofService, 21 lYilfredJ. Schrouder, Jr.

Vice President, Employee Relations, Public Affairs and Materials Management Age 51, Years ofSeivice, 30 Daniel J. Baler Assistant Controller Age 46, Years ofService, 9 John M. Kuebel Auditor Age 57, Years ofService, 28 Thomas S. Richards General Counsel Age 49, Years of Service, 1

El Prioredooreeyeledpoper.

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Requests forInformation Investors and security analysts seeking information about the Company should contact David C.

Heiligman, Vice President, Secretary and Treasurer.

Form fD.ffAnnual Report Shareholders may obtain a copy of the Company's 1992 annual report on Form 10-K, as filed with the Securities and Exchange Commis-sion, without charge, by writing to the Secretary.

Shareholder Services Shareholders with questions about dividend payments, address changes, missing certificates, ownership changes and other account informa-tion should contact our transfer agent.

Dividend Payment Dates RG&E's Board ofDirectors meets quarterly to consider the payment of dividends. Dividends on Common Stock are normally paid on or about the 25th ofJanuary, April,July and October. Dividends on the Preferred Stocks are payable, as declared, on or about the 1st ofMarch, June, September and December.

Dividend Direct Deposit Shareholders can elect to have their quarterly cash dividends electroni-cally deposited into their personal bank accounts. Deposits are made on the date the dividend is payable. If you would like to take advantage of this service, contact our transfer agent.

Dividend Reinvestment Common Stock shareholders who wish to acquire additional shares free ofbrokerage commissions or service charges are invited tojoin RG&E's Automatic Dividend Reinvestment and Stock Purchase Plan. Under the 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.

Duplicate Mailings Shareholders with more than one accou'nt generally receive duplicate mailings of annual and other reports.

To eliminate additional mailings, write to our transfer agent. Enclose labels or label information, where possible. Separate dividend checks and proxy material willcontinue to be sent for each account ofrecord.

Stock Listings RG&E's Common Stock is listed on the New York Stock Exchange and is identified by the stock symbol RGS.

The Preferred Stock issues are traded on the over-the-counter market.

Corporate Office Rochester Gas and Electric Corporation 89 East Avenue Rochester, NY 14649 (716) 546-2700 Agent forAutomatic Dividend Reinvestment and Stock Purchase Plan The First National Bank ofBoston Dividend Reinvestment Unit MailStop: 45-01-06 P.O. Box 1681 Boston, MA02105-1681 (800) 442-2001 Transfer Agent and Registrar The First National Bank ofBoston Shareholder Services Division Mail Stop: 45-02-09 P.O. Box 644 Boston, MA02102-0644 (800) 442-2001

'irst Mortgage Bond Trustee and Paying Agent Bankers Trust Company Attn: Security Holder Relations P.O. Box 9006 Church Street Station New York, NY 10249 (800) 735-7777 ROCbNCCl C4$ IIAdBCCltiC GNpNlliOO

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