ML17265A595

Rg&E 1998 Annual Rept.

ML17265A595
Person / Time
Site:	Ginna
Issue date:	12/31/1998
From:	ROCHESTER GAS & ELECTRIC CORP.
To:
References
NUDOCS 9903160358
Download: ML17265A595 (61)

Text

~ CATEGORY ly REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:9903160358 DOC.DATE: 98/12/31 NOTARIZED: NO 'OCKET ¹ FACIL:50-244 Robert Emmet Ginna Nuclear Plant, Unit 1, Rochester G 05000244 AUTH.NAME . AUTHOR AFFILIATION

• ' . Rochester Gas 8 Electric Corp.

RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"RG&E 1998 Annual Rept."

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Cs~rrently RGd'E supplies electric and gas service wholly within upstate New York in a nine-county area centering aboi<t the City of Rochester. The ourney j

to energy choice for coiisumers opens i<p new opporturuties. We'e no longer boi<nded by the borders of our traditional service frairchise territory.

Our traditional services inclr<de the prodhrctio<r, transnrission, distribi<tion and sales of energy in a service territory'of about one million people. The service territory is well diversified among residential, comniercial and industrial customers. The City of Rochester is the fourth largest in New York State and a major industrial center. Multi-national con<merce in the Greater

.Rochester Region accounts for 40 percent of all exports from New York State and makes our area the number one per-capita exporting comnu<nity in the nation. Our territory also has a substantial siiburban area with commercial growth and large, prosperous farming regions.

RGB'Es unregulated subsidiaries, Energetix, Inc. and Griffith Energy, Inc. allow r<s to be a si<ccessfi<l competitor throughout Upstate Neiv York in the emerging energy marketplace which is driven by consr<mer options for energy supplier choice and an expanded array of energy services.

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Firt<11Cil. HiGHl iGHTS 1998. 1997 Change Financial Data <Dollars in Thousandsl

.Operating revenues: Electric $ 687,970 $ 700,329 (2)

~ Gas $ 275,177 $ 336,309 (18)

S 71,215

$ 907,202 $ 891,297 Other'perating expenses 2 Operating income $ 127,160 $ 145,341 (13)

Net income S 94,138 $ 95,360 (1)

Earnings applicable to common stock S 89,296 $ 89,555 Rate of return on average common equity 11 22% 11.00%

Common Stock Data Weighted average number of shares outstanding lthousandsl Basic 38,462 38,853 (I)

Diluted 38,600 38,909 (1)

Per. common share:

Earnings Basic $ 2.32 $ 2.30 Earnings Diluted $ 2.31 $ 2.30 Dividends Paid $ 1.80 $ 1.80 Book Value (year end) $ 20.94 $ 20.80 1 Year-end market price $ 31.25 $ 34.00 (8)

Number of Common Stock Shareholders at December 31 28,995 319337 (7)

Operating Data Sales (rhousands)

Kilowatt-hours to retail customers 6,562,532 6,805,719 (4)

Kilowatt-hours to wholesale customers 1,671,959 1,218,794 37 Therms of gas sold and transported 472,933 538,062 (12)

Net additions to utility plant, less allowance

$ 129,286 $ 84,068 . 54, for funds used during construction {8 ousands'I Employees (year end) 2,333 3,938 19

'Unregulated business re3enues

Sl-IAR EHOLDER'S LETTER I

It was just a few nu'nutes past Midnight on September 7 dark but calm. The clock placed Rochester in the early morning hours of Labor Da) 1998. Movements later and without warn-ing, the calm was porn apart by an eight-mile-wide channel of 80-mile-per-hour winds that bent torrential rains horizontally and forged a path of destruction down a 100-mile corridor in upstate New York. It spent itself in just 45 nu'nutes but left behind an alley of devastation strewn with uprooted trees, smashed homes, broken power poles, and tangled and severed power lines. More than 100,000 RGd'E electric customers were without power.

was nothing new for us in 1998. It turned Whatever else we do, we need to keep the lights out to be a record-breaking year for on and the gas flowing to our customers. We did it declared electric storm emergencies- well in 1998, as our predecessors had done before us.

nearly a dozen and more than twice the Adding to excellent storm response, our power plant yearly average. But, using every resource performance was also strong, topped by a record year available in following our well-rehearsed electric for our Ginna Nuclear Power Plant. The Ginna plant emergency response plan in the Labor Day storm, operated without shutdowns in 1998, lowering our we were able to restore power to half of our affected cost of production and providing a reliable source of customers within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and to all the rest within power for our customers.

a week. However, doing well with what we have is not Besides testing our planning and resources, the enough. We continued to invest in our distribution Labor Day storm served as a reminder of what is system to improve its performance and make the important to our customers. While they welcome the changes necessary to give customers a choice of significant changes in our business that are bringing suppliers. A new more flexible customer information them a choice of energy services suppliers, they do not system was also installed, along with new networked expect to be put at risk during the transition. Unlike personal and enterprise computing systems.

the deregulation of many other industries, the transi- Not all the challenges originated from within tion of this industry cannot leave any customers our industry. For example, our response to the much behind. Whether or not aided by competitive choice, publicized Y2K problem was in full swing during we are expected to bring lower rates, high reliability 1998. You have probably learned that the problem and access to everyone, while continuing low-income, stems from computer systems that recognize only the environmental and other social programs. This last tno digits of a iear. They therefore cannot distin-balancing act requires that our company continually guish the coming year 2000 from the year 1900. At recognize and respond to all of these challenges. We RGB'E we'e been working on this issue since 1996.

welcome this challenge and appreciate the customers And while there is a certain amount of exaggeration who have given us the opportunity to serve them tor surrounding the description of this problem, we are many years. In this letter I will share ivith you some taking it very seriously and, as is described in the of the progress we made during the 150th year of our XIanagement Discussion and Analysis section of this history in meeting our challenges. annual report, we ivill be ready to provide reliable energy in the next century..

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customers, and we are committed to devel-oping mutually beneficial business relation-ships with them. There is a tremendous amount of change and work behind this shift and it has been accomplished in record time when compared to similar shifts in other, often less essential, industries.

To this point I have been talking about maintaining operational excellence

'n our traditional regulated utility business r->

and preparing that business and its sys-tems for the introduction of competitive P, ~

lh p choice. These components of our business are each important in their own right. The All this takes place as we continue to reduce challenge, however, is to balance them by electric costs for the customers served under our developing new sources of revenue and earnings. Our regulated rates; Residential customers will see an response to this challenge prompted the most exciting average reduction of ten percent by 2001, and corn- 'hange for us last year.

mercial and industrial customers will realize savings In 1998 we began to operate ENERGETtX, of 15 Percent or more. Our gas distribution rates an unregulated subsidiary that delivers energy prod-have not increased since 1994, and there will be no ucts and services to customers throughout upstate increase forat least another heating'season as we New York A great deal of time and effort work with the Public Service Commission to bring directed at the development of a viable and increased customer choice to the gas business. diversified ENERGETtX~ business plan. It is a plan I have been talking about the journey to energy that is flexible to the evolving competitiveness of the choice for several years now in this letter and at our retail electric and natural gas markets over time and annual meetings. With the arrival of electric energy will meet our goal of becoming the premier energy provider choice for our customers, we have moved service company in upstate New York. Since its incep-bevond anticipation to implementation. The first phase tion, ENERGET!X has put the plan into action and of customer choice in electric supply started in the succeeded in attracting thousands of commercial and summer of 1998 and by the end of January this year residential gas and electric customers, as well as all ten percent of our electric load that was eligible was customers for its ServiceCare" Appliance Warranty being served by eight competing, unregulated energy product line. Operating from separate headquarters service companies, including our own subsidiary, in Rochester since June, 1998, ENERGET!X'" has ENERGET!X~. This was being done under our "single grown to 26 employees.

retailer" model, unique to RG<%E in New York State. 'In August 1998, ENERGETtx" acquired Griffith Under this model, the new comPetitive energy services Oil, Inc., the second largest oil and propane distribu-company becomes the single supplier of electric service tion company in Neiv York State, ivith 65,000 retai to the end-use customer. The energy services comPany customers, 60,000 of whom reside outside RG@Es bills the customer. RGB:E, in turn, bills the net energy service territorv. Griffith operates throughout upstate company for the service of moving poiver through geiv York from 16 offices and distribution centers our system. The net companies become our ivith 338 employees. It provides a diversification of

the ENERGETtX'" product line to include liquid fuels included global merger and acquisition activity along and a base from which to expand the ENERGET!X'" with power plant sales by companies wanting to get electric and natural gas business. This diversification out of the generating business. In view of our signifi-of products and the established presence of Griffith cant commitment to nuclear generation, sales of these Oil will allow us to capitalize economically on the . assets at today's prices are not in the best interest of emerging opportunities in upstate New York, outside our shareholders.

of our service territory, where competitive choice has There'l be a number of factors, some real, just begun. We'e off to a fine start. From virtually soine imagined, that will affect the value of our stock nothing in 1997, we finished 1998 in the unregulated both positively and negatively over time. We cannot energy business with thousands of customers all over influence all of the factors. We can, though, run the upstate New York, 364 employees and $ 81.8 million business well, adopt a solid and flexible plan for in revenue. growth and execute it. That is what we are doing Our strategic focus on upstate New York is and I believe this is what will continue to make RG5c) designed to have ENERGETtX" build upon our a solid investment. We very much appreciate the sup-existing strengths. Griffith is well established through- port of our shareholders as we move forward with the out the region and we understand how to do business plan on this journey.

here. Having continually produced high levels of In 1999 the journey to competitive choice will reliability and customer satisfaction with the lowest continue. An additional ten percent of our electric rates in the region, RG8cE enjoys a fine reputation. load will become eligible to be served by competitive While our regulated service territory has about suppliers this summer. The electric transmission 344,000 electric customers, our core market contains system in New York, including RGBCE's transmission more than two million additional customers. The lines, is scheduled later this year to come under the opportunities are great. day-to-day control of an Independent System Operate Looking back on 1998, I believe we can (ISO) regulated by the Federal Energy Regulatory fairly conclude that we excelled at operating our Commission. The ISO's job is to ensure fair transmis.

business and adapting to competitive choice while sion access and reliable operation as electric energy experiencing dramatic changes in the nature of our competitors move power throughout the state. The industry. We managed the impact of a very warm regulatory process of creating the ISO is not complett heating season, lower rates, the cost of adapting the and the market for capacity and energy will not fully system to competitive choice and investments in develop until this essential system goes into operation growing the unregulated business, yet still managed While RGB E was not required to do so, many to increase per-share earnings modestly. However, other electric energy utilities in . Jew York State agree after a terrific performance in 1997, the performance as part of their settlements with the PSC, to sell their of our stock in 1998 was disappointing. fossil-fueled and hydro electric power plants. Auctio Investors and analysts are trying to understand were conducted in 1998 and the sales are expected n the changes and evaluate their impact on energy utility be concluded in 1999, opening the wholesale electric stocks. This is a time of change and uncertainty in our market to competitive forces never before seen here.

industry and it's reflected in the pricing of utility stocks Our generating business will also change in 195 today. Although our three-year return compares very We ivill close our coal-fired Beebee Station and acti-favorably with the other companies in the Edison vate the Allegany gas-fired plant we acquired recentl Electric Institute Index, our stock performance in 1998 as part of the settlement of our long standing disput<

was disappointing. In 1998 utility stock prices ivere with an independent power producer. Of significant influenced by large company growth strategies that importance to P.GB;E, given our relatively heavy

reliance on nuclear generation, is the Public Service formation has been mailed to shareholders along with Commission's new generic proceeding to investigate this annual report. I urge you to'review the contents the future of nuclear power in New York State. This of that document so that you may better understand proceeding, which will consider both changes in the this important milestone in our history.

ratemaking treatment of the plants as well as possible I began this letter by mentioning the devastating divestiture, is expected to be concluded later this year.

Labor Day Storm that affected a third of our electric We do not believe that the possible sale of any customers. I can't say enough about our RG5cE people nuclear plant should be considered apart from the for their outstanding performance, particularly the total impact on customers who, under any proposal, remarkable restoration of power in the wake of that will be expected to continue to pay much of the unre- storm on Labor Day. Moreover I want to express my covered cost of these plants while being exposed to an sincere appreciation for the effort of all RGBcE people immature and potentially volatile unregulated energy in the day-to-day work of making your company a market. We need to be sure that we can deliver on the reliable, safe and customer friendly energy provider.

promise to customers that they will have available, if Their performance reflects the new RGScE that is being they choose, declining fixed regulated rates, before we shaped and managed to do more through efficiency, lose control of the energy cost. The size of our i'nvest- process planning and innovation. This commitment to ment in nuclear power makes this a very important deal positively with change was confirmed by a five-to-issue for us, but it is equally important to our cus- one margin vore by our distribution employees to reject tomers and the supply of energy in New York State, an attempt to bring a union to the company.

which is 70 percent nuclear. This is not something Finally I want to extend our thanks to Robert E.

that can be subjected to experimentation or rushed to Smith who retired last year after 39 years of dedicated a conclusion.

service to RGScE. His engineering expertise and fine This is also the year in which we are scheduled management style led our electric generating opera-to address bringing competitive choice to the retail tions to their high standards of excellent natural gas market. While the ability to choose and performance. Missed also will be another gas commodity supplier has been available to wise advice and balanced counsel

'he all customers since 1996, in practice it has been mostly of our board member Constance F confined to the largest customers. The Public Service Mitchell who will leave her position Commission is now considering the issues that are at the annual meeting this year.

involved in making supplier choice available to all Connie has been a valuable part customers. This raises many of the issues already of our Board since she joined it involved'in the on-going changes in electric supply. in 1981. We would do favell to In particular, what role the regulated distribution find such people,.to serve our companies riillcontinue to play in supplying the gas Company in the future and commodity is under discussion. We will be actively I wish them both well.

involved in this process this year and expect to begin to implement changes in the fall.

As contemplated by the regulatory changes that began last year, we are proposing to form a holding Thomas S. Richards company this year to be called RGS Energy Group, Februan 1, l999 Chairman of the Board.

Inc. Shareholder approval for this proposal ivill be President and Chief the focus of our upcoming annual meeting. A rather Executive Officer lengthy, but necessary and complete, description of the

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DIAnAGEIhEnT S Discussion Ano AnwLYsis OF FINANCIALCONDITION AND RESULTS OF OPERATIONS INTKODUCTION The following is Xianagement's assessment of certain significant factors affecting the financial condition and operating results of Rochester Gas and Electric Corporation ("RGB E") and its subsidiaries (RGB'E, together with its subsidiaries, is referred to as "the Company" ) over the past three years. The Consolidated Financial Statements and the Viotes thereto contain additional dam. For the twelve months ended December 31, 1998, 66 percent of the Company's operating revenues were derived from electric service, 27 percent from natural gas service, and 7 percent from unregulated

'usinesses.

The discussion presented below contains statements ivhich are not historic fact and which can be classified as forward looking. These statements can be identified by the use of certain words which suggest forward looking information, such as "believes," "will,""expects," "projects,"

"estimates" and "anticipates". They can also be identified by the use of words which relate to future goals or strategies. In addition to the assumptions and other factors referred to specifically in connection with the forward looking statements, some of the factors that could have a significant difference in ivhether the forward looking statements ultimately prove to be accurate include:

1. any state or federal legislative or regulatory initiatives that affect the cost or recovery of in'vestments necessary to provide utility service in the electric and natural gas industries. Such initiatives could include, for example, changes in the regulation of rate structures or changes in the speed or degree to which competition occurs in the electric and natural gas industries;

2. any changes in the ability of the Company to recover environmental compliance costs through increased rates;

3. any changes in the regulatory status of nuclear generating facilities and their related costs,.

including recovery of costs related to spent fuel and decommissioning;

4. any changes in the rate of industrial, commercial and residential growth in the Company's service territories;

5. the de'i elopment of any new technologies ivhich allow customers to generate their own energy or produce lower cost energy;

6. any unusual or extreme weather or other natural phenomena;

7. the ability of the Company to manage profitably its net unregulated operations;

8. cerrain unknowable risks involved in operating unregulated businesses in net terrirories and net industries;

9. the timing and extent of changes in commodity prices and interest rates;

10. an) unanticipated developments associated ivith identify'n. assessing, tixing an J testing the modifications necessary to mitigate Year 2000 compliance problems, including the possible indirect impact of customers, suppliers and other business partners ivho do not sufficiently mitigate their Year 2000 compliance problems: and

11. any other considerations that ntay be disclosed from time to time in the Company's publicly disseminated documents and Iilings.

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Earnings Summary

'perating performance of the Company's generating plants, expens'e control, the sale of electric energy to wholesale customers, and the recognition of $ 17.4 million of non-recurring income during the year (see Other Statement of Income Items) allowed the Company to keep 1998 earnings applicable to Common Stock at abo'ut the same level as 1997, despite rate decreases and warmer temperatures during the 1998 heating seasons.

Basic earnings per share were $ 2.32 in 1998,'compared with S2.30 in 1997, and $ 2.32 a year earlier. Earnings per Common Share - Diluted were S2.31 in 1998, 52.30 in 1997, and S2.32 in 1996.

Earnings per share in 1998 were improved by approximately 5.02 per share resulting from the buyback of Common Stock under the Company's Stock Repurchase Program.

For the twelve month period ending December 31, 1998, the Company's unregulated subsidiary, Energetix, Inc., had a pretax operating loss of S4.1 million, which reduced consolidated earnings by approximately S0.06 per basic share. This loss is primarily due to initial stan-up and marketing costs.

Xloreover, ivhile Energetix divas formed Januarl I, 1998, the first revenues ivere not received until April of 1998. In addition, revenues from Griffith Oil Co., Inc., a company acquired by Energetix, only reflect sales since acquisition in August 1998. Energetix revenues for l 999 from electric and gas operations are expected to increase over 1998 levels as Energetix expands its customer base, although no assurance may be given that Energetix ivill achieve a net operating gain in 1999 or that new business opportunities ivill not impacr its operating results.

The impact of developing competition in the energy marketplace may affecr future earnings. The Competitive Opportunities Case Settlement (the -Senlement", see description beloiv) alloivs for a phase-in to open electric markets ivhile lowering customer prices and establishing an opportunity for competitive returns on shareholder investments. The nature and magnitude ot the potential impact of the Settlement'on the business of the Company nill depend on several factors, including the availability of qualified energy suppliers in the Company's service territory, the degree ot customer participation

<<nd ultimate selection ot an alternative energy supplier, the Company's ability to be competitive by controlling its operating expenses, and the Company's ultimate success in the development of its unregulated business opportunities as permitted under the Settlement.

Although under the current regulatory environment the Company does not earn a return on the gas commodity it acquires for distribution, future earnings may also be affected, in part, by the ultimate outcome of a November 1998 New York Sute Public Service Commission ("PSC") gas restructuring policy statement. That policy statement concludes that the most effective ivay to establish a robust competitive market for gas supply in New York State is for local distribution businesses, such as the Company, to exit the merchant function of acquiring gas for distribution. In addition, local distribution companies must cease assigning capacity to customers migrating from sales to transportation service no later than April 1, 1999. The nature and magnitude of the potential impact of these policies will depend on individual negotiations the Company will undertake with PSC Staff and other interested parties on RGScE-specific restructuring, as well as a number of Statewide collaborative efforts that will deal with such issues as provider of last resort, reliability, recovery of stranded costs, and market power as the transition is made to a more competitive gas business.

Coatpetition PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT.

During 1996 and 1997, RG8'E, the staff of the PSC and several other parties negotiated'an agreement which was approved by the PSC in I

November 1997 (the "Senlement"). The Settlement sets the framework for the introduction and development of open competition in the electric energy marketplace and lasts through June 30, 2002. Over this time, the way electricity is provided to customers will fundamentally change. In phases, RG5'E will allow customers to purchase electricity, and later capacity commitments, from sources other than RG5;E through its retail access program, Energy Choice. These energy service companies will compete to package and sell energy and related services to customers. The competing energy service companies will purchase distribution services from RG8cE who will remain the sole provider of distribution services. and will be responsible for mainuining the distribution system and For responding ro emergencies.

The Settlement sets RGE'.E's electric rates for each year during its five-year term. Over the five-year term of the Settlement, the cumulative rate reductions for the bundled service will be as folloivs:

Rate Year I (July I, 1997 to June 30, 1998) 53.5 million: Rate Year 2 S 12.8 million; Rate Year 3 S27.6 million; Rate Year 4 S39.5 million; and Rate Year 5 S64.G n>i)lion.

The Settlement permits RG5;E to fund its unregulated operations ivith up to S100 million.

In the event that RG5 E earns a return on common equity in excess of an effective rate of 11.50 percent over the entire five-year term of the Senlement, 50 percent of such excess ivill be used to ivrite down deferred costs accumulated during the term. The other 50 percent of the excess ivill be used to ivrite down accumulated deferrals or investment in electric plant or Regulator) Assets (ivhich are deferred costs ivhose classification as an asset on the balance sheet. is permitted by SFAS-71, Accounting for the Effects of Certain Types of Regulation). If certain extraordinary events occur, including a rate of return on common equity beloiv 8.5 percent or above I4.5 percent, or a preux interest coverage beloiv 2.5 times. then either the Company or any other party to the Settlement ivould have the right to petition the PSC for review of the Settlement and app opriate remedial action.

The Settlement requires RG5 E to functionally separate its three regulated operations:

distribution, generation and reuiling. Additionally, unregulated energy reuiling operations must be

0 structurally separate from the regulated utility functions. Although the Senlement provides incentives for the sale of generating assets, it does not require RGRE to divest generating or other assets or lvrite-off stranded costs. Additionally, RGikE lvill be given a reasonable opportunity to recover substantially all of its prudently incurred costs, including those perraining to generation and purchased popover.

RGB'E believes that the Settlement lvill noi adversely affect its eligibility to continue to apply certain accounting rules applicable to regulated industries. In particular, RG8 E believes it will continue to be eligible for the treatment provided by SFAS-71 which allolvs RGRE to include assets on its balance sheet based on its regulated ability to recoup the cost of those assets. However, this may not be the case with respect to certain operational costs associated lvith non-nuclear generation (see Note 10 of the Notes to Financial Statements under the heading Other platters, EITF Issue 97-4, Deregulation of the Pricing of Electricity).

The Company's retail access program, Energy Choice, divas approved by the PSC as part of the Settlement and went into effect on July 1, 1998. Details of the Energy Choice Program are discussed belolv.

One party to the Senlement negotiations has commenced an action for declaratory and injunctive relief as to certain provisions of the Settlement and rhe PSC's approval of it. The Company is unable, at this time, to predict the ourcome of this action.

BUSINESS AND FINANCIALSTRATEGY.

Under the terms of the Settlement, the Company has functionally separated its generation, distribution, and regulated energy services businesses. Consistenr with the Settlement, the Company has begun to implement a business and financial strategy which consists of the following: (1) the reorganization of its corporate structure into a holding company in order to more fully implement'the separation of its regulated and unregulated businesses, (2) the establishment of a separare unregulated subsidiary, Energetix, Inc. ("Energetix"), which will be able to compete for energy, energy services and products'both in arid outside the Company's existing franchise service territory, and (3) the development of an integrated financial strategy that includes new business initiatives and a Common Stock share repurchase program of $ 145 million.

Energy Choice. On July '1, 1998, the Company launched its full-scale retail Energy Choice

, Program. There are three basic components of the sale of energ): the sale of electricity which is the amount of energy actually used by the consumer, the sale of capacity ivhich is the ability through generating facilities or otherlvise, to provide electriciti lvhen it is needed, and the sale of distribution, lvhich is the physical delivery of electricity ro the consumer. Historically, the Company has sold all three components bundled together for a fixed rate approved by the PSC. Up to ten percent of RGRE's retail electric customers can nolv seek out or be approached by alternative energy service companies for electricity to be delivered over RGS:E's distribution system. Participation in Energy Choice is limited to no more than 10 percent of RGRE's total annual retail electric kilolvatt-hour sales during the first year of the program. This limit increases to 20 percent the second year and.30 percent in the third year. In July, 200 I, all retail customers lvill be eligible to purchase energy frOm <<Iternative energy seI"vlcc colupIlnies ~

The phase-in of the Energy Choice Program over, the next feiv years eventually ivill give retail electric customers the opportunity to purchase energy. capacity and retailing services from competitive energy service companies. They may also continue to purchase fully bundled electric service from RGRE under existing retail tariffs Energy Choice adopts the single-retailer model for the relationship between the Company as the distribution provider. qualified energy service conlp'lnles, 'lnd retail (end-use) custonlers. In this model, retail custonlers h;1've the opportunity fof choIce In 'their energy service colnpany and receive only one electric bill from the company that serves them. XX'ith the exception of enlergency sef'vices, 6'hich

remain the Company's responsibility, the retail customers'rimar) point of contact is ivith their chosen energy service company.

'nder the single-retailer model, energy service companies are responsible for buying or otherwise providing the electricity their retail customers ivill use, paying regulated rates for transmission and distribution, and selling electricity to their retail customers (the price of ivhich would include the cost of .

the electricity itself and the cost to transport electricity through RGRE's distribution system).

Throughout the term of the Settlement, RG8'E wiII continue to provide regulated and fully bundled electric service under its retail service tariff to customers ivho choose to continue with or return to 'such service, and to customers to whom no competitive alternative is offered.

Unt/l the development of a wholesale market for generating capacity, there drill be no suitable mechanism for the reallocation, from the regulated utility to the energ) service company, of responsibility for ensuring adequate installed reserve capacity. Accordingly, during the initial ".Energy Only" stage of the Energy Choice Program (July I, 1998 to July I, 1999), energy service companies will be able to choose their own sources of energy supply, ivhile RG<t<:E evil) continue to provide to them, through its bundled distribution rates, the generating capacity (installed reserve) needed to serve their retail customers reliably.

During the -Energy Only" stage, energy service companies have the option of purchasing "full-requirements" (i.e. delivery services and energy) from RGB E.

During the "Energy and Capacity" stage, scheduled to commence July 1, 1999, energy service companies will no longer have the option of purchasing "full-requirements" from RG8 E and ivill be responsible for procuring generating capacity, as well as energy, to serve the loads of their retail customers. Distribution charges will be accordingly reduced as described beloiv.

According to the terms of the Settlement, if a Statewide energy and capacity market is not implemented by July 1, 1999, RG8'E may petition the PSC for a delay in the implementation of the "Energy and Capacity" stage of RGBcE's retail access program. At this time, a functioning Statewide energy and capacity market does not exist (see discussion under FERC Open Access Transmission Orders and Company Filings). If a functioning Statewide energy and capacit) market is not functioning in the near future, the Company will need to seek a delay of the scheduled commencement of the "Energy and Capacity" stage.

During the initial 'Energy Only" stage ot the Retail Access Program, RGS:E's distribution rate

, evil) be set by deducting 2.3 cents per kilowatt-hour from its full service (-bundled" ) rates. The 2.3 cents per kiloivan-hour is comprised of 1.9 cents per kiloivan-hoiir (an estimate of the ivholesale market price ot electricity) plus 0.4 cents per kilowatt-hour for its avoided cost ot retailing services.

During the "Energy and Capacity" stage, RGRE's distribution rates ivi)1 equal the bundled rate less RGRE's cost of the electric commodity and RG8;E's non-nuclear generating capacity. During this stage of the program. RGRE's distribution rates ivili be set by deducting 3. cents per kilowatt-hour.

inclusive of applicable gross receipts taxes, from its full service (-brindled-) rates. The 3.Z cents per kilowatt-hour is comprised ot 2.<) cents per kiloivan-hour (an estimate of the ivholesale market price of electric energy and capacity, inclusive of ross re<.'eipts taxes) plus 0.4 cents per kilowatt-hour (or its avoided cost of retailing services.

Through January 31. 1999. eight energy service companies. including Energetix. the Company's unregulated subsidiary, have been qualitied by RG8 E to serve retail customers under the Energ)

Choice Program. In addition to Energetix, these companies are Columbia Energ) I never XIarketing Corporation, Enserch Energy Services (Net York). Inc., Florida Poiver 2 Light (FPL Fnergy Servicesl, Inc.. %EX East. L.L.C. (Ken'nergy X'entures). northeast Energy Services. Inc. (XORESCO),

North American Energy. and Select Ener< ) Inc. (Northeast Utilities 5'holesale Poiver). As of January 31. 1999. all ener<y service co>npanies have opted to purchase "full-requirements from RGB:E to serve their retail customers. As -full-requirements" custcmlers. energy service companies are

<<ble to purchase electricity froni l<GRE at I.) cents per kilcnvatt-hour. RGB:E has distributed approximatel) 6 0,000(annulllzedl megawatt-hours to fetallcustomersofenergyservicecompanies,

thereb) reaching 100 percent of the first-year cap of IO'o for the full-scale program. This impact divas not significant because the loss of RGRE retail sales is roughly offset by the sale of distribution service and electricit) to energ) -service companies. Although it is too earl) to quantify at this time, a substantial part of this revenue loss is expecred to be offset by cost reductions resulting from the shift in retailing responsibilities from RGB:E to energy service companies.

Looking ahead to the latter part of 1999, up to 20% of the total annual electric sales xvill be eligible for retail access. With implementation of the Energy and Capacitv phase of the full-scale program, the Company ivill also be shifting the responsibility for purchasing not only electricity, but also capacity to these energy service companies. Similarly, there ivill be a slight revenue loss as a result of the increased back-out rate. However, the Company expects to manage this revenue impact ivith offsetting savings in costs no longer incurred for the acquisition and maintenance of capacity and increasing ivholesale revenues through the sale of available capacity.

The PSC initiated a Statewide proceeding to recommend "uniform business rules" dealing with electric retail access programs for each of the utilities it regulates. In addition to this proceeding, there are three other proceedings underway: Electronic Data Interchange,,Competitive Metering, and the Single Billing Option. These proceedings are intended to bring more consistency among New York State utilities and potentially offer additional services for energy service companies to provide. The outcome of these proceedings may ultimately result in changes to the Company's business, but at this time the Company cannot predict the scope of such changes.

Holding Company. During the second half of 1998, the Company filed applications with various regulatorv agencies, including the PSC, Securities and Exchange Commission ("SEC"), Federal Energy Regulatorv Commission ("FERC"), and the Nuclear Regulatory Commission ("NRC"), requesting approval of a corporate restructuring including the creation of a holding company. RGS Energy Group, Inc. ("RGS Energy" ), a New York corporation, was organized in November 1998 for the purpose of carrying out the restructuring.

Subject to regulatory and shareholder approvals, the Company anticipates forming the holding company structure by mid-1999. FERC approved the Company's application in late November 1998 and the NRC gave approval in December 1998. The remaining regulatory approvals are expected to be received before mid-1999.

Ar the Company's 1999 Annual!vleeting of Shareholders, shareholders ivill vote on a Plan of Exchange ivhich provides that all of the outstanding shares of RGRE common stock ivill be exchanged 'n a share-for-share basis for RGS Energy common stock. Upon consummation of the exchange, RGS Energy evil) become the parent company of RGRE..'vtoreover, RGB'E intends to transfer its unregulated subsidiaries, Energetkx and RGS Development Corporation, to RGS Energy immediately prior to the exchange so that RGS Energy xvill become the parent company of RG5;E and such subsidiaries.

The holding compan) structure is consistent ivith provisions of the Competitive Opportunities Settlement.

Unregulated Subsidiaries. It is part of RGB;E's financial strategy to seek growth by entering into unregulated bus'inesses. The Settlement alloivs RGRE to invest up to S I00 million in unregulated businesses. The first step in this direction divas the formation and operation of Energetix effective January I, 1998. Energetix is an unregulated subsidiary that brings energy products and services to the marketplace both ivithin and outside of RGRE's re ulated franchise territory. Energetix markets electricity. natural gas. oil, gasoline, and propane fuel energy services in an area extending in approximatel) a 150-mile radius around Rochesten

("

In August l 998. Ener'etix announced the acquisition of Griffith Oil Co.. Inc. Griffith"), the second largest oil and propane distribution con>pan) in Xeiv York State. Ener etix accounted for its acquisition of Griffith <<5 a purchase in the anlount ot 53 I.500.000. <<nd purchase accounting

<<djustnzents. including good'A'ill. <<re reflected in the consolitlated financial 'statements of the Company

<<t Decen>ber 3 I. I 998.

Griffith gives Energetix access ro 6i.000 nerv customers, 60.000 of which are outside of RGB Es regulated franchise territory. In addition to its current products, Griffith sells electricity, natural gas and other services offered by Energetix to its exisring customers. Griffith has approximately 350 emplo) ees and operates 16 customer service centers.

Additional information on Energetix's operations (including Griffith) is presented under the headings Operating Revenues, Operating Expenses, and is contained in Note 4 of the bootes to Financial Statements.

. During the second quarter of 1998, the Company formed a net unregulated subsidiary, RGS Development Corporation I "RGS Development" ). RGS Development divas formed to pursue unregulated business opportunities in the energy marketplace. Through December 31, 1998, RGS Development operations have not been material to the Company's results of operations or its financial condition.

Stock Repurchase Plan. By order issued April 24, 1998, the PSC approved a Stock Repurchase Plan providing tor the repurchase of Corumon Stock having an aggregate market value not to exceed S14i million. The Company began the repurchase program in May 1998 and has repurchased 1,507,000 shares of Common Stock for approximately 546.4 million through December 31, 1998.

The Company expects to repurcha>e up to an additional three million shares over the next nvo years.

PSC PROCEEDING ON NUCLEAR GENERATION.

~ g On %larch 20, 1998, the PSC initiated a proceeding to examine a number of issues raised by a Staff position paper on nuclear generation and the comments received in response to ir. In reviewing the Staff paper and parties'omments, the PSC:

1. adopted as a rebuttable presumption the premise that nuclear popover should be priced on a market basis to the same degree as i"

• ji

) poner from other sources,'~vith parties challenging that premise having to bear a substantial burden of persuasion,

2. characterized the proposals in the Staff paper as by and large consistent in concepr ivith the PSC's goal of a competitive.

market-based elecrricitv industrv.

3. questioned Staff's position that ivould leave fundin< and other decommissioning responsibilities ivith the sellers of nuclear popover interests and

4. indicated interest in the potential for a Xeiv York Xu<<lear Operatin Company (XYXOC) proposal to benefit customers through ett'icienc) gains and directed pursuit ot that matter in this nuclear generating proceeding or separately upon the tiling ot a formal XYXOC proposal.

The Company's potentially strandable assets in nuclear plant could be impacted b) the outcome of this proceeding. The initial collaborative conference for this proceeding divas held. on January 20, 1999. This proceeding is intended ro be completed in the fourth quarter ot 1999.

FERC OPEN ACCESS TRANS~IISSION ORDERS AND COXIPANY FILINGS.

On January 31, 1997, the Net York electric utilities filed a "Comprehensive Proposal To Restructure the Net York Wholesale Electric WIarket" ivith the FERC: As proposed, the existing New York Popover Pool (NYPP) will be dissolved and an independent system operator (NYISO) will administer a Stateivide open access tariff and provide for the short-term reliable operation of the bulk popover system iri the State. In addition to proposing a FERC-endorsed NYISO, the proposal calls for creation of a New York Power Exchange and a Net York State Reliability Council.

On June 30, 1998, FERC issued an Order that conditionally authorizes the establishment of the NYISO by the member systems of the NYPP. The order addresses areas of governance, standards of conduct and reliability. A NYISO Board of Directors has been formed. FERC has deferred consideration of the unexecuted tariff and agreements "filed under Section 205 of the Federal Power Act. FERC noted that these filings will be addressed in a future order, but at this time, no specific date has been set. FERC has also recommended that concerned parties revisit the independent system operator weighted voting distribution relative to governance. On October 23, 1998, the member systems of the NYPP filed a senlement agreement for a comprehensive senlement of governance issues and an explanatory 'roposed statement of the senlement agreement. The explanatory statement represents the settlement agreement to be in compliance with the Commission's June 30, 1998 Order.

Significant changes to pricing procedures now in effect within NYPP are expected, but it is unclear what effect these changes may have once other regulatory changes in New York State are implemented. At the present time, the Company cannot predict what effects regulations ultimately adopted by FERC will have, if any, on future operations or the financial condition of the Company.

PSC GAS STRUCTURING POLICY STATEMENT.

On November 3, 1998, the PSC issued a gas restructuring policy statement ("Gas Policy Statement" )

announcing its conclusion that, among other things, the most effective way to establish a competitive gas supph market is for gas distribution utilities to cease selling gas. The PSC established a transition process in which it plans to address three groups of issues: (1) individual gas utility plans to implement the PSC's vision of the market; (2) I<ey generic issues to be dealt with through collaboration among gas utilities, marketers, pipelines and other stakeholders, and (3) coordination of issues that are common to both the gas and the electric industries. The Company is in the process of evaluating this Gas Policy Statement and ivill respond to the specific requirements of the Order. The PSC has encouraged settlement negotiations ivith each gas utility pertaining to the transition to a fully competitive gas market.

COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIALPOSITION.

With PSC approval, the Company has deferred cerrain costs rather than recognize them oii its books ivhen incurred. Such deferred costs are recognized as expenses ivhen they are included in rates and recovered from customers. Such deferral accounting is permitted by SFAS- 1. These deferred costs are shoivn as Regulatori Assets on the Company's Balance Sheet and a discussion and summarization of such Regulatory Assets is presented in Nore 10 of the Notes to Financial Statements.

In a competitive electric market, strandable assets ivould arise ivhen investments made in facilities, or costs incurred to service customers, are not 1'ully recoverable in marker-based rates. Estimates of such strandable assets are highly sensitive to assumptions of competitive ivholesale'market prices. In a competitive natural gas market, strandable assets could arise ivhere customers migrate aivay from dependence on the Company for full service, leaving the Company ivith surplus pipeline and storage capacity, as favell as natural gas supplies. under contract. A discussion ot strandable assets is presented in Note I0 ot'he Notes to Financial Statements.

At December 31, 199S, the Company believes thar its regulatory assets are not impaired and are probable of recovery. The Settlemenr in rhe Competitive Opportunities Proceeding does not impair the opportunity of the Company to recover its investment in these assets. However, the PSC issued an Opinion and Order Instituting Further Inquiry on %larch ZO, 1998 to address issues surrounding nuclear generation. The ultimate determination in this proceeding could have an impacr on strandable assets and the recovery of nuclear costs. The initial meeting in this Inquiry divas held in January 1999 and such a determination is unlikely before year-end.

Rates and Regrilatoiv Matters GAS PROPOSAL AND INTERIM SETTLEilIENT.

In August 1998, prior to issuance of the PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Sratement above), RG8'E had commenced negotiations ivith the PSC staff and other parries to develop a comprehensive multi-year senlement of various issues, including rates and the structure of RG8 E's gas business. Because the negotiation of a comprehensive senlemenr is nor anticipated to conclude until mid-1999, the parties to the negotiations agreed to an Interim Senlement, effective November 199S through June 1999, that deals svith such issues as rates, transporration and storage capacity costs, assignment of capacity, and retail access. Under the Interim Settlement, ivhich was approved by the PSC on i november 9, 1998, base rates for gas service remain frozen at their current levels (ivhich ivere fixed pursuant to a 1995 Senlement that expired ar the end of October 1998).

Additionally, RG8'E must provide a guaranteed level of benefits to customers from the re-marketing of unneeded transportation and storage capacity, and RG8;E must permit marketers serving up to ten percent of retail and aggregated customer annual throughput to do so ivithout mandatory assignment of the cor'responding capacity. RG5cE is permitted to recover the costs associated with non-assigned capacity from all customers, with certain exceptions.

An Interim Gas Settlement having been reached and the PSC having issued its Gas Policy Statement, RGBcE a'nd other parties anticipate proceeding with discussions ivith PSC Staff based on the Company's August 1998 comprehensive proposal and the PSC's Gas Policy Statement. RGE'.E's objective is to ha've a comprehensive final settlement in place prior to July I, 1999, although no assurance can be given.

Under a %larch 1996 Order, the PSC permitted RG8'E and other gas distribution companies to assign ro marketers the pipeline and storage capacity held by RGRE to serve their customers. In its Gas Policy Sta'tement issued in November 1998, the PSC ordered that the mandatory assignment of capacity, permitted by the %larch 1996 Order, be terminated effective April 1. 1999. According to the Gas Policy Statement, however, the utilities are to be afforded a reasonable opportunity to recover resulting strandable costs, if any.

FLEXIBLE PRICIXG TARIFF.

Under its flexible pricing tariff tor major industrial and commercial electric customers, RG8;E may negotiate competitive elecrric rates at discount prices to compere ivith alternative popover sources.

such as customer-oivned generation facilities. Pursuant to the terms ot the Settlement under the Competitive Opportunities Proceeding. RGRE ivill absorb, as it has done since the inception of these rates. the difference between the discounted rates paid under these individual contracts and the rates thar vvould otherwise apply. Approximateli 29 percent of all electric sales to customers are made under long-term contracts. primarily to large industrial customers. These contracts represent approximately 45 percent of RGikE s feventies froln its collllllerclal and industrial customers.

Liqrridih~ arrd Capital Resorrrces Cash floiv from operations, external long-term debt financing, and short-term borroavings provided. the funds for construction expenditures, funding of unregulated operations, the Company's stock repurchase program, debr reductions, redemption of Preferred Stock and the payment of dividends during 1998. Capital requirements of the. Company during 1999 are anticipated to be satisfied from the combination of internally generated funds, short-term credit arrangements, and possibly some external long-term financing.

CAPITAL AND OTHER REQUIREMENTS.

The Company's capital requirements relate primarily to expenditures for energy delivery, including electric transmission and distribution facilities and gas mains and services as well as nuclear fuel, electric production, the repayment of existing debt, and the repurchase of outstanding shares of Common Stock. Construction expenditures in 1998 reflect primarily expenditures for nuclear fuel and upgrading electric transmission and distribution facilities and gas mains. The Company has no plans to install additional baseload generation.

1998 Labor Day Storm. At approximately midnight, IIonday morning, September 7, 1998, a severe lightning and windstorm struck the Company's franchise area. The storm damaged the Company's electrical system at several hundred different locations. Several counties within rhe Company's franchise area were declared State and federal disaster areas.

The Company estimates that initially as many as 100,000 customers lost power due to the storm.

On Saturday afternoon, September 12, the Company announced that all power had been restored, in all but a few isolated cases.

In 1998, the Company incurred $ 7.2 miHion of costs associated with this storm. Under the Competitive Opportunities Settlement with the PSC, if incremental costs resulting from a "catastrophic event" exceed S2.5 million, such costs could be deferred. The Company has submitted a petition to the PSC for deferral of costs associated with this storm.

Settlement with Co-generator, In May 1998 the Company entered into a Global Settlement Agreement regarding the termination of a power purchase contract ~vith Kamine/Besicorp Allegany L.P.

(Kamine). In August 1998 the PSC approved the Global Settlement Agreement, and on December 1, 1998, the Agreement became effective. The Global Senlement Agreement is discussed under Vote 10 of the Notes to Financial Statements. Under the terms of the Global Senlement Agreement,,the Poner Purchase Agreement divas terminated in consideration of payment by the Company of S168 million over the next 16 years, ~vithout interest, ivith an initial payment of S/0 million. Also, under the terms of the Global Settlement Agreement the Company paid an additional S15 million for the purchase of the Kamine generation facility. The plant may be operated if marker conditions ivarrant and the Company ivill assess the possible disposition of the planr. The'Company does not expect the te'rms of the Global Settlement Agreement to have any material effect on its earnings. Pursuant to a PSC order approving the terms of the Global Senlement Agreement, regulatory assets have been established by the Company to account for the initial payment, the facility purchase, and future payments. The Company has no other long-term obligations to purchase energy (rom other cogenerarion facilities.

Year 2000 Readiness Information. As the year 2000 (Y2K) approaches.-the Company, like most companies, faces potentially serious information and operational systems (computer and microprocessor-based devices) problems because many software applications and embedded systems programs created in the past ivill not properly recognize calendar dates beginning ivith the year 2000 or that the year 2000 is a -leap-year".

The Company identified the need to address Y2K issues earli and in June 1996 established the Y2K Project ( Y2K Project). Resources ('om across the enterprise have been committed to the Y2K Project. The Company has assigned approximately 40 ('ull-time equivalent people to ii ork on the Y2K Project as favell as retaining certain outside consultants to assist in the inventory. assessment. and certi('ication of date-aware devices. Th'e Company expects to tund its Y2K Project internalh and estimates it ivill incur between S IO to S12 million of incremental costs throu~Ji January I. 000. associated ivith making the necessary modifications identified ro dare ro applications (S I I million) and devices (S1 million). This

projection includes contingencies and replacement systems that may be required and represents Zi% of the Corporate Information Technology (IT) budget. The Company has not deferred any other major IT

.project due to this effort. The Company has incurred approximately S5.3, million of its 5 I 2 million total costs through December 31, 1998. The Company is also participating in the YZK activities of several organizations such as the Net York Popover Pool, North American Electric Reliability Council, Electric Popover Research Institute and others for the development of a network to verify the risks and costs nationally, in the Northeast, in New York State, and in the Company.

The YZK Project is divided into five primary phases. The first phase is the inventory phase during which applications (both internally developed and vendor developed) and devices (in the generation plants, delivery substations and facilities) are identified and criticality to the business is determined. During the next phase, the assessment phase, the Y2K Readiness of the items is determined. Year 2000 Readiness is defined as a computer system or application that has been determined to be suitable for continued use into the Year 2000 even though the computer system or application is not fully Y2K complianr. The third phase, fixing, is when replacement or remediation of the items is performed. The fourth phase is the testing phase, when the items are functionally verified and date tested. The final phase is the contingency phase when contingency plans iyill be developed for all critical applications, devices and systems.

To date, the Y2K Project has completed the inventory phase, ivhich divas the identification of internally developed applications, devices, vendor applications and critical external parties including customers, suppliers, business partners, government agencies, and financial institutions. The Company will prioritize these critical parties and independently evaluate the most critical of these by various methods, such written verification to the Company of their status or testing transfer of information. as'andatory The Y2K Project, in the assessment. phase, has completed assessment of internally developed applications and critical devices. The Company expects to complete the assessment of critical external parties and vendor applications by the end of the first quarter of 1999. Results of these assessments will be given to the Business Areas for further action.

The fix phase activities of the Y2K project for internally developed applications is 82% complete and for critical devices is 75% complete. The phase is expected to be complete by the end of the first half of 1999. As part of this phase, a recently implemented customer information and billing system is Y2K ready, and starting in April 1998 and continuing through the first half of 1999, the Company is replacing its PC ivorkstations and sofovare with YZK-ready equipment and sobvare. As facility maintenance outages occur this spring, Y2K critical device replacement/moditications will be performed. Critical devices are an integral part of the system ivhich controls, monitors, and assists in the operation of equipment, machinery, or planr.

Testing of internal applications for YZK readiness has begun and is Z8% complete. Testing of critical applications, devices, and systems ivill take place primarily in the first half of 1999 and is currently in the initial stages.

The Company has in place a Business Recovery Plan describing alternative processes and procedures to ensure the integrity of its energ) and financial systems. The Business Recovery Plan ivill serve as the basis for YZK contingency plans. Contingency planning commenced in October 1998 and is expected to be completed by June 1999. The Company ivill be able to identify'ts most reasonably lil'ely ivorst case YZK contingency scenario by the end of the first quarter of 1999 ivhen it completes the Scenario Risk An'alysis phase of contingency plannin<. Failure to address Y K issues properly could cause the Company to, among other things, issue inaccurate bills, report inaccurate data, or incur plant outages and/or energy deliver) problems.

All activities'in support of mission critical systems are expected to be completed by July 1999, as required by the PSC. Likewise, the Company fully expects to meet the July 1999 completion criteria set by tlie XRC for the Company's Ginna facility.

Energetix. the Corupan) 's ivholli oined subsidiary, includin< its recently acquired Griffith, estimates the cost ot nlaking the necessary moditicatinns identified to date to be less than 5100,000, 50.<<

of ivhich relate to devices and 50" o to applications. The cost represents approximately 50% of their IT bud< et. but no inajor IT proj>>cts have been deferred due to YZK. ~lost ot its systems, personal computers

<<nd operating equipment are less than seven years old. Energetix has identitied items thar are the most vulnerable to the YZK problem <<nd is in various sta<'es of assessing; tixing.ind testing those items. These items are expected to be YZK-read) by the third quarter ot 1999, ar which time a Scenario Risk Analsis ivill b>> coinpleted. Energetix has a Business Recovery Plan, xvhich ivill serve as the basis for YZK contin<<ency planning by the third quarter of 1999 also. Ener<etix has begun to survey critical third

parries including customers, suppliers, business partners and financial institutions to assess their degree of

'2K readiness and develop contingency plans to ensure the integrity of its operational and financial systems. Energetix will prioritize these critical parties and independently evaluate the mo'st critical of these by various methods, such as mandatory verification of their status or testing transfer of information.

ENVIRONiVIENTALISSUES.

The production and delivery of energy are necessarily accompanied by the release of by-products subject to environmental controls. The Company has taken a variety of measures (e.g., self-auditing, recycling and waste minimization, training of employees in hazardous waste management) to reduce the potential for adverse environmental effects from its energy operations.

The Company has recorded liabilities to reflect specific issues where remediation activities are currently deemed to be probable and ivhere the cost of remediation can be estimated. Estimates of the extent of the Company's degree of responsibility at a particular site and the method and ultimate cost of remediation require a number of assumptions for which the ultimate outcome may differ from current estimates. While the Company does not anticipate that any adjustment would be material to its financial statements, it is reasonably possible that the result of ongoing and/or future environmental studies or other factors could alter this expectation and require the recording of additional liabilities.

The extent or amount of such events, if any, cannot be estimated at this time.

Additional information concerning the Company's environmental matters can be found in Note 10 of the Notes to Financial Statements.

REDEMPTION OF SECURITIES.

In addition to first mortgage bond maturities and mandatory sinking fund obligations over the past three years, discretionary redemption of securities totaled S49 million in 1996, $ 152 million in 1997, and $ 25.5 million in 1998. Included in discretionary redemptions for 1997 and 1998 were over

$ 127 million of tax-exempt securities.

CAPITAL REQUIREMENTS

SUMMARY

Excluding the Kamine Global Settlement obligations discussed above, capital requirements for the Company over the three-year period 1996 to 1998 and the current estimate of capital requirements 2001 are summarized in the Capital Requirements table. 'hrough

'%M~ ~p8r%8~<4~ti~ w~ <so~rtg t)tl;4~~<Zt c" 0, >" g

=

" "- ': ~

>-" Actu'at'-'.',~'r;.";.",'v"res".NProTscted, re.~yg 1990 1997 =".'998 '<'j",s'199Rij+g000Cj2001.~~jul ur Type',of'FaetHtfes r".>t;.'.sl." .".'~,";~-~. '=- .., (MilSons of Dollars) i~i,>,",9>s,gjj>'i v)~i Eiectnc Property ~ .

'.;;-'Production,

".>.",",", Energy. Delivery

$ 57 23

$ 9 28

$ 16 41,

'35 " "34 '.$

'20,.$ 11

'<<i.i9'.'0 l;11- '-

~.~,".,', Subtotal 37 57 .," 55 "~."45;,'"~,30:-,',.-

".,:,'.;QItciear 16 19 14, 16,, '27,, ",';'9g,;..

Electric Fuel.'-*.;,";::'~"'Total 96 56 71,, " 71,,-';. 72,,~l3$

.,-'Gas Property - 17 22 21- . 18,,', '21 ~;::;19

'ommon'Property 6 9 21 24 ;;. 14 .:11

-,..; Total,." 119 87 113 113 ;107: .;,69 .

<.';;.CaffpIlg Costs;

'.!-.", 'AIIowance for Funds Used During Construction 2 1 1 1,'~,...1;.'.':".~ 1>>- '-.;

"..'=.'- Totaf Construction Requirements 121 88 114 114 "

..108

?0,'", .

'~~!Securtties,Redemptions, Maturities and Sinking

'-"'-, '."Fund 67 182 66' 1D'.'"",30.- ;4" "" -'",

Obligations';.-;,".:~

Total Capital Requirements $ 270 $ 180 , "$ 124,p..'*$ 138zÃil5'70, w

'1SS j,".'z'",Eidudcs, prospcctivc rc6naacin8s.

The Company's capital expenditures program is under continuous review and could be revised for any number of issues. The Company also may consider, as conditions ivarrant. rhe redemption or refinancing of certain outstanding long-term securities.

FINANCING.

On December 22, 1998 rhe Company issued S50 million of 5.84/a Firsr XIortgage Bonds, Designated Secured Wledium-Term Notes, Series B. The net proceeds from this financing were used to repay short-term debt.

In September 1998 the Company completed the delivery of S25.5 million of 5.95% Nen York State Energy Research and Development Authority (YYSERDA) tan-exempt bonds due September 1, 2033. Proceeds ~vere used to redeem S25.5 million of outstanding tan-exempt First WIortgage 8 3/8%

Bonds, Series OO, on December 1, 1998.

Included on the Company's consolidated Balance Sheet as of December'31, 1998 is a S24.6 million Promissory Note issued by Energetic in connection svith the acquisition of Griffith in August 1998, as discussed under Competition - Unregulated Subsidiaries. This Note is payable in seven annual insrallments of principal and interest. Also included ar year-end 1998 is a S94.8 million liability associated ivith the $ 168 million Promissory Note issued in connection with the Kamine Global Settlement Agreement (see Liquidity and Capital Resources

- Setrlement ivith Co-Generator). This amounr represents the present value ar December 31, 1998 of future obligations under the Note assuming a discount rate of 7.5 percent. This Note is secured by a subordinate mortgage on the Company's propert~; Addirional information about these Promissory Notes is discussed in Note 6 of the Notes to Financial Statements.

Under the Company's Performance Stock Option Plan, options for 403,605 shares of Common Stock became exercisable due to Common Stock market price performance during 1997. During 1998, additional options for 43,141 shares ivere granted, none of ~vhich became exercisable. Common Stock shares outstanding increased by 10,883 shares in 1997 and 23,466 shares in 1998 as a result of those options ivhich ivere actually exercised. These ivere the only shares of Common Stock issued by the Company during 199 and 1998.

~

In 1998 the Company began funding a stock repurchase program and investments in unregulated businesses as discussed under Competition.

Capital requirements during 1999 are anticipated to be satistied primarily from the combination of internally generated funds and the use of shon-term credit arrangements ivith some eyternal long-term financing possible during the year. The Company mai retinance tong-term securities obligations during 1999 depending on prevailing financial market conditions.

The Company anticipates utilizing its credir agreements and unsecured lines of credit to meet any interim external 1'inancing needs prior to issuing any long-term securities. For information xvith respect tn short-term borroivin<g arrangements and limitations. see ~ore 9 of the bootes to Financial Statements. As tinancial market conditions ivarrant, the Company ma1 also, from rime to time, redeem higher-cost senior securitic.'s.

Results of Operntions The following financial review identifies the causes of significant changes in the amounts of revenues and expenses, comparing 1998 to 1997 and 1997 to 1996. The Notes to Financial Statements contain additional information.

IIsICOiWIE STATEivIENT CHANGES.

Operating revenues have been reclassified into three components. Tivo of them, electric operating revenues and gas operating revenues, include all regulated and unregulated sales of electricity and gas, respectively. The third, other operating revenues, includes mainly sales from Griffith, as well as other energy products. Unregulated fuel expenses and unregulated operating and maintenance expenses excluding fuel reflect certain operating expenses of Energetix.

OPERATING REVENUES AND SALES SUibIiMARY.

Total Company operating revenues in 1998 were S1,034 million, or 0.2% beloiv 1997. Revenues in 1998 reflect unregulated operations as discussed below. For 1998, a decrease in electric base rates and lower therm sales of gas due to milder weather during the heating season were partially offset by higher ivholesale electric sales. In 1997, operating revenues ivere louver than 1996 ivith the effect of RGB'E's electric base rate decreases in July 1996 and 1997 and lower therm sales of gas due to milder weather partially offset by higher electric kilowatt-hour sales.

Unregulated Operating Revenues and Sales. Included in total operating revenues for 1998 are S10.6 million of electric and gas operating revenues received by Energetix and S71.2 million of Griffith operating revenues.

During 1998, Energetix derived 99% of its revenues (excluding Griffith revenues) from electric and gas sales. The balance of revenues was derived from ServiceCare, the appliance warranty service.

Electric sales do not reflect significant seasonal variances. Gas revenues, however, are subject to seasonal fluctuations due to the dependence on spaceheating sales during the heating season. While Energetix was formed January 1, 1998, its first revenues were not received until April of 1998. As a result, 1998 gas revenues reflect only a small amount of spaceheating sales.

During 1998 and since its acquisition by Energetix in August, Griffith derived 97% of its total revenues from distillates (heating oil, kerosene, and diesel), and gasoline sales. The balance of revenues divas mainly derived from propane, servicing and motor lubricant sales, Griffith separates the business into three general segments:

retail or residential, ivholesale ivhtch consists of large commercial ELECTRIC and reseller accounts, and dealers or service stations. For distillates SWLZS and propane sales, Griffith experiences seasonal fluctuations due ltl~otts ins6 of nin lrl to the dependence on spaceheating sales during the heating season.

In addition, gasoline sales reflecr seasonal fluctuations due to 1} increased consumer driving during the ivarmer months'.

,219 .672 Regulated Operating Revenues and Sales. The effect ot 995, I iveather variations on operating revenues is most measurable in the Gas Depanment. ivhere revenues from spaceheating customers comprise about 90 to 9i percent of total gas operating revenues. Compared to a year earlier. iveather in the Cornpan1 's service area divas 13.6 percent ivarmer during the first three months ot'1998 and 18.1 percent ivarmer for the entire year on a calendar month heating degree day basis. Likewise, iveather during I99, divas 1.2 percent ivarmer than 1996 on a calendar month heating degree day basis. The Company has no iveather normalization clause in its gas tariff: therefore, abnormal u cather variations ivill have a more pronounced effect on gas 1996 i99 i99S revenues. 5,'armer summer iveather during I 998 boosted electric energy sales to meet the demand for air conditioning usage,

compared to the cool 1997 summer <<cather conditions. On a cooling degree day basis, <<cather in 1998

<<'s 62 percent <<'rmer than 1997, <<'hile in contrast, the 1997 <<cather <<as approximately 27 percent cooler than 1996.

Compared << ith a year earlier, kilo<<'att-hour sales of energy to retail customers <<ere do<<n 3.6 percent in 1998, folio<< ing a 1.2 percent increase in 1997. Commercial and industrial sales <<ere do<<n in 1998 due, in part, to the opening of the electric market under terms of the Competitive Opportunities Settlement. Reported retail sales are depressed as former RGB'E customers choose an alternative energy supplier as permitted under the terms of the Competitive Opportunities Senlement.

RGB'E, however, also sells electric energy, as well as distribution services, to qualified energy marketers in its franchise territory, <<'hich has the effect of increasing electric <<holesale sales and revenues as discussed in'the folio<<ing paragraph. Partially offsetting the decline in electric sales in 1998 to retail customers was the increased demand for air conditioning usage caused by the <<armer summer <<'cather.

In contrast, cooler summer weather had a negative impact on kilo<<an-hour sales in 1997.

Under its Energy Choice Program, RGB:E on July I, 1998 began selling electricity and distribution services to qualified energy marketers to serve their retail customers as permitted by the terms of the Competitive Opportunities Settlement. Electric sales to energy marketers, including the Company's unregulated subsidiary Energetic, totaled 174,676 mega<<att-hours in 1998. Revenue from these energy marketers for electricity and distribution services totaled S li.0 million and is included in electric operating revenues.

Fluctuations in revenues from electric sales to other utilities are generally related to RGRE's customer energy requirements, the wholesale energy market, availability of transmission, and the .

availability of electric generation from RG8cE's facilities. Revenues from electric sales to other utilities were $ 29.0 million in 1998, an increase of $ 8.1 million over 1997. These revenues are included in electric operating revenues. The higher revenues in 1998 reflect a favorable wholesale market and increased marketing of available capacity. Revenues in 1997 from electric sales to other utilities also rose compared with a year earlier due ro increased sales resulting from greater availability of RGB'E's combined nuclear and fossil generation, a favorable wholesale market in the second half of the year,

. and increased maiketing of available capacity.

The transportation of gas for large-volume customers who are able to purchase natural gas from sources other than the Company is an important component of the Company's marketing miz. Company facilities are used to distribute this gas. <<hich amounted to I6.4 million dekatherms in 1998 and 16.6 million dekatherms in 1997. These purchases by eligible customers have caused decreases in the Company's retail gas customer revenues, << ith offsetting decreases in purchased gas expenses and, G>S SGXD a in general, do not adversely affect earnings because transportation TRAIISPORTKD customers are billed ar rates <<'hich. except for the cost of buying (niillions of rl>era>s) and transporting gas to the ComIiam's cirh gate, are the same as the rates charred the Company's retail <as servi<.'e customers. Xioreover,

.96 I 53S under the current regulatory environment. the Company does not

a. 3 earn a remrn on rhe gas eornmodin'r neqaires for disrrihnrion. Gas supplies transported in this manner are not included in Company therm sales. depressing reported gas sales to non-residential I ciistoillers.

Therms of gas sold and transported <<'ere do<<n 12.1 percent in 1998. after declinin< four percent in 199 . These changes reflect,

' re 1'rimarily. the effect of <<cather variations on therm sales to customers <<ith spaceheating. If adjusted for normal <<cather 3

s: conditions. residential gas sales <<'ould have decreased about 1.5 percent in 1998 over 199 . <<hile non-residential sales, including

<sas transported. <<ould have increase.i approximately t<<o percent in 1998. The average use per residential gas customer, <<'hen RK s... i996 i99 i998

\ eKS" 3'.a+ adjusted for normal <<'cather conditions, sho<<'ed a modest decrease in 1998 and 199 .

FOSSIL UNIT STATUS.

On January 21, 1998, the Company announced the retirement of Beebee Station by mid-1999.

Factors such as the plant's age, lack of a rail/coal delivery system and more stringent clean air regulations made the plant uneconomical in the developing competitive generation business. The retirement of Beebee Station is not expected to have a material effect on the Company's financial, position or results of operations. The plant ivill be fully depreciated at the time of retirement. The Competitive Opportunities Settlement provides thar all prudently incurred incremental costs associated ivith the retirement and decommissioning of the plant are recoverable through the Company's distribution access rates. The electric capacir) and energy currently provided by the plant are expected to be replaced in the energy markets as needed.

The Company and Niagara Mohawk Popover Corporation (Niagara Mohawk) have entered into an agreement dated June 8, 1998 (Sale Agreement) ivhereby the Company's 24% oxvnership interest in the Oswego Generating Facility Unit 6 (Oswego 6) non-nuclear generating facility was included in the bidding process for the sale of.'niagara!vlohaivk's non-nuclear generation pursuant to 'niagara .'vfohawk's electric restructuring agreement approved by the PSC. Niagara Mohawk owns the remaining 76% of Oswego 6.

The Sale Agreement provides for the allocation of proceeds and liabilities pertaining to the Oswego 6 facility in accordance ivith the oivnership interests of the Company and Niagara Wiohaivk.

For purposes of the Sale Agreement, the Company's 24% interest in the Oswego 6 facility has been deemed equivalent to a 12% interest in the entire Oswego Generation Facility, which consists of Oswego 6, another operational unit, Oswego 5, that is virtually identical to Oswego 6, and four older, non-operational units, Oswego 1-4. The Sale Agreement has been approved by the PSC. The bidding process continued into January 1999. The Company cannot predict whether Oswego 6 will be sold or at what price. Under the terms of the Competitive Opportunities Senlement, a gain for RGB:E on such sale would be shared between RG8"E and its customers. With regard to a loss on such sale, the Settlement acknowledges an intent that RG8cE will be permitted to recover such losses through distribution rates during the term of the Senlement. Future rate treatment is to be consistent with the principle that RGScE is to have a reasonable opportunity to recover such costs. The electric capacity and energy currently provided by the plant are expected to be replaced in the energy markets as needed.

The book value of the Company's interest in Oswego 6 at December 31, 1998 divas 553.8 million.

OPERATING EXPENSES SUM ~1ARY.

Changes in fuel expenses for both comparison periods reflect primarily the availability of Company generating facilities, variations in sales of energy, and iveather effects on gas purchased for resale during the heating season. For the 1998 comparison period, fuel expenses also reflect unregulated operations.

Non-fuel operating expense divas down in 1998 reflecting louver federal income taies and a drop in other operating expenses (see Operations Excluding Fuel Expenses'partially offset by recognition of unregulated non-fuel operating expense. For 1997, compared to a"year earlier, non-fuel operating expense divas,up due to higher depreciation expense, partially offset b) louver local and State taxes.

Unregulated Operating Expenses. Unregulated fuel expenses in 1998 as shoivn on the Income Statement reflect mainly the cost of purchased fuel for Griffith operations since its acquisition by Energetic. Unregulated non-fuel operating expenses reflect primarily payroll expenses, fleer expenses for Griffith, and general and administrative expenses.

Regulated Operating Expenses.

Energy Costs - Electric. Higher tuel expense for electric generation in both comparison periods reflects increased generation to support higher electric sales. For the 1998 comparison period, increased tuel expense also reflects relatively more generation from the Compan) 's costlier fossil-fueled units. A fuel cost <<djustment clause was eliminated et'fective July I, 1996. Company shareholders are;assuming the full benefits and detrhnents realized front actual electric fuel costs and generatlml mix compared ivith PSC-approved Iorecast amounts.

l<GikE nonually purchases electric popover to supplen)ent its oivn generation xvhen needed to meet load or reserve requirements. and ivhen such popover is available <<t a cost louver than the Company's production cost. Increased availability and efficiencies following the )996 installation of net steam

generators at the Ginna nuclear plant resulted in lotver kilon art-hour purchases of elect'ricity in 1997 which led to a decline in purchased electric popover expense. In 1998, purchased electric expense also

'ecreased, refleering greater availablity of the Company's generating facilities.

Energy Management and Costs - Gas. RG5;E acquires gas supply and transportation capacity based on its requirements to meet peak loads ivhich occur in the ivinter months. RGRE is committed to transportation capacity on the Empire State Pipeline (Empire) and the CXG Transmission Corporation (CNG) pipeline systems, as favell as to upstream pipeline transportation and storage services. The combined CNG and Empire transportation capacity is adequate to meet RGRE's current requirements.

For the 1998 and 1997 comparison periods, gas purchased for resale ezpense declined driven by a reduced volume of purchased gas resulting from a ivarmer heating season.

Operations Excluding Fuel Expenses. For the 1998 comparison period, operations less fuel ezpenses declined, reflecting decreased expense of S5.3 million associated ivith uncollectible accounts and a S7.9 million drop in welfare expenses due to the performance of pension assets (see Note 3 to the Notes to Financial Statements). Partially offsetting these louver costs ivere increased payroll costs of SZ.Z million.

For the 1997 comparison period, the increase in operations excluding fuel expenses reflects mainly higher outside services ezpenses (S6.1 million), recognition of obsolete and unproductive materials inventory (S3.0 million), and storm costs (S1.7 million) partially offset by S3.9 million ot louver payroll costs and decreased expense of 52.0 million associated with uncollectible accounts. The recognition of obsolete materials was driven by the planned relocation of the Company's ivarehouse. The decrease in the uncollectable accounts expense is driven by the increased level of collection activity in the last tivo i'ears.

For the 1997 comparison period, the increase in depreciation and amortization expense reflects prim'arily results from depreciation of the Ginna nuclear plant steam generators, which were'replaced in 1996 and recovery of increased nuclear decommissioning expense of approximately $ 3.> million per quarter beginning July I, 1996. The higher decommissioning expense reflects an increase in the estimated cost of decommissioning as recognized in rates for Ginna Station and Fine XIile Two.

Dep'reciation and amortization expense in 1998 includes S1.1 million for unregulated operations, but remained relatively flat compared to 1997 due to the completion of depreciation ezpen'se on certain fully depreciated computer equipmenr.

Taxes Charged To Operating Expenses. Local, State and other taxes declined in 1998 reflecting mainly lower State revenue taxes due to decreased revenues. This decline was partially offset by an additional S1.5 million of local and State razes associated ivith unregulated operations. The decrease in local and State taxes for 1997 reflects mainly lower property taxes due to decreases in assessments and/or rates and lower state revenue taxes due to decreases in revenues and the New York State revenue taz surcharge rate.

The decrease in federal income taz in 1998 reflects decreased earnings and in 1997 reflects mainly the reversal of a prior provision for the in-service date of Nine XIile Tivo as a result of an agreement reached ivith the Internal Revenue Service.

Other Statement of Income Items. For the 1998 consp<<rison period. the v<<ri<<tion in non-oper<<ting 1'e Jet<<i income taz reflects v<<riances in non-oper<<ting earnings before fe der<<l income t<<zes, <<s ~veil as <<

S I .. n>illion reserve for deferred t<<zes subsequent to <<review of the hisn>ric b<<lances.

The change in Other Income <<nd Deductions. Other-net in I )98 reflects the recognition of income Jue to the revers<<l of certain deferred credits in <<ccor J<<nce iv<th the C<>mpetitive Opportunities Settlement. In prior years, the PSC ha J required the Comp<<ny to establish deferred ere Jits to <<ccount for certain pensi<>n <<n J <>ther post.employn>enf benefit ch<<rges <<n J Nine Xlile T\vo oper<<ting and m<<lnten<<nce expenses. In 1998. these deferred credits totaling S I 2 million were eliminated consistent vvith the terms of the Setrl<'.ment <<n J discussions xvith the PSC. An <<mount of S8.8 million <<ss<)elated xvith certain pension charges iv<<s reflected on the Conlp<<ny's books in the first quarter ot 1998, after the Con>p<<n< r<'c<.'ived the writteh <>rder <<ss<>ciated uirh the C<m>petirive Opportunities Settlemenr. An

<<mount ot SG.O n>illion <<ssoci<<ted with certain Nine Xlile Tiv<> <>per<<ting <<nd maintenance expenses iv<<s reflected rar<<bly <>v<.'r e<<ch <>f the. fot>r qu<<rters of 1998. c<>nsistc.'nr ivith Kine Xlile Tivo accounting pf<<ctices. The rem<<in der <<ssoci<<ted ivith cert<<in other post.<'.lupi<>ynl<',lit benefits was reflected in the sec<>n J quarter of 1998, <<fter th>> Co<up<<ny h<<J c<>nclu JeJ discussions <vith the PSC. The Company does not have any deferred credits ivhich <<r>> subject to PSC Orders ivhich ivould permit the recogniti<>n of <<ny si< nit'ic;tnt credits t<> inc<>me in the t'utur<.'. This inconle vvas partially offset by

expenses associated ivith the gas'interim senlement agreement.

Other (Income) and Deductions, Other net changed in 1997 R~TA<><D due mainly to recognition of expense associated with P~g g j gGS 'anagement performance aivards and the Company's End of Periorl Performance Stock Option Plan.

tmillions of dollars) Both mandatory redemptions and the optional redemptions of 129 certain higher-cost long-term debt have helped to reduce long-term debt interest expense over the three-year period 1996-1998.

109 Other interest decreased in 1998 due to lower miscellaneous interest charges on pension and other post-employment benefits.

This decline was partially offser by an additional $ 1.0 million of interest expense associated with unregulated operations.

Compared to the prior year, the average RGB'E short-term debt outstanding was up in 1998 and nearly unchanged in 1997.

The mandatory redemption of the Company's 7.55% Preferred Stock, Series T, caused Preferred Stock dividends to decrease in 1998. Preferred Stock dividends also decreased in 1997 due to the Company's discretionary redemption in April 1997 of its 7.50% Preferred Stock, Series N and the mandatory sinking fund 1996 1997 1998 redemption of its 7.45% Preferred Stock, Series S in September.

Dividend Policy The level of future cash dividend payments on Common Stock will be dependent upon the Company's future earnings, its financial requirements, and other factors. The Company's Certificate of Incorporation provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company.

OFFicER APPoirtTmErtT Parrl C. Will;ens rvas pr'onroted to the position of senior vice-president of generatiorr. Most recentl>'e bad beerr director of gas services, arrd bas erctensive ev peri ence in electric generation arrd rvas once director of rnrclear erlgllleeflrlg sen'rces.

0 Fir1'anci<L REPoRTS Report of Independent Report of Management............50 Accountants 74 Interim Financial Data ~............50 Statement of Income 25 Common Stock and Statement of Retained Earnings ..25 Dividends 51 Balance Sheet 26 Selected Financial Data ............52 Statement of Cash Flows ..........28 Electric Department Statistics ....54 Notes to Financial Statements.... 29 Gas Department Statistics......... 55 REPORT OF I11DEPE11DEI1T ACCOU11TA11TS 1 100 Bausch 5: Lomb Place Rochester, Yeiv York 14604-7705 pVCSVA~ERHOUs+07PER5 II Jan ua ry 0, 7 '1 999 To the Shareholders and Board of Directors ot Rochester Gas and Electric Corporation In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, retained earnings and cash flows present fairly,'in all material respects, the financial position of Rochester Gas and Electric'Corporation and its subsidiaries at December 31. 1998 and 1997. and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepred accountin. principles. These 1'inancial statements are the responsibility of the Company's management; our responsibility is to express <<n opinion on these 1'inancial statements based on our audits. XI'e conducted our audits ot'hese statements in accordance with g<<neralli accepted auditing standards which require that we plan and pert'orm the audit to obtain reasonable assurance about rvhether the financial statements are free of material misstatement. An audit inclttdes examining, on a tesr basis. evidence supporting the amounts and disclosures in the ttnancial statements, assessing the accounting principles used and significarit estimates ntade hy management, and evaluating the overall tinancial statement presentation. 5,'e believe that our audits provide a reasonable basis for the opinion expressed above. ~

4 CanSOLiDf4 EO StatEmEnt OF 'HCO E (Thousands of Oolfars) Year Ended Oecember 31 1998 1997' 1996' Operating Revenues Electric 5 687,970 700,329 707,76S Gas 275,177 336,309 346)279

-Other 71,215 Total Operating Revenues ~

1,034,362 1,036,638 1,054,047 Operating Expenses Fuel Expenses Fuel for electric generation 53,954 ~

47,665 40,938 Purchased electricity 27,024 28,347 46,484 purchased for resale 196,579 202,297

'as 155,497 Unregulated fuel expenses 60,001 Total Fuel Expenses 296;476 272,591 289,719 Operating Revenues Less Fuel Expenses 737,886 764,047 764,328 Other Operating Expenses Operations and maintenance excluding fuel expenses 301)625 315,109 313,157 Unregulated operating and maintenance expenses excluding fuel 13,257 Depreciation and amortization 116,122 116,522 105,614 Taxes local, state and other 118,337 121,796 126,868 Federal income tax 61,385 65,279 69,501 Total Other Operating Expenses 610,726 618,706 615,140 Operating Inconre 127,160 145;341 149,188 Other (Income) and Deductions Allowance for other funds used during construction {408) (351) {684)

Federal income tax 516 (3,704) (3,450)

Other, net (13,181) 3,308 (712)

Total Other (Income) and Deductions (13,073) (747) (4,846)

Interest Charges Long'term debt 42,590 44,615 '8)618 Other, net 4,158 6,676 9)328 Allowance for borrowed funds used during construction (653) (563) (1,423)

Total Interest Charges 46,095 50,728 56,523

¹t Income 94,138 95,360 97,511

'Dividends on Preferred Stock 4,842 5,S05 7,465 Earnings Applicable to Common Stock 5 89,296 5 89,555 5, 90,046 Earnings per Common Sbare Basic 5 232 5 230 5 232 Earnings per Common Sbare Diluted 5 2.31 5 230 5 2.32 CortsoLios)tED S1n1 ErnErt1 oF RE t Al!TED EaRninGS (Thousands of Dollars) Year Ended December 31 1998 1997 1996' Balance at Begirrrring of Period 5109,313 5 90,540 70,330 Add

'Aet Income 94,138 95,360 97,511 Adjustment Associated ivith Stock Options Exercised {72)

Adjustment Associated ivith Stock Reden>ptions (126) lS46)

Total 203.253 185.054 l67,841 Deduct Dividends declared on capital stock Cumulative prof)8rred stock at required rates 4,842 5.S05 7,465

, Con1I11OI1 stock 68,927 69,936 69,836 Tot ll , 3,769 5. 4l , 4,30 I Bsll)1>lee at End of Period 51~9 484 5109,313 5 90.540 Casb Divi<lends Declared per Connnon Sitare 5 1.80 5 180 5 1.80 The s;e))mran)mg nnte. are an )nre.ref prt 4)t rhe nn2ne)zl )utentent).

"Reel>5)itic J t'4)r;i)mraratr)e rnrr4)5e5,

CortsoliD52teo BALAIICE SHEE't (Thousands of Dollars) At December 31 . 1998 Assets UtilityPlant 1997'2,439,108 Electric 52,477,077 Gas 435,318 416,989 Common 158,038 134,938 Nuclear fuel 256,562 243,042 3,326,995 3,234,077 Less: Accumulated depreciation 1,640,645 1,510,074 Nuclear fuel amortization 222,830 204,294 1,463,520 1,519,709 Construction work in progress 98,554 74,018 Net Utility Plant 1,562,074 1,593,727 Current Assets Cash and cash equivalents 6,523 25,405 Accounts receivable, net of allowance for doubtful accounts:

1998 $ 26,554; 1997 S26,926 89,291 104)781

'nbilled revenue receivable 37,922 48,438 Materials, supplies and fuels 43,024 39,929 Prepayments 25,950 23,818 Other current assets 253, Total Current Assets 202,963 242,371 Intangible Assets Goodwill "14,681 Other intangible assets 6,381 Total Intangible Assets 21,062 Defened Debits and Other Assets Nuclear generating plant decommissioning fund 183,502 132,540 Nine Mile Two deferred costs 29,258 30,309 Unamortized debt expense '7,241 16,943

'ther deferred debits ) 18,531 20,411 Regulatory assets. 416,320 231,988 Other assets 1,984 Total Deferred Debits and Other Assets 666,836 432,191 Total Assets 52,452,935 52.'-68.289

(ThuuSandS Of OOllarS) At December 31 1998 and t.iabllitles 1997':apltallzation Capitalization Long term debt mortgage bonds S 510,002 S 485,434 promissory notes 248,224 101,900 Preferred stock redeemable at'option of Company 47,000 479(f00 Preferred stock subject to mandatory redemption 25,000 35,000 Common shareholders'quity:

Common stock ($ 5 par, 37,378,813 shares at December 31, 1998 and 38,862,347 shares at December 31, 1997) 699,730 699,031 Retained earnings 129,484 109,313 829,214 808,344 Less: Treasury stock at cost (1,507,000 shares) 46,433 Total Common Shareholders'quity 782,781 808,344 Total Capitalization 1,613,007 1,477,678 Long Term Liabilities Nuclear waste disposal 87,566 83,261 Uranium enrichment decommissioning 12,197 13,465 Site remediation 26,157 13,626 Total Long Term Liabilities 123,920 110,352 Current Liabilities Long term debt due within one year 427 30,000 Preferred stock redeemable within one year 10,000 10,000 Short term debt 57,000 20,000 Accounts payable 52,454 53,195 Dividends payable 17,937 18,791 Equal payment plan 11,025 8,935 Other 34,526 34,770 Total Current Liabilities 183,369 175,691 Deferred Credits and Other Liabilities Accumulated deferred income taxes 326,972 344,969 Pension costs accrued 58,677 67,361 Kamine deferred costs 65,799.

Post employment benefits internal reserve 42,909 32,190 Other 38,282 60,048 Total Deferred Credits and Other Liabilities 532,639 504,568 Commitments and Other Matters Total Capitalization and Liabilities 52.652,935 52.268.289

'Reefasstne6f tor eomparathe purposes.

The a,;ompannng notes are an tntepraf parr ot the tinannaf Statements,

0 Cor(soLiontED S15)tElnEr)1 or CASH FLOWS.

(Thousands of Dollars) Year Ended December 31 ~

1998 1997 1996'ash Flow from Operations Net income S 94,138 S 95,360 S 97,511 Adjustments to reconcile'net income to net cash provided from operating activities:

Depreciation and amortization 134,259 133,942 121,824 Deferred fuel (3,565) 489 (6,501)

Deferred income taxes (9,141) (10,064) 6,391 Allowance for funds used during construction (1,061) (914) (2,107)

Unbilled revenue, net 10,516 4,823 10,908 Stock option plan, net 99 2,399 Nuclear generating plant decommissioning fund (20,827) (20,331) (11,732)

Payment to Kamine (17,790)

'ension costs accrued (15,818) . (3,398) 494)

Post employment benefit internal reserve 10,719 6,189 6,626 Provision for doubtful accounts (372) 5,078 4,987 Changes in certain current assets and liabilities:

Accounts receivable 27,549 3,049 3,228 Materials, supplies and fuels 141 (41) (1,238)

Taxes accrued (1,448) 347 (13,944)

Payroll accrued 54 433 17 Accounts payable (7N1) 3,733 (3,116)

Other'current assets and liabilities, net (817) 6,911 (5,203)

Other, net (4,699) 6,847 (3,931)

Total Operating 194,906 234,852 201,226 Floe from Investing Activities

'etCash additions to utility plant

'Acquisition, net of cash (129,286) (84,068) (114,274)

(30,977)

Other, net 484 (1) 9,204 Total Investing (159,779) (84,069) (105,070)

Cash Flow from Financing Activities Proceeds from:

Sale/Issuance of common stock 586 272 8,612 Issuance of long term debt 99,422 101,900 Short term borrowings, net 30,500 6 6,()00 14,000 Retirement of long term debt (55,500) (151,568) (67,332)

Retirement of preferred stock (10,000) (30,000)'6,366)

Dividends paid on preferred stock (5,031) (7,465)

Dividends paid on common stock (69,592) (69,933) (69,657)

Paynlent for treasury stock (46,433)

Equal payment plan 2,090 3,385 4,273 Other, net (51) 1369l (1,407)

Total Financing (54,009) (146.679) (118,976)

Increase (Decrease) in cash and cash equivalents S (IS.882) S 4.104 S (22,S20)

Cash and cash equivalents at beginning of year S 25,405 S 21,301 S 44:121 Cash and cash equivalents at end ot year S 6,523 5 25,405 S 21.301 4

SvppLsrnEntr)L DiscLosv< or CASH FLOW If1FORIl1AtIOfi (Thousands of Dollars) , Year Ended December 31 1998 1997 1996 Cash Paid Drtrlng the Year Interest paid (lret of capitali:ed Srnrount) laconic ttlxes pard "14ef ts>>t)eJ inr e()myrio(re rurr()4e.,

The.)'e()mr)ny)n(. notes ere an )ntear tl part ui the 6nln;:lf surement>.

H

11OTES 0to FinanciaL Statements Suntmary ofAccounting Principles OTE GENERAL.

The Company supplies regulated electric and gas services wholly within the State of New York.

The unregulated portion of the Company provides products and services as discussed in Note 4.

The Company is subject to regulation by the Public Service Commission of the State of New York (PSC) under New York statutes and by th'e Federal Energy Regulatory Commission (FERC) as a licensee and public utility under the Federal Power Act. The Company's accounting policies.

conform to generally accepted accounting principles as applied to New York State public utilities giving effect to the ratemaking and accounting practices and policies of the PSC.

The preparation df financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the, financial statements and the reported amounts of reve'nues and expenses during the reporting period. Actual results could differ from those estimates.

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

PRINCIPLES OF CONSOLIDATION.

k The consolidated financial. statements include the accounts of the Company and its wholly-owned subsidiaries Energetix and Energyline. All intercompany balances and transactions have been eliminated. Energetix financial statements are'consolicfated with its wholly-owned subsidiary Griffith.

Energyline was formed as a gas pipeline corporation to fund the Company's investment in the Empire State Pipeline project. In late 1996, Energyline sold its investment in the Empire State Pipeline.

During the second quarter of 1998, the Company formed a new unregulated subsidiary, RGS Development Corporation ("RGS Development" ). RGS Development was formed to pursue unregulated business opportunities in the energy marketplace. Through December 31, 1998, RGS DeveIopment operations have not been material to the Company's results of operation or its finan-cial condition.

SU>>iiMARY OF SIG>NIFICANT ACCOUNTING POLICIES.

GooDwILL AYD OTHER INTANGIIILEAssETs ~

Goodwill presented on the consolidated balance sheet, represents the excess of cost over the net tangible and identifiable intangible assets of acquired businesses. It is stated at cost and is amortized, principally on a straigln-line basis, over the estimated future periods to be benefited (20 years). On an annual basis the Company reviews the recoverability of goodwill based primarily upon an analysis of undiscounted cash flows from the acquired businesses. Other intangible assets include dealer improvements and are being amortized over varying periods. Accumulated amortization amounted to $ 0.7 million at December 31, 1998.

ACQUISITIONS In August 1998, Fnergetix announced the acquisition of Griffith'Oil,'Co., Inc. ('riffith" ), for S3 l.i million. Griffith sells oil. propane. electricity. gasoline, natural gas and other services offered by Energetix to its existing customers. The acquisition was accounted for as a purchase resulting in oodwill as reflected on the consolidated finaiicial statements. The principal assets acquired ivere vehicles. tanks, pumps, buildings and commodity inventory.

X'i>/r I r>>>>r>>>>rr>I >>>> p.>rr 3>h

(contmutd from ,RATEs AND REYENUE.

IPdgc 9I

'Revenue is recorded on the basis of meters read. In addition, the Company records an estimate of unbilled revenue for service rendered subsequent to the meter-read date through the end of the accounting period.

Through June 30, 1996, tariffs for electric service included fuel cost adjustment clauses which adjusted the rates monthly to reflect changes in the actual average cost of fuels. Beginning July 1, 1996, the electric fuel adjustment clause was eliminated'n connection with a rate settlement agreement with the PSC.

The Company continues to use gas cost deferral accounting. A reconciliation of recoverable gas costs with gas revenues is done annually as of August 31, and the excess or deficiency is refunded to or recovered from the customers during a subsequent period.

UTILITYPLANT, DEPRECIATION AVD AMORTIZATION.

The cost of additions to utility plant and replacement of retirement units of property is capital-s ized. Cost includes labor, material, and similar items, as well as indirect charges such as engineering and supervision, and is recorded at original cost. The Company capitalizes an Allowance for Funds Used During Construction (AFUDC) approximately equivalent to the cost of capital devoted to plant under construction that is not included in its rate base. AFUDC is segregated into two components and classified in the Consolidated Statemerit of Income as Allowance for Borrowed Funds Used During Construction, an offset to Interest Charges, and Allowance for Other Funds Used During Construction, a part of Other Income. The rate approved by the PSC for purposes of computing AFUDC was 5.0% during the three-year period ended December 31, 1998. Replacement of minor items of property is included in maintenance expenses. Costs of depreciable units of plant retired are eliminated from utility plant accounts, and such costs, plus removal expenses, less salvage, are charged to the accumulated depreciation reserve.

'epreciation in the financial statements is provided on a straight-line basis at rates based on the estimated useful lives of property, which have resulted in an annual regulated depreciation provision of 3.2% in the three-year period ended December 31, 1998. The annual depreciation provision of

'nergetix is 8.0% for 1998.

CASH AND CASH EQL'IVALENTS.

Cash and cash equivalents consist of cash and short-term commercial paper. These investments have.original maturity riot evceeding three months. Such investments are stated at cost, ivhich approximates fair value, and are considered cash equivalents for Financial statement purposes.

INYEsTIIENTs IN DEBT AND EQUITY SEcUIKITIEs.

The Company's accounting policy, as prescribed by the PSC, ivith respect to its nuclear decommissioning trusts is to reflect the trusts'ssets at market value and reflect unrealized gains and losses as a change in the corresponding accrued decommissioning liability. The Company has no other debt or equity securities.

FINANCIAI./COiDIODITYINSTRL'AIFNTS.

The Company periodically enters into agreements to minimize price risks for natural gas in storage. Gains or losses resulting from these agreements are deferred until the corresponding gas is ivithdraivn from storage and delivered to customers. The Company primarily enters into forward kA 4>tet contracts for natural gas through its gas broker.

toi and t Lwto; l al(f\Whth>A

Griffith is in the business of purchasing various petroleum-related commodities for resale.to its customers. In order to manage the risk associated with market price fluctuations Griffith enters into various exchange-traded futures and option contracts and over-the-counter contra'cts with third parties. The commodity instruments are designated at the inception as a hedge where there is a dir'ect relationship to the price risk associated with the company's inventory or future purchases and sales of .

commodities used iri the company's operation. These contracts are closely monitored on a daily basis to manage the price risk associated with the company's inventory and future product commitments.

All hedge contracts are accounted for under the deferral method with.gains and losses from the hedging activity included in the cost of sales. as inventories are sold or as the hedge transaction occurs. Commodity instruments not designated as effective hedges are marked to market at the end ~

of the reporting period, with the resulting gains or losses recognized in cost of sales. As of December 31, 1998 the Company had net deferred gains on open hedge contracts of $ 0.7 million.

REsEARcH AND DEVELoPMENT CosTs.

Research and Development costs were charged to expense as incurred. Expenditures for the years 1998, 1997, and 1996 were $ 3.4 million,$4.5 million and $ 4.9 million respectively.

, EN'VIRONMENTALREMEDIATION COSTS.

The Company accrues for losses associated with environmental remediatiori obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completipn of the remedial feasibility study.

Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value.

MATERIALS, SUPPLIES AND FUELS.

Materials and supplies inventories are valued at the lower of cost or market using the first-in, first-out method. Regulated fuel inventories are valued at average cost. Griffith fuel inventories are valued at the lower of cost or market.

STOCK-BASED COMPENSATION.

Financial Accounting Standards Board Statement No..123 (SFAS-123), Accounting for Stock-Based Compensation, was adopted by the Company in the first quarter of 1996. It recommends the use of a fair value based method of accounting for compensation costs associated with stock-based compensation. The Company currently has Stock Appreciation Rights plans covering certain.

employees and directors. For these plans, the Company's accounting policy has been to use a fair value method of computing periodic compensation expense. SFAS-123 was applied to the valuation of the 1996.Performance Stock Option Plan (PSOP), which became effective on January 22, 1997.

The aggregate amount charged to expense as a result of these plans for the years 1998, 1997 and 1996 approximates $ 5.9 million, S8.2 million and $ 1.0 million respectively. Additional information on the PSOP is included in 7'ote 8.

EARNINCS PER SH~RE.

SFAS-128, Earnings Per Share, was adopted by the Company in the fourth quarter of 1997. This statement replaces the presentation of primary Earnings Per Share ivith Basic Earnings Per Share,

.and also requires presentation of Diluted Earnings Per Share. Basic Earnings Per Share (EPS) is computed by dividing income available to common shareholders by the weighted average number Xiii I er>nlvnic<I on pagg 32(

of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the Company.

The following table illustrates the calculation of both Basic and Diluted EPS for the year ended December 31,:

(thousands of dollars except per share amounts) 1998 1997 Basic EPS:

Net Income S94,138 $ 95,360 Less:

Preferred Stock Dividends (4,842) '5,805)

Income available to Common Shareholders $ 89,296 $ 89,555 Shares 38,462 38,853 Per-Share Amount $ 2.32 $ 2.30 Diluted EPS: ~

'Effect of Dilutive'Securities Stock Option Plan 138 56 Income available to Common Shareholders plus assumed conversions $ 89,296 $ 89,555 Shares 38,600 . 38,909 Per-Share Amount S2.31 $ 2.30 There were no dilutive shares in 1996.

COMPREF(ENSIVE INCOME.

There were no items of comprehensive income during the year ended December 31, 1998; therefore, net income is equivalent to total comprehensive income.

NEW ACCOUNTING PRONOUNCEMENTS.

Financial Accounting Standards Board Statement No. 131 (SFAS-131 j, Disclosures about Segments of an Enterprise and Related Information, was adopted by the Company in 1998. SFAS-131 supersedes SFAS-14, Financial Reporting for Segments of a Business Enterprise. The adoption of SFAS-131 did not affect the Company's operating results. Note 4 contains specifi information and disclosures related to the Company's Regulated Electric, Regulated Gas and Unregulated segments.

REcLAssIFIcATIQNS.

Certain amounts in the prior years'inancial statements were reclassified to conform iiith current year presentation.

K whar.

I II,J 'IV

u

<< Federal Income Tnxes

<<DOTE>>

The provision for federal income taxes is distributed between operating expense and other income based upon the treatment of the various components of the provision in the rate-making process. The following is a summary of income tax experise for the three most recent years.

i (Thousands ol Dollars) 1998 1997 1996 Charged (Credited).to operating expense:

Current 570,541 S69,812 . S65,757 Deferred (9,156) (4,533) 3,744 Total 61,385 65,279 69,501 Charged (Credited) to other income:

Current (1,614) 1,828 (6,097)

Deferred 4,562 (3,100) 5,079 Deferred investment tax credit (2,432) (2,432) . (2,432)

Total 516 (3,704) (3,450)

Total Federal income tax expense S61,901 S619575 566,051 The following is a reconci)iation of the difference between the amount of federal income tax expense reported in the Consolidated Statement of Income and the amount computed at the statu-tory tax rate of 35%.

(Thousands of Dollars) 1998 1997 1996

~

Net Income S 94,138 S 95,360 S 97,511 Add Federal income tax expense 61,901 61,575 '66,051 Inconae before Federal income tax S156,039 S156,935 S 163,562 Computed tax.expense at statutory tax rate S 54,614 S 54,927, S 57,247 Increases (decreases) in tax resulting from:

Difference between tax depreciation and amount deferred 9,366 10,772 10,796 Deferred in'vestment tax credit (2,432) (2,432) (2 432)

Miscellaneous items, net 353 (1,692) 440 Total Federal income tax expense 5 61,901 5 61.575 S 66.051 A summary of the components of the net deferred tax liability is as follows:

(Thousands ot Donars) 1998 1997 1996 Nuclear decommissioning S(24.849) St50,60 r S(1-8801 Accelerated depreciation 214.521 2I6, 04 13,907 Deferred investment tax credit 25.768 2..98l 29,562

'\

Depreciation previously flowed through 146,953 8i '69,562 Pension (20,161) 523, l665 124.5 0)

Other 111.7601 r l3,28l) (5531 Tot<<l S 326,9 "2 5 i<<.969 SS l)IPS SFAS-l09 -Accounting for Inconie Taxes- requires that a deferred tax liability must he fecog-nl7ed on the Rill<<)lee sheet tor tax ditterences previously Iloived through to customers. Substantially all ot these Iioiv-through adjustments rel;lte to property, plant and equipmenr and related invest-nlellt tilx credits <<lid 1'vill be <<mortized consistent ivith the depreciation ot these accounts. The net

<<mount ot the additional liability <<t December 3 I, 1998 and )997 divas 5,43 million and S 160 million. respectively. In conjunction ivith the reco<'nition of this liability, a corresponding regulatory ilsset lv<<s ilIso recogrll7ed.

Pension and Other Postretiretnent Benefit Plans

."I1 oTE".

The following table shows reconciliations of the domestic pension plan and other postretirement plan benefits as of December 31, 1998 and 1997:

~< << (Millions)

KKKKKX~

J< W Pension Benefits Other Benefits 1998 1997 1998 1997 Cbange in benefit obligation Benefit obligation at beginning of year 5 499.3 5 480.2 5 89.0 5 79.1 Service cost 7.0 6.') 1.1 0.9 Interest cost 32.9 33.1 6.0 5.8 Plan Amendments 0.0 0.0 4.3 0.0 Actuarial loss 10.6 13.1 2.7 7.2

~

Benefits paid (33.0) {33.3) (4.1) ~

{4.0)

Benefit obligation at end of year 5 516.8 5 499.3 5 99.0 5 89.0 Cbange in plan assets Fair value of plan assets at beginning of year 5 638.4 5 56..1 5 0.0 5 0.0 Actual return on plan assets 100.0 104.0 0.0 0.0 Company contribution 0.9 0.5 4.1 4.0 Benefits paid . (32.9) (33.2) (4.1) (4 0)

Fair value of plan assets at end of year 5 7064 5 638.4 5 0.0 5 0.0 Funded status 5 189.5 5 139.1 5 (99.0) 5 (89.0)

Unrecognized actuarial loss (259 4) (2))9.0) I 1.2 S.4 Unrecognized prior service cost 9.9 10.7 12.6 8.9 Unrecognized net.transition obligation (asset) 1.3 I.S 32.3 39.5 Accrued benefit cosr 5 (58.7) 5 (67.4) 5 (42.9) 5 (32.2) 0'eigbted-average assumptions as of December 31 Discount rate . 6 50'/ 6.75% 6.50% 6 7o'/

Expected return on plan assets 8.50% 8.50%

Rate of compensation increase o.00% 5 00%

(Millions)

Pension Benefits Other Benefits 1998 1997 1996 1998 1997 1996 Con>ponents of net periodic benefit cost Service cost 5 .0 5 6.2 5 5 I.l 5 {).9 5 I tt interest cost 32.9 33.1 33.4 6.0 3.8 3.4 Expected return on plan assets (44.S) <39.6> 2l 0.0 o.n t).0 Unrecognized transition obligation 0.5 0,5 0.5 1 8

Amortization of prior service 09 t).9 0.9 0.6 <).6 {).5 Recognized ncttltlf>ill l{)ss {4.3) -3.1< <e.n. 0.0 t).0 t).9 Net periodic benefit cost 5 t<.8) 5 <'.t)< 5 <1.0 S10.5 S 5 lt).2 5 l0.6 In addition to providing pension benetits, rhe Company provides cerrain health care and life insurance benehts on a delined dollar basis. In 1998, the health care benehr consists of a conrribu-tion ot up to S) 10 per retiree per month n)ivards the cost of a group health policy provided by rhe Company. The lite insurance benetir consists of a Basic Group Life benefit, coverin<subsranrially all employees, providing;1 death benefit equal to one-hali ot the retiree's hnal pay. Effective Jatluary 1999. the Co{lip;tny 'ltllended the health cafe 1)ltltl itlcreasitlg the cotltribution to up SZZO per retiree per tllotlth.

ln <<ddition n) the;lhove plans. etttpioyees.lr<.'liihle n) conrribure to a 401{k) plan. The Cotllp(ttly Illtlrches ll porrtotl of these ct)ntrihutit)ns. Conrributions charged to income tor this plan for 1998, 199 . and 19)6 lvere S .1 tuillion. S1.3 million, and S .3 million. respectively.

r

Operating Segment Financial Information I1 oTE Under SFAS-131, information pertaining to operating segments is required to be reported. The prior'years'egment results were not restated as the Company'reviously reported Electric and Gas segments and the unregulated segment was formed in 1998. Generally, operating segments are com-ponents of an enterprise that engage in busine'ss activities from which revenues may be earned and for which expenses are incurred, whose results are reviewed for purposes of resource allocation and performance evaluation, and for which discrete financial information is available. Upon adoption of SFAS-131, the Company identified three operating segments, driven by the types of products and services offered and regulatory environment under which the Company primarily operates. The three segments are Regulated Electric, Regulated Gas, and Unregulated. The Regulated segments'inancial records are maintained in accordance witjt generally accepted accounting principles (GAAP) and Public Service Commission (PSC) accounting policies. The Unregulated segment's financial records are maintained in accordance with GAAP.

During the reported periods, all revenues are from United States sources except for $ 1.2 million from Canada, and all assets are located in the United States. No single customer represents more than 10% of the overall Company revenue.

The Regulated Electric segment supplies electric distribution services wholly within New York State. It produces electricity, and distributes and sells electricity to retail customers within a fran-.

chise area centering about the City of Rochester. It also sells electricity on a wholesale basis to other electric utilities throughout the Northeast and to energy marketers who resell that electricity to retailA;ustomers.

The Regulated Gas segment supplies gas services wholly within New York State. Gas is pur-chased and distributed to retail customers and distributed on behalf of other large or aggregated customers who purchase their own gas supply.

The Unregulated segment includes Energetix and RGS Development Corporation, both unregu-lated subsidiaries of the Company formed in 1998. In August, 1998, Energetix acquired Griffith Oil Inc., the second largest propane and oil distribution company in New York State. Energetix brings energy products and services to the marketplace both within and outside of the Company's regu- '

lated franchise area. These energy products and services include appliance warranty and repair, elec-tricity, gasoline, natural gas, oil, and propane. RGS Development Corporation was formed to pursue unregulated business opportunities in the energy marketplace.

(Thousands ot Ootlars) 1998 1997 1996 RFGULATFD ELFCTRIC Profit 5 93,762 5 81 -65 5 83,52S Revenues from External Customers 5 687,100 5 00.329 5 07!6S Revenues from Intersegment Transactions. 5 8,984 Interest Revenue 5 1,694 5 3.379 5 1.455 Depreciation and Amortization 5 101,113 5 103,395 92,615 Regulatory Amortization S 15,0SO 5 23,409 ,5 23,743 Nuclear Fuel Amortization 5 18,138 S 1"',419 5 16,109 Interest Expense, 5 36,122 5 40,583 S 45,218 Income Tax Expense 5 62,900 5 58,682 5 58,950 Capital Expenditures, Net 5 96 106 8,522 5 95,334 Total Identifiable Assets S 1.941.622 SI.,83.82$ S 1,877,224

~ Vole'4 <ontrnIIrJ rin pIIrc 1181

'(Thousands of Dollars) 1998 1997 1996 REGULATED GAS Profit . S 3,610 S 12,595 S 13,983 Revenues from External Customers S 274,540 S 336,309 S 346,279 Revenues from Intersegment Transactions S 72 Interest Revenue S 424 S . 845 S 364 Depreciation and Amortization S 12,867 S 13,127 S 12,999 Regulatory Amortization S 1,461 $ 1,337 S 1,677 Interest Expense S 9,030 S 10,145 S .11,305 Income Tax Expense S 504 S 2,893 S 7,101 Capital Expenditures, Net S 28,075 S 25,546 S 18,940 Total Identifiable Assets 5 433,039 5 441,349 5 447,865 (Thousands of Dollars) 1998 1997 1996 UNREGULATED (Loss) S (3>234) $

Revenues from External Customers S 81,778 $

Interest Revenue S 158 $ 4 Depreciation and Amortization 854 $

Goodwill Amortization 'S

'78 S Interest Expense S 943 $

Income Tax Benefit S (1,503) $

Capital Expenditures, Net S 5,005 $

Total Assets 5 59,946 5 There are intersegment transactions which occur between the Regulated segments and the Unregulat'ed segment.'These transactions are governed by guidelines established in the Competitive Opportunities Settlement and other PSC proceedings. The Unregulated segment is charged for the provision of services and for an allocation of other corporate costs by the Regulated Segments on a fully loaded est basis. The Unregulated segment buys electricity from the Regulated Electric segment at rates established through PSC proceedings. The Unregulated segment also pays the Regulated segments for electric and gas distribution services at rates established through PSC proce'edings. The total'amount of the revenues identified by operating segment do not equal the total Company consolidated amounts as shoivn in the Consolidated Statement of Income. This is due to the elimination of certain intersegment revenues during consolidation. The total assets identified by operating segment do not equal the total Company consolidated amounts as shown in the'Consolidated Balance Sheet. This is due to the elimination of certain intersegment transactions during consolidation, and certain common assets being unidentifiable by segment.

A reconciliation follows:

(Thousands of Dollars) 1998 1997 1996 REvE~vEs Regulated Electric 5 687,100 $ 700)329 $ 707,768 Regulated Gas 274,540 336,309 346,279 Unregulated 81,778 Total 1,043,418 1,036,638 l,054,047 Reported on Consolidated Income Statement 1,034,362 1,036,638 1,054,047 Difference to Reconcile 5 9,056 5 INTERSEGMENT REVENUES Regulated Electric from Unregulated 5 8,984 5 5 Regulated Gas from Unregulated 72 '9 Total Intersegment 5 9,056 (Thousands of Dollars) 1998 1997 1996 ASSETS Regulated Electric 5 1,941,622 51,783,825 $ 1,877,224 Regulated Gas ' 433,029 441,II49 ~, 447,865 Unregulated 59,946 Cash and Cash Equivalents, Regulated Operations 5,375 25,405 21,301 Unamortized Debt Expense 17,241 16,944 14,820 Investment in Subsidiaries 11,202 266 266 266 Other'ntersegment Eliminations (15,746)

Total Assets 5 2,452,935 5 2,268,289 52,36),476 Jointly-Owned Facilities The following table sets forth the jointly-owned electric generating facilities in which the Company is participating. Both Oswego Unit No. 6 and Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are operated by Niagara Mohawk Power Corporation. Each participant must provide its own financing for any additions to the facilities. The Company's share of direct expenses associated with these two units is included in the appropriate operating evpenses in ihe Consolidated Statement of Income. Various modifications will be made throughout the lives of thest; 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 c'apability (summer) 78S RGRE's share megaivans 189 1.128 percent 158 14 Year of completion 1980 1988 Plant ln Service Balance Accumulated Provision For Depreciation Plant Under Construction 599.6 543.6

'881.8 Millions of Dollars at December 31. 1998 5490.9 5 0.0 5 0.,

The Plant in Service and Accumulated Provision tor Depreciation balances for Nine Xlile Point

'Nuclear Unit Xo. shoivn above include disallosved costs ot S3,4.3 million. Such costs, net of income tav ettects, ivere previously ivritten ot't in 198r and 1989.

~CKKX:X:KRDI ong-Tenn Debt H orE (Thousands of Dollars)

Principal Amount December 31 Series Due 1998 1997 6.7 X July 1, 1998 5 30,000 8N Oo (a) Dec. 1, 2028 25,500 9N PP Apr. 1, 2021 100,000 100,000 Mar. 15, 2002 100,000 100,000 84A QQ (b) 6.35 RR (a) May'15, 2032 10,500 10,500 6.50 May 15, 2032 50,000 50,000 SS (a) 7.00 (b) (c) Jan. 14, 2000 30,000 30,000 7.15 Feb. 10, 2003 ~ 39,000 39,000 (b) (c)

XIar. 3, 2003 1,000 1,000 7.13 (b)(c) 7.64 Mar. 15, 2023 33,000 33,000 (c) 7.66 (c) )0lar. 15, 2023 5,000 5,000 7.67 Mar. 15, 2023 12,000 12,000 (c)

July 30, 2003 40,000 40,000 6.375 (b)(c) 7.45 July 30, 2023 40,000 40,000 (c) 5.84 (b)(d) Dec. 22, 2008 50,000 5 510,500 5 516,000 Net bpnd discount (498) (566)

Less: Due within one year 30,000 5 510,002 0 405,434 Total (a) The Series OO, Series RR and Series SS First Mortgage Bonds equal the principal amou'nt of and provide for all payments of principal, premium and interest corresponding to the Pollution Control Revenue Bonds, 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 (NYSERDA) through a participation agreement with the Company. Payments of the principal of, and interest on the Series 1992 A and Series 1992 B Bonds are guaranteed under a Bond Insurance Policy by MBIAInsurance Corporation.

(b) The Series QQ First Mortgage Bonds and the 7%, 7.15%, 7,13%, 6.375% and 5.84% medium. term notes described below are generally not redeemable prior to maturity.

(c) In 1993 the Company issued $ 200 million under a medium. term note program entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series A" with maturities that range from seven years to thirty years.

(d) In 1998 the Company issued $ 50 million under a medium-term note program entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series B" with maturities that range from severi years to thirty years.

The First Mortgage provides security for the bonds through a first lien on substantially all the property owned by the Company (except cash and accounts receivable).

Sinking and improvert(ent fund requirements aggregate $ 333,540 per annum under the First lvfortgage, excluding mandatory sinking funds of individual series. Such requirements may be met by certification of additional property or by depositing cash with the Trustee. The l 997 and I 996 requirements were met with funds deposited ivith the Trustee, and these funds ivere used for redemption of outstanding bonds of. Series Y.

On December I, 1998 the Company redeemed all its outstanding First!vlortgage 8N% Bonds, due December I, 2028, Series OO.

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

(Thousands of Dollars) 1999 2000 2001 2002 2003 I4 Series 5.'0.000 5eries QQ 5100.000

, 1 a 44 )eries 539,000

~ 13 44 5ef les 1,000 6.3 5 n 5ef les

~

40,000 a4<h0 440 530.000 0 I 00.000 580.000 048 404 I .4'i'Ã>>

0 444/14041M4

'RQMIssoRY NQTEs AicD OTHER (Thousands of Dolfars)

December 31 Issued Due 1998 1997 September 2, 1998 (e) September 1, 2033 S 25/00 $

August,19, 1997 (f) August 1, 2032 101,900 101)900 August 3, 1998 (g) August 3', 2005 24,563 December 1, 1998 (h) March 31, 2014 94)761 Other Long Term Debt of Subsidiaries (i) 1,500 Total 5248,224 5101,900 (e) The $ 25.5 million Promissory Note was issued in connection with NYSERDA's 5.95% Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), 1998 Series A. Payment of the principal of, and interest on the Series A Bonds is guaranteed under a Bond Insurance Policy by MBIA Insurance Corporation.

(f) Multi-mode pollution control notes totaling the principal amount of $ 101.9 million were issued in connection with NYSERDA's Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), $ 34,000,000 1997 Series A, $ 34,000,000 1997 Series B and $ 33,900,000 1997 Series C. The Multi-mode Revenue Bonds have a structure that enables the Company to optimize the use of short-term t'ates by allowing for the interest rates to be based on a daily rath, a weekly rate, a commercial paper rate, yn auction rate or a multi-year fixed rate. Payment of the prihc>pal of, and interest on the Multi-mode Revenue Bonds is guaranteed under Bond Insurance Policies by MBIA Insurance Corporation. At December 31, 1998'and December 31, 1997, the Multi.mode Revenue Bonds bore interest at the weekly rate and the average annual interest rate for all three series was 3.21% and 3.65%,

respectively.

The Company is obligated to make payments of principal, premium and interest on each Promissory Note which corresponds to the payments of principal, premium, if any, and interest on certain Pollution Control Revenue Bonds issued by NYSERDA as described above.

(g) The $ 24.6 million Promissory Note was issued in connection with the acquisition of Griffith'Oil,Inc. by Energetix and is secured by a pledge of the stock of Griffith Oil, Inc. The Company has made a financial guarantee on behalf of Energetix which obliga'tes the Company in the event of a default by Energetix in payments under the Note.

Payments of principal are made in seven annual installments and interest for the first three years accrues at the rate.

of 7% per yearpnd thereafter at rates varying between 7%-8N% per year.

(h) The Promissory Note was issued in connection with the Kamine Global Settlement Agreement (See Note 10.) The Promissory Note is secured by a mortgage, the lien for which is subordinate to the lien of the First Mortgage. The

$ 94.8 million liability represents the present yalue at December 31, 1998 of future obligations under the Note assuming a discount rate of 7.5 percent. This balance will decrease as payments are made o(er the term of the Note.

During 1998 the Company made payments totaling $ 7.8 million. In 1999 the Company expects to make payments totaling $ 9.6 million and thereafter, payments. totaling $ 10.6 million per year.

(i) Represents mainly promissory notes under various distribution seller agreements of Energetix aggregating S1,927 less $ 427 due within one year.

Based on an estimated borrowing rate at year-end 1998 of i.84% for long-term debt with similar terms and average maturities (1Z years), the fair value of the Company's long-term debt out-standing (including Promissory Notes as described above) is approximately $ 844 million at December 31, 1998.

Based on an estimated borrowing rate at year-end 1997 of 6.62% for long-term debt with similar terms and average maf;urities (13 years), the fair value of the Company's long-term debt out-standing (including Promissory Notes as described above} is approximatel) 565'illion at December 31, 1997.

Preferred and Preference Stock I1 oTE Type, by Order ol Seniority Value Shares Authorized Shares Outstanding Preferred Stock (cumulative) 5100 2,000,000 820,000'ar Preferred Stock (cumulative) 25 4,000,000 Preference Stock 1 5.000.000

'See below for mandato redem ption requirements.

'o shares of preferred or preference stock are reserved for employees, or for options, warrants, conversions, or other rights.

A. Preferred Stock, not subject to mandatory redemption (Thousands) ~

Optional Outstanding December 31 f

'edemption

~ Series Oecember 31 1998

~ 1998 1997 (per share) 4 F 120,000 512,000 $ 12,Ooo $ 105

'4.10 H 80,000 8,000 8,000 101 4/i ~ 1 60,000 6,000 6,000 101 4.10 4.95 K j 50,000 60,000 ~

5,000 6,000 5,000 6,000 102.5 102 4.55 M 100,000 10,000 10,000 101 Total 470,000 547,000 $ 47,000 tt May be redeemed ac any time ac the option of chg Company on 30 days minimum npciee, plus accrued dividends in all eases.

B. Preferred Stock; subject to mandatory redemption:

(Thousands)

Shares Optional Outstanding Oecember 31 Redemption 0/, Series Oecember.31, 1998 1998 '1997 (per share) 7.55 T 5 $ 10400 Not applicable 7.65 U 100,000 10,000 10,000 Not applicable 6.60 V 250,000 25,000 ~ 25,000 Not Before 3/1/04+

Total 350,000 535,000 545,000 Less: Due within one year 100,000 10,000 10,000 Total 250,000 525.000 535,000

+Thereafter at 5100.00 MANDATQRY REDE501PIloiN PRovlslQNS 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 U. All of the shares are subject ro redemption pursuartr to mandatory sinking funds on September I, 1999 at $ 100 per share.

Series V. The Series V is subject to a mandatory sinking Fund sufficient to redeem on each

.'0larch 1 beginning in 2004 to and including 2008, 12,500 shares at 5100 per share and on

.'vlarch 1, 1009, the balance of the outstanding shares. The Company has the option to redeem up to an additional 12,500 shares on the same rerms and dares as applicable to the mandatory sinking fund.

Based on an estimared dividend rare ar year-end 1998 of 4.:i "5u For Preferred.Srock, subjecr to mandatory redemption, ivith similar terms and average maturities (6.61 years), the fair value of the Company's Preferred Stock, subject to mandatory redemption, is approiimatel) 539 million at Decetllber 31, 1998.

Based on an esrimated dividend rate at year-end 1997 of 5.6 40 for Preferred Stock, subjecr to mandatory redemption, ivith similar terms and avera< e maturities. (5.9 years), the fair value of rhe S KhKK05

<v 055S I t00te; Company's Preferred Stock. subject'to mandatory redemption, is approximately S4b million at C iKC K55002 December 31. 1997.

I Connnon Stock and Stock Options I1 oTE REPURCHASE PLAiN In December 1997, the Board of Directors of the ("ompany authorized the repurchase of up to 4.5 million shares of the Company's Common Stock on the open market. A total of 1,507,000 of the shares were purchased in 1998.

,Shares Amount Outstanding (Thousands)

Balance, December 31, 1997 0 $ 0 Reacquired through Repurchase Plan (1,507,000) (46,433)

Balance, Decerhber 31, 1998 11.507,000) 5 (46,433>

CQMMQN STocK At December 31, 1998, there were 50,000,000 shares of $ 5 par value Common Stock autho-rized,'of which 37,378,813 were outstanding. No shares of Common Stock are reserved for warrants, conversions, or other rights..There were 1,965,651 shares of Common Stock reserved for employees under the 1996 Performance Stock Option Plan, as further described below. There were

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',026,840 shares of Common Stock reserved and unissued for shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan and 129,664 shares reserved and unissued for employees under the RGBcE Savings Plus Plan.

Shares Amount Outstanding (Thousands)

Balance,'ecember 31, 1995 38,453,163 $ 687,518 Shares'Issued through Stock Plans 398,301 8,612 Decrease (Increase) m Capital Stock Expense (111)

Balance, December 31, 1996 38,851,464 ~

$ 696,019 Shares Issued through Stock Plans, ~

10,883 272 Additional Paid in Capital 2,399 Decrease (Increase) in Capital Stock Expense 341 Balance, Decem6er 31, 1997 38,8621347 $ 699,031 Shares Issued through Stock Plans 23,466 586 Additional Paid in Capital 99 Repurchase Plan (1,507,000) (46,433)

,. Decrease (Increase) in Capital Stock Expense 14 Balance, December 31, 1998 37,378,813 $ 653,297 PERFORilAYCE STOCK OPTIOY PLAY

'he Company has a Performance Stock Option Plan which provides for the granting of options to purchase up to 2,000,000 authorized but unissued shares or treasury shares of S5 par value Common Stock to executive officers and other key employees. No participant shall be granted options'or more than 200,000 shares of Common Stock during any calendar year. The options would be exercisable for a period to be determined by the Committee on Management of the Board of Directors (the Committee). The Committee grants the right to receive a cash payment upon any of an option equal to the quarterly dividend payment per share of Common Stock paid 'xe'reise from the date the option was granted to the date of exercise..

In 1998, the Board of Directors granted 27.984 options at an exercise price of S33.9065 per share and 15,157 options at an exercise price of S31.0005 per share; These options are vested at 25% when the stock closes at S35 per share, 50;o at S40 per share. 75'0 at 545 per share and 100% at S50 per share. These options are exercisable for a period ot'O years. The iveighted average grant date option tair value is 55.56. The weighted average contractual remaining life at December 31, 1998 is 9.10 years.

.X<350 S <<7)75))77<@<I u)1 Pagr 425

(CohnlfuCd'flatly page 4l r In 1997, the Board of Directors granted 504,700 options at an exercise price of $ 19.0625 per share. These options are vested at 50% when the stock closes at $ 25 per share, 75% at $ 30 per share and 100% at $ 35'per share. Also in 1997, the Board of Directors granted 50,159 options at an exercise price of $ 24.75 per share. These options are vested at 25% when the stock closes at $ 25 per share, 50% at $ 30 per share, 75% at $ 35 per share and 100% at $ 40 per share. These options are exercisable'for a period of 10 years. The weighted average grant date option fair value is $ 4.60..

The weighted a'verage contractual remaining life at December 31, 1998 is 8.13 years.

In order for the options to become vested, the closing prices must be sustained at or above the levels indicated above for a minimum of five consecutive trading days.

Since the Company adopted.SFAS-123, compensation expense associated with the options granted is reflected in 1997 and 1998 net income. The compensation expense recorded was

$ 2,399,000 in 1997 and $ 239,800 in 1998. The compensation expense was calculated using the shorter of the anticipated or actual vesting period. In applying SJ'AS-123, the fair value of each option granted is estimated on the date of the grant using the Black-Scholes option pricing model with the following assumptions: risk-free rate of return ranging between 6.39% and 6.56% for 1997 and 5.54% to 5.65% for 1998, expected dividend yield of 0% for 1997 and 1998, and expected stock volatility of 17% far 1997 and 1998.

A summary of the Company's stock option activity is presented below:

Weighted Average Options Exercise Price Options granted 1997 554,859 $ 19.577 exercised 'ptions (10,883) $ 19.063 Outstanding at 12/31/97 '543,976 $ 19.587 Vested at 12/31/97 392,722 $ 19.426 Available for future grant at 12/31/97 1,445,141 Optior)s granted 1998 '3,141 $ 32.886 Options exercised (23,466) $ 19.063 Outstanding at 12/31/98 563,651 $ 20.627 Vested at 12/31/98 369.'55 $ 19 449 Available for future grant at 12/31/98 1.402,000 Sbort-Tenn Debt On December 31, 1998, the Company and its subsidiary, Energetix had short-term debt outstanding II II R

of S50.5 million and S6.5 million, respectively. At December 31,'1997 the Company had short-term 8

~I debt outstanding of $ 20.0 million. At no time during 1997 did Energetix have any short-term debt out-II I standing. The weighted average interest rates on short-term debt outstanding at year-end 1998 for the

~

a y

Company and Energetix were 5.81% and 6.66%, respectively. The weighted average interest rates for borrowings during the year ivere 5.51% and 6.31%, respectively. The weighted average interest rate on short-term debt borrowed during 1997 for the Company was 6.0i lo.

The Company's S90 million revolving credit agreement currently terminates on December 31, 2001.

Commitment fees related to this facility amounted to 597,705 in 1998 and S113,000 in 1997 and 1996.

At the time of acquisition of Griffith Oil Co.. Inc. by Energetix, Griffith secured a S15'illion revolving credit agreement. Borrowings under this agreement are secured by personal property of Griffith.

Rich< '.cr (In znJ rk.rw

'l L'fflCllkII

Energetix has made a financial guarantee on behalf of Griffith which obligates Energetix in the eventef a Griffith default.

The.Company's Charter provides that the Company may not issue unsecured debt if immediately after such issuance the total amou'nt of unsecured debt outstanding would exceed 15 percent re the Company's total secured indebtedness, capital, and surplus without the approval of at least a majoriry of the holders of outstanding Preferred Stock. As of December 31, 1998, the Company would be able to incur approximately $ 93.8 million of additional unsecured'debt under this provision. The Company has unsecured lines of credit totaling $ 47 million available from several banks, at their discretion.

In order to be able to use its $ 90 million revolving credit agreement, the Company has created a subordinate mortgage which secures borrowings under its revolving credit agreement that might other-wise be restricted by this provision of the Company's Charter. In addition, the Company has a Loan and Security Agreement to provide for borrowings up to $ 30 million as needed from time to time for other working capital needs. Borrowings under this agreement, which can be renewed annually, are secured by a lien on the Company's accounts receivable.

Commitments and Other Matters H oTE REcULATQRY AssETs With PSC approval the Company has deferred certain costs rather than recognize them on its books when incurred. Such deferied costs are then recognized as expenses when they are included in'rates and recovered from customers. Such deferral accounting is permitted by SOS-71. These deferred costs are shown as Regulatory Assets on the Company's Balance Sheet. Such cost deferral is appropriate under .

traditional regulated cost-of-service rate setting, where all prudently incurred costs are recovered

. through rates. In a purely competitive pricing environment, such costs might not have been incurred and could riot have been deferred. Accordingly, if the Company's rate setting was changed from a cost-of-service approach, and it was no longer allowed to defer these costs under SFAS-71, these assets would be adjusted for any impairment to recovery (pursuant'to SFAS-121): In certain cases, the entire amount could be written off.

SFAS-121 requires write-down of assets whenever events or circumstances occur which indicate that the carrying amount of a long-lived asset may not be fully recoverable.

Below is a summarization of the Regulatory Assets as of December 31, 1998 and 1997:

(Millions of Dollars) 1998 1997 Income Taxes 5147.6 5159.6 Kamine 192.8 Uranium Enrichment Decommissioning Deferral 15.1 16.4 Deferred Ice Storm Charges 8.9 11.5 Deferred Environmental SIR Costs 20.9 12.4 Labor Day 1998 Storm Costs 7.2 Gas Deferred Fuel 10.7 7.1 Other, net 13.1 25.0 Total - Regulatory Assets 5416.3 5232.0

~ Income Taxes: This amount represents the unrecovered portion of tax benefits from accelerated depreciation and other timing differences ivhich ivere used to reduce tax expense in past years. The recovery of this deferral is anticipated over the remaining life of the related property, ivhich varies from one to thirty years, when the effect ot the past deductions reverses in future years.

< Kamine: This amount results from a settlement resolving all litigation, releasing all claims and termi-nating all electricity purchase obligations under a popover purchase agreement.

~ Uranium Enrichment Decommissioning Deferral: The Energy Policy Act of 1992 requires utilities to contribute such amounts based on the amount of uranium enriched by the United States Department

<Note lO coorioord on pzgr Al

tconlmurd (inn of Energy (DOE) for each utility. This amount is mandated to be paid to DOE through the year 2007.

pzgr 43i The recovery of these costs is through base rates of fuel.

>+ Deferred Ice Storm Charges: These costs result from the non-capital storm damage repair costs fol-lowing the March 1991 ice storm. The recovery of these costs has been approved by the PSC through the year 2002.

i~ Deferred Environmental Site Investigation/Remediation Costs: These costs represent the Company's share of the estimated costs to investigate and perform certain remediation. activities at both Company-owned and non-owned sites with which it may be associated. The Company has recorded a regulatory asset representing the remediation obligations to be recovered from ratepayers, subject to .

the terms of the Competitive Opportunities Settlement.

~~ Labor Day 1998 Storm Costs: These costs result from a 1998 Labor Day storm. Under the Competitive Opportunities Settlement, the Company is entitled to defer, for later recovery in rates,

'ertain costs, including those caused by "catastrophic events", when any single event results in costs exceeding $ 2.5 million. The Cotnpany has filed a petition with the PSC notifying them of the deferral of these storm costs..

~ Gas Deferred Fuel: These costs result from a PSC-approved annual reconciliation of recoverable gas costs with gas revenues in which the excess or deficiency is refunded to or recovered from cus'tomers during a subsequent period.

In a competitive electric market, strandable assets would ar'ise when investments are made in facilities, or costs are incurred to service customers, and such costs are not fully,recoverable in market-based rates.'

Examples include purchase power contracts or high cost generating assets. Estimates of strandable assets are highly sensitive to the competitive wholesale market price assumed in the estimation. The amount'of potentially strandable assets at December 31, 1998 dep'ends on market prices and the competitive market in New York State which is still under development and subject to continuing changes which are not yet determinable, but could be significant. Strandable assets, if any, could be written'down for impairment of recovery in the same manner. as deferred costs discussed above.

In a competitive natural gas market, strandable assets would arise where customers migrate away from dependence on the Company for full service, leaving the Company with surplus pipeline and storage capacity,"as well as natural gas supplies, under contract. The Company has been restructuring its transportation, storage and supply portfolio to reduce its potential exposure tostrandable assets.

Regulatory developments discussed under "Gas Cost Recovery" below, may affect this exposure; but whether and to what extent there may be an impact on the level and recoverability of strandable assets cannot be determined at this time.

At December 31, 1998 the Company believes that its regulatory and strandable assets, if any, are not impaired and are probable of recovery. The settlement approved in the Competitive Opportunities proceeding (Competitive Opportunities Settlement) does not impair the opportunity of the Company to recover its investment in these assets. However, the PSC issued an Opinion and Order Instituting Further Inquiry on March 20, 1998 to address issues surrounding nuclear generation. The ultimate determination in this proceeding could have'an impact on strandable assets and the recovery of nucleat costs. The initial meeting in this Inquiry was held in January 1999 and such a determination is unlikely before year-end.

CAPlTAL EXPEND) TURES The Company's 1999 construction expenditures program is currently estimated at S I 14 million. The Company has entered into certain commitments for purchase of materials and equipment in connection with that program.

Nuclenr-Retnted iMntters f Decommissioning Trust. The Company is collecting amounts in its electric rates for the eventual RikMcf decommissioning of its Ginna Plant and for its 14";0 share ot the decommissioning of Nine Mile'Two.

(sli J1J l1C'ital 'l The operating licenses tor these plants expire in 2009 and 2026, respectively; Otp'4JtNVl

Under accounting procedures approved by the PSC, the Company has collected decommissioning costs of approximately $ 138.3 million through December 31, 1998 and is authorized to collect approxi-mately $ 22 million annually through June 30, 2002 for decommissioning, covering both nuclear units.

The amount allowed in rates is based on estimated ultimate decommissioning costs of $ 296.3 million for Ginna and $ 112.8 million for the Company's 14% share of Nine Mile Two (1995 dollars). These esti-mates are based on site specific cost studies for each plant completed in 1995. Site specific studies of the anticipated costs of actual decommissioning are required to be submitted to the NRC at least five years prior to the expiration of the license.

The NRC requires reactor licensees to submit funding plans*that establish minimum NRC external funding levels for reactor decommissioning. The Company's plan, filed in 1990, consists of an external decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two sbare. Since 1990, the ~

Company has contributed $ 107.3 million to this fund and, including realized and unrealized investment returns, the fund has a balance of $ 183.5 million as of December 31, 1998. The amount attributed to the allowance for removal of non-contaminated structures is being held in an internal reserve. The internal reserve balance as of December 31, 1998 is $ 31.0 million.

The NRC has issued a policy statement relating to industry restructuring which addresses, in part, the prospects of joint and several liability of co-owners for nuclear decommissioning costs, such as co-

. owner's of Nine Mile Two. The NRC recognizes that co-owners generally divide costs and output from their facilities by using a contractually-defined,'ro rata share standard. The NRC has implicitly accepted this practice in the past and believes that it should continue to be the operative practice, but reserves the right, in highly unusual situations where adequate protection of public health and safety would be compromised'if such action were not taken, to'consider'imposing joint and several liability on co-owners when one or more co-owners have defaulted.

The PSC in August 1997 issued for comment a report by its staff proposing norms by which nuclear plants in the state would relate to the competitive electricity market following the'period covered by electric utility restructuring agreements then pending before the PSC. Among other things, the report envisioned the sale of these plants at auction, but with the selling utilities remaining responsible for ultimate decommissioning as well as for disposal of certain spent fuel. Recognizing that bidders may not be attracted to certain units which could include both the Company's Ginna plant and the Nine Mile Two plant in which it has a 14% interest, the report contemplated their early shutdown 'unless they

'ould compete with other forms of generation. In Fall 1997, the Company and others commented on these and other facets of the report. On March 20, 1998 the PSC issued an Opinion and Order Instituting Further Inq'uiry. In December 1998 the PSC issued a Notice of Collaborative Conference to further examine the future treatment of nuclear generation. The initial collaborative conference in this proceeding will be held in January, 1999.

The Staff of the Financial Accounting Standards Board is studying the recognition, measurement and classification of certain liabilities related to the closure or removal of long lived assets. This could affect the accounting for the decommissioning costs of the Company's nuclear generating stations. If current accounting practices for such costs were changed, the annual provisions for decommissioning costs could increase, the estimated cost for decommissioning could be reclassified as a liability rather than as accumulated depreciation, the liability accounts and corresponding plant asset accotints could be increased and trust fund income from the external decommissioning trusts could be reported as invest-ment income rather than as a reduction to decommissioning expense.

If annual decommissioning costs increased, the Company would expect to defer the effects of such costs pending disposition by the PSC.

Uranium Enrichment Decontamination and Decommissioning Fund. On June 12, 1998, 16 electric utilities from across the country. including the Company, filed a multi-count complaint against the United States government in the United States District Court for the S< uthern District of Ken York. The suit challenges the constitutionality of a S2.25 billion'etroactive assessment imposed by Xnlc IOciinhmiedom p.tgr 46(

Irontinnrd frow the federal government on domestic nuclear power companies to pay for the clean up of the federal gov-psgr ISED ernment's three uranium enrichment plants. Those plants are located at Oak Ridge, Tennessee, Paducah, Kentucky, and Portsmouth, Ohio. The Oak Ridge plant went into operation in 1945, and the other two plants began operation during the 1950s.

The assessment, enacted by Congress as part of the Energy Policy Act of 1992, is based on the amount of uranium enrichment services purchased by the utilities as far back as the 1950s and is to be collected over @15-year period. The assessment, if not overturned, would relieve the government of a substantial portion of the costs it would otherwise have to pay for decommissioning and decontaminat-ing its three uranium enrichment facilities. In their complaint, the utilities seek a declaratory judgment that the assessment violates the due process cia'use of the Constitution because it abrogates vested rights the utilities obtained under fixed-price agreements with the government when they purchased uranium enrichment services. The utilities also challenge the assessment as unreasonably retroactive. The suit seeks an injunction prohibiting the government from continuing to collect the assessment from the plaintiff utilities.

The assessments for Ginria and the Company's share of Nine Mile Two are estimated to total

$ 22.1 million, excluding inflation and interest. Installments aggregating approximately $ 11.2 million have, been paid through 1998. A liability has been recognized on the financial statements along with a corresponding regulatory asset. For the two facilitids the Company's liability at December 31, 1998 is

$ 13.9 million ($ 12.2 million as a long-term liability and $ 1.7 million as a current liability). The Company is recovering costs through base rates of fuel.

Nuclear Fuel Disposal Costs. The Nuclear Waste Policy Act INuclear Waste Act) of 1982, requires the DOE to establish a nuclear waste disposal site and to take title to nuclear waste.

as'mended, A permanent DOE high-level nuclear waste repository is not expected to be operational before the year 2010. In December 1996 the DOE notified the Company that the DOE will not start acceptance of Ginna spent fuel in 1998. The Nuclear Waste Act provides for a determination of the fees collectible by the DOE for the disposal of nuclear fuel irradiated prior to April 7, 1983 and for three payment options.

The option of a single payment to be made at any time prior to the first delivery of fuel to the DOE was selected by the Company in June 1985. The Company estimates the fees, including accrued interest, owed to the DOE to be $ 87.6 million at December 31, 1998. The Company is'allowed by the PSC to recover these costs in rates. The estimated fees are classified as a long-term liability and interest is accrued at the current three-month Treasury bill rate, adjusted quarterly. The Nuclear Waste Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of approximately one mill ($ .001) per KWH of nuclear energy generated and sold. This charge (approxi-mately $ 4.7 million per year) is currently being collected from customers and paid to the DOE pursuant to PSC authorization.'The Company expe'cts to utilize on-site storage for all spent or retired nuclear fuel assemblies'until an interim or permanent nuclear disposal facility is operational.

There are presently no facilities in operation in the United States available for the reprocessing of spent nuclear fuel from utility companies. In the Company's determination of nuclear fuel costs it has taken into account that nuclear fuel would not he reprocessed and has provided for disposal costs in accordance with the Nuclear Waste Act. In November 1998 the Company completed installation of seven high-capacity spent fuel racks in the spent fuel pool. This will allow interim storage capacity of all spent fuel discharged from the Ginna Plant through the end ot its Operating License in the year 2009.

EXVIROXXlEXTALMAXI'ERS The Company is subject to federal, state and local laivs and regulations dealing with air and water quality and other environmental matters. Environmental matters may expose the Company to potential liabilities which, in certain instances, may be imposed ivithout regard to fault or historical activities ivhich ivere lawt'ul at the time they occurred. The Company continually monitors its activities in order to determine the impact of its activities on the environment and to ensure compliance with various environ-RA.&trr (ow JF t n:o mental laws. The Company has recorded a total liability of approximately 524.2 million in connection a ~ ~rr nxiw with Site Investigation and/or Remediation tSIRl efforts where disposal of certain waste products may

have occurred. Estimates of the SIR costs for each of these sites range from preliminary to highly refined.

The Company expects to pay these SIR costs over the next ten years. These estimates could change materially, based on facts and circumstances derived from site investigations, changes in required'emedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations. Liability may be joint and several. for certain of these sites. There may be additional costs with respect to these and possibly other sites, the materiality of which is not presently determinable.

Company-Owned Electric and Gas 5'aste Site Activities. The Company is conducting proactive SIR efforts at seven Company-owned sites where past waste handling and disposal may have occurred.

Remediation activities at five of these sites are in various stages of planning or completion and the Company is conducting a program to restore the other two sites. The Company has recorded a liability of approximately $ 21.6 million for SIR efforts'at the seven Company-owned sites in the Rdchester, NY area.

Superfund and Non-Owned Other Sites. The Company has been or may be associated as a potentially

. responsible party at eight sites not owned by it and has recorded estimated liabilities of approximately

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$ .8 million in connection with SIR efforts at these sites. The Company has signed orders on consent for five of these sites.

Griffith Facilities. The Company's subsidiary, Energetix, recently acquired Griffith Oil, Inc. A review and audit was conducted of all Griffith facilities by a nationally recognized engineering firm as part of the due diligence acquisition process by Energetix. As a result of the review of 43 sites and subsequent subsurface investigations of 26 sites, thirteen new New York State Department of Environmental Conservation (NYSDEC) spill numbers ivere assigned. These sites are, currently undergoing evaluation and remediation planning for corrective action. Using historical NYSDEC remedial actions as a guide,

, Energetix estimates the accrual of aggregate cleanup costs over' five-year period for all 43 sites approximates $ 1.8 million.

GAS CORI'ECOVERY The Company entered into several agreements to help manage its pipeline capacity costs and has successfully met Settlement targets for capacity remarketing for the twelve months ending October 31, 1998, thereby avoiding negative financial impacts for that period. In July, the Company entered into an agreement with Dynegy Ma'rketing and Trade to provide assistance with respect to the management of the Company's gas supply, transportation and storage costs consistent with the goal of providing reliable service and reducing the cost of gas.

On October 16, 1998, the Company, the staff of the PSC and certain other parties entered into an interim settlement agreement, designed to address the period between expiration of the 1995 Settlement and the implementation of a new multi-year settlement to be negotiated. The interim settlement was approved by the'PSC on November 4, 1998. In its ruling, the PSC indicated that the allocation of transi-tion costs that result from the migration of customers to other gas suppliers under the Interim Settlement Agreement may be subject to revision after it considers similar issues in another case. Wiajor elements of the interim settlement include: (I) the'term is from December 1, 1998 through the earlier of June 30, 1999 or the effective date of a'new multi-year agreement; (2) base rates, which cover the cost of the local distribution system, will remain frozen for all customers at their current level (which were fixed at the

'July 1994 level pursuant to the 1995 Settlement that expired on October 31, 1998), while the Gas Cost Adjustment will continue to vary from month to month; (3) a level of revenues (S11.9 million on an annual basis) which corresponds to the Company's anticipated revenues from capacity remarketing transactions currently in place is imputed to the Company; (4) the Company will share 15% of the savings realized from the reduction of capacity commitments; (5) the Company will simplify the trans-portation gas program and cap the migration of customers at 10% of annual retail sales and not assign capacity costs to certain migrating customers; (6) the Company will be allowed to recover the upstream costs that may be stranded by migration; and, (7) certain issues relating to past gas costs have been resolved whereby the Company shall set aside, in a manner to be determined by the PSC for the benefit of customers, S2.2 million of the total amount recovered through the Gas Cost Adjustment.

(Xlilt l<J tnnlimitd on pJgt Agl

(connnucd /rnm LITIGATION pvgc 47)

Spent Nuclear Fuel Litigation. The federal Nuclear Waste Act obligated DOE to accept for. disposal spent nuclear fuel (SNF) from utilities'owerplants by January 31, 1998 (Statutory deadline). Since the mid-1980s, the Company and other nuclear. plant owner's and operators have paid substantial fees to DOE to fund that obligation (Nuclear Waste Fund). That DOE would not meet its obligation was evident well prior to 1998; DOE admitted as much as the statutory deadline approached.

In 1994, Northern States Power Company and other owners of nuclear plants filed suit against'DOE and the federal government in the U.S. Court of Appeals for the District of Columbia Circuit (Court)"

seeking a declaration that DOE's course of action was in violation of its statutory obligation and requesting other relief. In 1996, the Court upheld the utilities'osition that DOE is obligated to accept and dispose of the utilities'NF by the statutory deadline. The Court rejected the DOE contention that it could defer the disposal until the availability of a suitable SNF repository, but stopped short of providing the utilities a remedy since DOE had not yet defaulted.

In late 1996, DOE invited nuclear utilities'iews on how its anticipated inability to meet the statutory deadline could "best be accommodated." The Company and a number of other parties responded to that invitation.

By a Joint Petition for Review, the Company and othe'r nuclear utilities'petitioned the Court in

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January 1997 for a declaration that the Petitioners were relieved of the obligation to pay fees into the Nuclear Waste Fund, and were a'uthorized to place those fees into escrow until DOE commences dispos-ing of SNF. The petition further requested that DOE be ordered to develop a program that would enable it ta begin acceptance of SNF by the statutory deadline. In November 1997, the Court held that DOE could not delay acceptance on grounds that it lacked an SNF repository, and that the utilities had a "clear right to relief". Rather than grant funding relief and order the DOE to move SNF, however, the Court referred the utilities to their contractual remedies against DOE. State agencies, municipal govern-men'ts and DOE sought review of this decision, but the U.S. Supreme Court declined in November 1998 to hear the case. The Company, joined by several otlier nuclear utilities, in July 1998 initiated a further effort to have the Co'urt provide a suitable remedy under its "original and exclusive" jurisdiction over matters arising un'der the Nuclear Waste Act. The Court has yet to rule on that request.

DOE's'ailure to meet its statutory deadline has given rise to numerous other lawsuits. For example, several plant operators brought suit against DOE in the U.S. Court of Federal Claims. In decisions issued in October and November 1998, that court held that DOE had breached its contractual obliga-tions. It denied most portions of DOE motions to dismiss the operators'laims and granted the opera-tors'ummary judgment on DOE contract liability.

It is not possible to predict the future course of this obligation or the resolution of the spent nuclear fuel movement and storage concern that underlies it. The current court rulings on the DOE's default in meeting its obligation to remove SNF by the statutory deadline, and on its contractual liability therefor, have been promising. The current court rulings appear to have prompted greater DOE effort to complete site investigations at its Yucca Xiountain, 4V, site for SXF disposal and to focus greater Congressional attention on the inappropria'teness of continuing to house SNF around the nation at short-term SNF facil-ities of nuclear polverplants. These developments have not yet led, however, either to a firm schedule for DOE's movement of SNF from plant facilities to a permanent repository or to the authorization of plant owners and operators to withhold their Nuclear Waste Fund payments to DOE until that schedule is established. The Company and other nuclear utilities continue to work toward those objectives.

Litigation With Co-Generator. On December I 1998 the Company completed the closing under its

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Global Senlement Agreement with General Electric Capital Corporation (GECC), Kamine/Besicorp Allegany L.P. (Kamlne) and other Kamine affiliates. In connection with the closing, the Company paid S 10 million and gave a promissory note in the aggregate amount of S 168 million payable to GECC. The promissory note is secured bl a general mortgage on the Company's property which mortgage is subject and subordinate to the Company's First XIortgage. The mortgage is not recorded but may be recorded in RaibL~tCf the event of. default. In addition. the Company purchased the gas-fired generation facility rated at 6jl Ilv in'lew',:"i 4 snfInJil 'n ~

Ior S 15 million. The Global Settlement was approved by the PSC which authorized the Company to recover the payments in rates.'

OTHER MATTERS Other Statement of Income Items, The change in Ot)1er Income and Deductions, Other-net in 1998 reflects'the recognition of income due to the reversal of certain deferred credits in accordance with the Competitive Opportunities Settlement. In prior years, the PSC had required the Company to establish.

deferred credits to account for certain pension and other post-employment benefit charges and Nine Mile Two operating and maintenance expenses. In 1998, these deferred credits totaling $ 17.4 million were eliminated consistent with the terms of the Settlement and discussions'with the PSC. An amount of $ 8.8 million associated with certain pension charges was reflected on th'e Company's books in the first quarter of 1998, after the Company received the written order associated with the Competitive Opportunities Settlement. An amount of $ 6.0 million associated with certain Nine Mile Two operating and maintenance expenses was reflected ratably over each of the four quarters of 1998, consistent with Nine Mile Two accounting practices. The remainder associated with certain other post-employment benefits was reflected in the second quarter of 1998, after the Company had concluded discussions with the PSC. The Company does not have any deferred credits which are subject to PSC Orders which would permit the recognition of any significant credits to income in the future. This income was partially offset by expenses associated with the gas interim senlement agreement.

EITF Issue 97-4'Deregulation of the Pricing of Electricity. In July 1997, the Financial'Accounting Standards Board's Emerging Issues Task Force (EITF) reached a consensus on accounting rules for plans for moving to more competitive environments and provided guidance on when 'tilities'ransition utilities with transition plans will need to discontinue the application of SFAS-71,'Accounting for of Certain Types of Regulation".,

the'ffects The major EITF consensus was that the application of SFAS-71 to a segment (e.g. generation) which.

is subject to a deregulation transition plan should cease when the legislation or enabling rate order contains sufficient detail for the utility to reasonably determine what the transition plan will entail. The EITF also concluded that a decision to continue to carry some or all of the regulatory assets (includihg stranded costs) and liabilities of the separable portion of the business that is discontinuing the applica-tion of SFAS-71 should be determined on the basis of where the regulated cash flows to realize and settle them will be derived. If a transition plan provides for a non-bypassable fee for the recovery of stranded costs, there may not be any significant write-off if SFAS-71 is discontinued for a segment.

'he Company's application of the EITF 97-4 consensus has not affected its financial position or results of operations because any above-market generation costs, regulatory assets and regulatory liabili-ties associated with the generation portion of its business will be recovered by the regulated portion of the Company through its distribution rates, given the Settlement provisions. The Settlement provides for recovery of all prudently incurred sunk costs (all investment in electric plant and electric regulatory assets) as of March 1, 1997 by inclusion in rates charged pursuant to the Company's distribution access tariff. The Settlement also states that "the Parties intend that the provisions of this Settlement will allow the Company to continue to recover such costs, during the term of the Settlement, under SFAS-71", and that "such treatment shall be consistent with the principle that the Company shall have a reasonable opportunity beyond July 1, 2002 to recover all such costs". The fixed portion of the non-nuclear genera-tion to-go costs after July 1, 1999 and the variable portion of the non-nuclear generation to-go costs after July 1, 1998 are subject to market forces and would no longer be able to apply SOFAS-71. The Company's net imestment at December 31, 1998 in nuclear generating assets is $ 666.9 million and in non-nuclear generating assets is $ 117.9 million.

Lease Agreements. The Company, including Energetiv, leases 1i properties for administrative offices, operating activities and vehicles. The total lease expense charged to operations was $ 4.8 million, S4.2 million and S3.9 million in 1998, 1997 and 1996. respectively. For the years 1999, 2000, 2001, 2002 and 2003 the estimated lease expense charged to operations ivill be S5.2 million, S3.4 million, $ 3.3 million, S2.9 million and S2.8 million, respectively. Commitments under capital leases ivere not signifi-cant to the accompanying financial statements.

Gas Purchase Commitments. Energetix has entered into natural gas purchase commitments with numerous gas suppliers. These commitments support a fixed price otfering to retail gas customers.

~ 0 REPORT OF IIIAIlAGEIIIEIIT The management of Rochester Gas and Electric Corporation has prepared and is responsible for the consoli-dated financial statements and related financial information contained in this Annual Repor't. Management uses its best judgements and estimates to'ensure that the financial statements reflect fairly the financial position, results of

'perations and cash flows of the Company in accordance with generally accepted accounting principles.

Management maintains a system of internal accounting controls over the preparation of its financial statements designed to provide reasonable assurance as to the integrity and reliability of the financial records..

This system of internal control includes documented policies and guidelines and periodic evaluation and testing'y the internal audit department.

The Company's financial statements have been examined by PricewaterhouseCoopers LLP, independent accountants, in accordance with generally accepted auditing standards. Their examination includes a review of the Company's system of internal accounting control and such tests and other procedures necessary to express an opinion as to whether the Company's financial statements are presented fairly in all material respects in conformity with generally accepted accounting principles..The reporr of PricewaterhouseCoopers LLP is presented on page 24.

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

Management believes that, at December 31, 1998, the Company maintained an effective system of internal control over the preparation of its published financial statements.

Thomas S. Richards J. Burt Stokes Chairman of the Board, President and Senior Vice President, Corporate Services and Chief Executive Officer Chief Financial Officer January 20, 1999 j.IITERllh FIIIAIIC1ALDATA In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods. The variations in operations reported on a quarterly basis are a result of the seasonal nature of the Company's business and the anil-ability of surplus electricity. The sum of the quarterly earnings per share may not equal the fiscal year earnings per share due to rounding.

(Thousands of Dollars)

Earnings per Common Share Operating Operating Net Earnings on (in dollars)

Quarter Ended Revenues Income Income .Common Stock Basic Oiluted December 31, 1998 5 2S7.106 5 22.345 5 IS.OI5 5 14.088 50.37 50.37 September 30, 1998 253.606 34,444 25.2I3 13.908 0.62 0.61 June 30, 1998' 211.134 11 103 I5.655 14,350 0.37 0.37 larch 31, 282.516 48.16S 3S.255 36,950 0.95 0.95 51'6 1998'ecember

31. 199c 52 1.039 524.406 5 I4.03 I 50.32 50.32 September 30, 199" "1.331 34.616 20.419 0.52 0.52

'1'19 June 30. 199. 419 IS,I 2 16.6S I 0.42 0.42

%larch 31. 199 3 I 4.845 55.I94 4 I.433 ~9 '9 1.02 102 December 31. 5 '.43l 5 13.048 52 i).362 50.52 50.52

30. 1996 1996'eptember

'34.84) 36.I59 '.i)62 I e. I 96 0.49 0.49 June 30. 1996 "1.I IS II <.866 0.25 0.25 Rii'hCNCC %larch 31. 1996 )OCi.l9t 5 6.866 4 .489 40.623 1.05 I.i)5 ale J14 i S'sich

\ ~ <Cpl V Jill

'Reclassified tor comp.ir.itive purposes.

0 CBIIIIIIBIISTBCK AI1D DiViDEIIDS Earnin s/Ditndends 1998 1997 1996 S bares/Sbarebolders 1998 1997 1996 Earnings per share Number of shares (000's)

,basic 52.32 52.30 S2.32 Weighted average diluted 52.31 52.30 52.32 basic 38,462 38,853 38,762 Dividends paid diluted 38,600 38)909 38,762 per share 51.80 51.80 Sl.80 . Actual number at December 31 37,379 38,862 38,851 Number of shareholders at December 31 28,995 31,337 33,675 TAX STATUS OF CASH DIVIDENDS.

Cash dividends paid in 1998, 1997 and 1996 were 100 percent taxable for federal income tax purposes.

DIVIDEND POLICY.

The Company has paid cash dividends quarterly on its Common Stock without interruption since it became publicly held in 1949. The level of future cash dividend payments will be dependent upon the Company's future earnings, its financial requirements and other factors. The Company's Certificate of Incorporation provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company.

Quarterly dividends on Common Stock are generally paid on the twenty-fifth day of January, April, July and October. In January 1999, the Company paid a cash dividend of $ .45 per share on its Common Stock. The January 1999 dividend payment is equivalent to $ 1.80 on an annual basis.

COMMON STOCK TRADING.

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

1998 1997 1996 Common Stock Price Range High 1st quarter 33'/i 20'/< 23'/.

'nd quarter 32'/i 21%i 21/i 3rd quarter 32%. 24"/)< 21)/i 4th quarter 33'/i 34</< 19>>/i Low 1st quarter 29'/ ') '/

18/< 1 2nd quarter 29%). ~ 18 19/>>

3rd quarter 28%>> 20i/1 18 quarter

'th 28%. 23'/ I?/i At December 31 3 I '/i 19)/.

~ . ~

SELECTED Firtls rlCiAL DATA (TI>ousands of Dollars) Year Ended December 31 1998 1997 1996'995'994'993 Consolidated Summary of Operations Operating Revenues Elect'ric . 5 687,970 5 700,329 5 707,768 5 722,465 5 674,753 5655,316 Gas 275,177 336,309 346,279 293)863 326,061 293,708 Other 71,215 Total Operating Revenues 1,034,362 1,036,638 1,054,047 1,016,328 '1,000,814 949,024 Operating Expenses Fuel Expenses Fuel for electric gerieration 53,954 47,665'0,938 44,190 44,961 45,871 Purchased electricity 27,024 28,347 46,484 54,167 37,002 '31,563 Gas purchased for resale 155,497 196,579 202,297 167,762 194,390 166,884 Unregulated fuel expenses 60,001 Total Fuel Expenses 296,476 272,591 289,719 266,119 276,353 244,318 Operating Revenues Less Fuel Expenses 737,886 764,047 '64,328 750,209 724,461 704,706 Other Operating Expenses Operations and maintenance excluding fuel expenses 301,625 315,109 313,157 308,433 296,741 302,035 Unregulated operating and maintenance expenses excluding fuel 13,257.

Depreciation and amortization 116,122 116,522 105,614 91,593 87,461 84,177 Taxes local, state and other 118,337 121,796 126,868 133,895 129,778 126,892 Federal income tax current 70,541 69,812 65,757 65,368 35)658 33,453 deferred 19,1561 (4,533) 3,744 847 25,587 15,877 Total Other Operating Expenses 610,726 618,706 615,140 600,136 575,225 562,434 Opera'ting Income '27,160 145,341 149,188 150,073 249,236. 142,272 Other (Income) arid Deductions Allowance for other funds used during construction (408) (351) '684) (585) (396) (153)

Federal income tax 516 (3,704) (3,450) (16,948) (16,259) (9,827)

Regulatory disallowances 26,866 600 1,953 Pension Plan Curtailment 33,679 8,179 Other, net (13,181) 3,308 (712) 9,631 (923) 2,113 Total Other (income) and Deductions (13,073) (747) (4,846) 18,964 16,701 2,265 Interest Charges Long. term debt 42,590 44,615 48,618 53,026 53,606 56,451 Short-term debt 431 398 1,808 I,487 Other. net 3,727 6,629 9.30 8.658 4."58 5 220 Allo>vance for borrowed funds used during construction (653) f563I r l,423) f2.90 1 I (2,0 I 2) (1,714)

Total Interest Charges 46,095 50,"28 .'>6,D 3 59.18 I 58. I 60 61,444 Net Inconre 94,138 95.360 9..51 I 7I.928 78,563 Dividends on Preferred Stock at Required Rates 4,842 5.805 .465 ".,465 ".,369 7,300 Eanrings Applicable to Common Stock 5 $ 9.396 .5 59 SSS S 90.046 S 64.463 5 6 .006 5 )1.363 Earnings per Common Share-Basic 52.30 51.69 5 I.79 52.00 Eanrings per Co>nmon Slrare Diluted 53..10 50 30 51.69 Sl.:9 51.00 C<rsb Divirlends Declared per Conrmon Share 51.50 S 1.)0 5 I 50 SI:50 5 I. 51..3 014'<<las)>he J l<>r <<<>n>I).>rat>v<< I urf)I>5<<i.

Condensed Consolida alance Sheet (Thousands of Dollars) At December 31 1998 1997'996'995'994'993'ssets UtilityPlant 53,326,995 53.234.077 '3.159.759 53,068.1P3 52,981 ~ 151 52,890,799 Less: Accumulated depreciation and amortization 1,863,475 1,714,368 1,$ 69,07S 1,518,878 1,423,09S 1,335,0S3 1,463,520 1,519,709 1)590,681 1,549,225 1,558,053, 1,555,716 Construction work in progress 98,554 74,018 69,711 121,725 128,860 112,750 Net utiliry plant 1,562,074 1>593,727 1,660,392 1,670,950 1,686,913 1,668,466 Current Assets 202,963 242,371 2$ 0,461 292,596 236,519 248,589 Investment in Es(spire 38,879 ".

38,560 38,560 Intangible Assets 21,062 Deferred Debits and Other Assets 666,836 432,191 450,623 453,726 484,962 488,527 Total Assets 52,452,935 52,268,289 52,361,476 52,456,151 52,446,954 52,444,142 Capitalization and Liabilities Capi tali zati on Long-term debt $ 758,226 $ 587,334 5 646,954 5 716,232 $ 735,178 $ 747,631 Preferred stock redeemable at option of Company 47,000 47,000 67,000 ~ 67,000 67,000 67,000 Preferred stock subject to mandatory redemption 2$ )000 35,000 45)000 ~, 55,000 55)000 42,000 Common shareholders'quity:

Common stock 699,730 699,031 696,019 687,518 670,569 652,172 Retained earnings 129,484 109,313 90,$ 40 70,330 74,566 75 126 Less: Treasury stock at cost (1,507,000 shares) 46,433 Total common shareholders'quity 782,781 808,544 786,559 757,848 745,135 '27,298 Total Capitalization 1,613,007 1,477,678 1,545,513 1,596,080 1,602,313 1,$ 83J29 Long-Tenn Liabilities (Department of Energy and Site Remediation) 123,920 110,352 106,578 101,561 88,500 89,804 Current Liabilities 183,369 3 75,691 145,391 171,664 ~

180,653 234,530 Deferred Credits and Other Liabilities 532,639 504,568 563,994 586,846 575,488 535,879 Total Ca italization and Liabilities $ 2,452,935 $ 2,268,289 $ 2,361,476 $ 2,456351 52,446,954 $ 2,444,142

'Redassified for comparative purposes.

Financial Data At December 31 1998 1997 1996 1995 1994 1993 Capitalization Ratios(a) (percent)

Long-term debt 49.8 43.0 44.7 47.4 48.2 494 Preferred stock 4.2 5.2 6.9 7.3 7.3 6.6 Common shareholders'quity 46.0 51.8 48.4 45.3 44.5 44.0 Total 100.0 100.0 100.0 100.0 100.0 100.0 Book Value per Common Sirare Year End $ 20.94 520.80 $ 20.24 $ 19.71 $ 19.78 519.70 Rate of Return on Average Common Equity (b)

(percent) 11.22 11.00 11.41 8.37 8.92 10.25 Embedded Cost of Senior Capital (percent)

Long-term debt 7.20 .38 40

" '6 Preferred stock 5.56 5.80 6.26 6 '6 6.26 6.69 Effective Federal Income Tax Rate (percent) 39.7 39.2 o/ ~ >> 33.5 Depreciation Rate (percent) Electric '3.09 3.12 2.99 2.69 2.6')

Gas 2.64 2.60 2.60 ~ 2.59 2.60 Interest Coverages Before federal income, razes (incld. AFUDC) 4.41 4.06 3.S2 2.95 2.98 2.87 (excld. AFUDC) 4.38 4.04 2.90 2 94 2.84

')

After federal income taxes (incld. AFUDC) 3.06 2.86 2.68 2.16 14 (evcld. AFUDC) 3.03 2.S4 2. I 0

') ')0 ) 7I Interest Coverages'Evclsrdissg Nots-Recssrrissg Items (c)

Before federal income taxes (incld. AFUDCI 4.41 4.06 3.S2 3.66 3.55 3.03 (ezcld. AFUDCI 4.3S 4.04 3.61 3.00 After federal income taxes (incld. AFUDC) 3.06 '6 0.68 l 65

')

61 3.51 2.61 2.35 (excld. AFUDCI 3.03 2.84 s .J J Inde) Com)wn)>>) Iona term hah!Its to th>> Dcp nmcnt ot Enefp DOE i)>> nuiscar )IJ>>e J>>p>>JE Ei:.'u~ DOE loot term (i&I!Itsior ur Jnlvln cnr>>ament Je >>>>nm>>sionlnr anJ amounts Jucnrrcdccma!4!eiinhlnmeyear.

h The retvrn on>>erase v)mm4>>) cavil! tOt I>".< ei luJIne Ci ceti oi the I'H t 0>>>> icttselv>>nt Ii I '. lit ">>. The rate 41 fnum on JI et Jee'ommon c)Iu)ty Cielo Jinpciic'u ili rcnrCmem enhancement rroeramiresv>>rnlreJ hl the C4>>nrans ln lo"J 2nd loot ls I I."o"- JnJ I I.'I >>. fc wenlic!i.

Coieraeei ti4r looa JnJ I "as eic!vJc the citcaioirctlremcnt cnh)ncemcnt "rIISramifei4>>'nllcJ hi" lhc(4'

nl Jni Jul l.,'cJehicJr JnJ i'crtaln et) pvfeht>>eurldcfehames iiflttefloft u) iona JnJ I"os, CillcfJScstn lo",4 ciclude:hero)n4)ml,'ei est>>it thc loot (iai N'.emcn: SJJ.'l'114)n.pret@,.

ELECTRIC DEPARTIh EIGHT STATISTICS Year Ended December 31 1998 1997 1996 1995 1994 1993 Electric Revenue (000's)

Residential $ 250,073 $ 252,464 $ 254,885 $ 256,294 $ 243,961 $ 234,866 Commercial 203,338 ., 210,643 215,763 215)696 206,545 196,100 Industrial 130,778  ! 144,305 153,337 157,464 150,372 148,084 Municipal and Other 58,889 72,061 66,898 67,128 57,270 59,905 Electric revenue from our customers 643,078 679,473 690,883 696,582 658,148 638,955 Wholesale electric, 44,022 20,856 16,885 25,883 16,60$ 16,361 sales'otal electric revenue 687,100 700,329 707,768 722,465 674,753 655,316 Electric Expense (000's)

Fuel used in electric generation 53,954 47,665 40,938 44,190 44,961 '45)871 Purchased electricity 27,024, 28,347 46,484 54,167 37,002 31,563 Other operation 195,400 205,058 204,746 199,524 192,360 192)749 Maintenance 38,022 41,217'03,395 41,429 44,032 47,295 52,464 Depreciation and amortization

• 102,123 92,615 78,812 .75,211 72,326 Taxes local, state and other 89,164 91,111 95,010 ~ 102,380 97,919 96,043 Total electric expense 505,687 $ 16,793 521,222 523,105. 494,748 491,016 4

Operating income before Federal Income Tax 181,413 '83,$ 36 186,$ 46 199,360 180,005 164,300 Federal income tax 61,477 61,837 61,901 59,500 52,842 43,845 Operating Income from Electric Operations (000's) $ 119/36 $ 121,699 $ 124,645 $ 139,860 $ 127,163 $ 120,455 Electric Operating Ratio % ,45.8. 47.1 47.3 47.7 49.2 Electric Sales KWH (000's) J Residential 2,111,739 21139,064 2,132,902 2,144,718 2)117,168 2,123,277.

Commercial 2,007,282 2,118,991 2,061,625 2,064,813 2,028,611 1,986,100 Industrial 1,929,268 2,010,613 2,010,963 , 1,964 975 1,860,833 1,892)700 Municipal and Other $ 14,243 537,051 520,885 531,311 513,675 504,987 Total customer sales 6,562,532 6,805,719 6,726,375 6,705,817 6,520,287 6)507,064 Wholesale electric 1,671,959 1,218,794 994,842 1,484,196 1,021,733 743,588 sales'otal electric sales 8834,491 8,024,513 7,721,217 8,190,013 ',542,020 7,250,652 Electric Customers at December 31 Residential 309,931 308,909 307,181 306,601 304,494 302,219 Commercial 30,248 30,940 30,620 30,426 29,984 ~

29,635 Industrial 1,279 1,300 1,325 1,347 1,361 1,382 Municipal and Other 2,594 2,824 2,688 2,711 2,670" 2,638 Total electric customers 344,052 343,973 341,841 341,085 338,509 Electricity Generated and 335,874',520,936 Purchased-KWH (000's)

Fossil 1,962,889 1,664,914 1,512,513 1,631.933 1,478,120 nuclear 5,323,639 5,119,544 4,094,272 4,645,646 4,527,178 4,495,457 Hydro IS9,512 227.867 248.990 171,886 218,129 I99,239 Pumped storage 232,927 238,900 246,726 237,904 247,550 233,477 Less energy for pumping (348,438) 1358.350) r3 "0.09. ) (361.144) 1371,383) (355,725)

Other 195 890 936 1.565 1,24$ 2.559 Total generated net 7,360,724 6,893,765 aa'33a340 6,327,790 6,100,839 6,095,943 Purchased 1,376,221 1.301,636 2,43";.433 2,343,484 1,998,882 1,646,244 Total electric energy 8,736.945 8.195.401 8.170.77 3 8,671274 8,099,721 7.742,187 Systenr ¹t Capabilih IAVat December 31 Fossil 526,000 526.000 529.000 529,00D 532,ODD 541,00D nuclear 638,000 638.000 63S,OOD 640,000 617,000 620,000 Hydro 47,000 4 .000 4".000 47.000 47,000 47,000 Orher 28,000 28,000 28,000 28.000 29,000 29,000 Purchased 349,000 3 $ .000 3 5,000 3 5.000 375,000 347,000 Total sysrem ner capahiliry 1.588.000 1.614.000 1.617.000 1.619,000 1,600,000 1,584.000 Net Peak Load DV 1,388,000 1.421.000 1.305.000 1,425,000 1,374,000 1,333,000 Arrnual Load Factor Net % 595 16.1 61.9 5..6 5S.S 59.1 Ri4.4)>'.49 4 is. snJ 8;<<.1:" 'Inclu4ies sales to energy marketers and bulk sales.

8 ~ <<54'rsrs<<)

GAS 'D EPARTIh E11T

. 0 STATISTICS

. ~

Year Ended December 31 1998 1997 1996 1995 1994 1993

'as Revenue (000's)'esidential S 2,944 S 5,852 S 6)010 S 4,081 '5,935 $ 5,526 Residential spaceheating 201,686 249,101 246,945 230>934 215,974 201,129 Commercial 40,196 51)893 52,073',175 51,117 49>115 46)321 Industrial 4,222 5,800 6,686 7,088 6,368 Municipal and other 25,492 23,663 35,076 ~

1,045 47,949 34,364 Total gas revenue 274,540 336,30> 346,27> 293,863 326,061 293,708 Gas Expense (000's)

Gas purchased for resale 155,497 196,579 202,297 167,762 194,390 166,884 Other operation 63,014 63,416 61,348 59,684 49,312 47,593 Maintenance 5,188 5,418 5,634 5,194 7,774 9,229 Depreciation 12,867 13;127 12,999 12,781 12,250 11)851 Taxes local, state and other 27,672 30,685 31,858 31,514 31,859 30,849

'otal gas expense 264,238 309,225314,136 276,935 29$ ,585 266,406 Operating Income before Federal Income Tax 10,302 27,084 32,143 ~

16,928 30>476 27,302 Federal income tax (92) 3,442 7,600 6,715 8,403 5.485 Operating Income from Gas Op'erations (000's) S 10,394 $ 23,642 $ 24,543 5 10,213 5 22,073 $ 21,817 Gas Operating Ratio % 81.5 78.9 77.8 79.2 77.1 76.2 Gas Saks Therms (000's)

Residential 3,599 5,773 6,455 7,167 6,535 6,871 Residential spaceheating 239i740 285,395 299,085 280,763 '283,039 295,093 Commercial 53,552 65,675 70,543 68,380 72,410 78,887 Industrial 7,828 9,334 9,560 11,420 12,030 6,079',388 Municipal 7,331 8,086 8,219 10,230 12,188 Total gas salps 309,358 ~ 372,002 393,503 374,089 383,634 405,069 Transportation of customer-owned gas 163,575 166,060 167,729 146,149 136,372 124,436 Total gas sold and transported 472,933 538,062 561,282 $ 20,238 520,006 52>,$ 05 Gas Customers at December 31 Residential 16,944 16,265 16,718 17,443 17,836 18,389 Residential spaceheating 249,684 243,264 240,685 238,267 235,313 231,937 Commercial 18,633 19,118 19,045 18,978 18,742 18,636 Industrial 778 829 857 879 905 924 Municipal 965 1,117 961 981 988 1,001 Transportation 1,900 836 744 655 558 466 Total gas customers 288,904 281,429 279,010 ~77 ~03 274,342 271,353 Gas Therms (000's)

Purchased for resale 203,677 274,430 279,353 237,728 262,267 347,778 Gas from storage 111,164 104,317 122,S43 152.852 134,802 76,378 Other 1,496 1,410 1,082 1.S00 2,959 1,039 Total gas available 316,337 380, l57 403,278 392,380 400,028 425,195 Daily Capacity- 'otal Therms at December 4,380,000 4380.000 4,4S0.000 5.230,000 5,625.000 5,625,000 daily throughput Therms ',114.290 4.022.600 3,980,000 4,735,690 3,864;850 31'aximum 3,583,500 Degree Days (Calendar vfonth)

For the period 5,666 6,916 6.998 6,535 6,699 7,044 Percent colder (warmer) than normal ((t.>1 2.8 3.9 (3.0) (0.61 4.4

'Xfethod for determining daily apacity. hosed on current nct2vor 2 m6 >s(s. re(le ms the mtr (mu m rlemm>mme>( h r>e man(m((>on 0mems can accept whhout a dcticiency.

55

IIIVESTOR I IIFORIt(ATIOII BUSINESS Ai%) FINANCIAL SHAREHOLDER SERVICES Dividend Reinvestment INFORMATION Shareholder services representatives , RG8;E offers a dividend RG8cE business and financial are available weekdays from 9 a;m. reinvestment plan as a service to information is now available on line to 6 p.m." eastern standard time Common Stock shareholders who as well as by phone. .through Boston EquiServe at- vvish to purchase additiopal shares.

(800) 736-3001. Among other In addition to full or partial RG8(:E by Phone things, they can provide dividend reinvestment of dividends, the plan Access RG8cE from anywhere in information, enroll you in our gives shareholders the opportunity to the United States or Canada by dividend reinvestment program make direct cash investments ranging calling our automated investor and handle requests for ownership from $ 50 to $ 5,000 as often as once communications system at or account changes. a month. To enroll, you need to (800) 724-8833. You will be greeted have ten shares of RG8cE Common with a brief message, then given a Stock Transfer Agent Stock and the shares have to be held menu of options. Among other BankBoston, N.A. in your name, meaning they can't be things, you can hear RG8:E's clo Boston EquiServe in a broker street name account.

quarterly earnings announcement or P.O. Box 8040 request a copy, including financial Boston, MA 02266-8040 FIRST MORTGAGE BOND statements, by fax or by mail. (800) 736-3001 TRUSTEE

. Bankers Trust Company RGBcE on Line Telecommunication Device cfo BT Services Tennessee Inc.

RG8cE's web site now features for the Deaf (TDD) Securities Payment Unit electronic versions of our annual (800) 952-9245 P.O. Box 291207

~

report and annual meeting, along Nashville, TN 37229.1207 with the latest news and financial (800) 735-7777 information, including quarterly DIVIDENDS divide'nd and earnings announce- Dividend Payment Dates ANNUALMEETING.

ments, financial statements and Dividends on Common Stock are RG8cE's 1999 annual meeting of riess releases. Visit us on line at paid quarterly around the 25th of shareholders will be held at the httpllwww.rge.corn. January, April,July and October. Hyatt Regency Rochester, on Dividends on the Preferred Stocks , Thursday, April 29, 1999 at 11 am RG8cE Financial Information are payable, as declared, on or Earnings results are typically released about the 1st of March, June, STOCK LISTINGS around the 23rd of January, April, September and December. RG8cE's Common Stock is listed on July and October. Dividend the View York Stock Exchange and is announcements are made in %larch, Dividend Diicct Deposit identified b) the stock symbol RGS.

June, September and December at Shareholders can elect to have The Preferred Stock issues are traded mid-month. their quarterly cash dividends on the over. the. counter marker.

electronically deposited into their Security Analyst Contact personal bank accounts. Deposits FORII 10-KAhNUALREPORT Security analysts and others are made on the date the dividend Shareholders may obtain a copy of requesting information about RGRE is payable. If you ivould like to RGS:E's 199S annual rcport on should contact Thomas E. dewberry, take advantage of this service, Form 10.K, as filed vvith the Director of Investor Relations at contact our stock transfer agent. Securities and Exchange (716) 724.S091. Commission, ivithout charge, by calling (800) 724.8833 or ivriting Corporate Address to Investor Services at RG8 E.

Rochester Gas and Electric Corporation S9 East Avenue Rochester, XY 14649 0001

( 16) 546.2.00

0 BOARD OF DIRECTORS AIID BFFICERS BOARD APPOINTMENT BOARD OF DIRECTORS OFFICERS (as ofJanuary I, I 999) (as ofJanuary I, 1999)

AXGELOJ. CHIARELLAt, THOSIAS S. RICHARDS Former Vice President, Chairman of the Board, President and Rochester ) Iidtown, L.L.C. Chief Executive Officer Age 55, Years of Service, 7 ALLAXE. DLGAX.~

Executive Vice President, J. BURT STozxs Business Group Operations, Senior t "tie President, Corporate Xerox Corporation Services and Chief Financial Officer Age 55, Years of Service, 3

)VIAIKB. CRIER t Executive Vice President, MICHAEL T. TOSIAIXO Financial ilanagement, Senior Vice President and The Prudential Insurance Company General Counsel of America Age 6I, Years of Service, I SUSAX R. HOLLIDAV, PAL'L C. WILKEXS President and Publisher, Senior Vice President, Generation Rochester Business Journal Age 51, Years of Service, 25 CLEVE L. KILLNGSWORTH,JR. JAV T. HOI )IES, DAVID C. HEILIGSMX Attorney and Commercial Arbitrator Vice President and Cleve L. Killingsworth, Jr. was Corporare Secretary elected to RGBLE's board of SA)IUEL T. HUBBARD,JR. tg Age58, YearsofService,35 directors in July 1998. He is Former President and Chief Executive Officer, ROBERT C. MECREDV president and chief executive officer The Ailing and Cory Company Vice Presidem, of Health Alliance Plan that serves Nuclear Operations more than a half-million customers CLEVE L. KILLIÃGSWORTH,JR.

Age 53, Years of Service, 27 in cvlichigan and northern Ohio. President and Chief Executive Officer, Mr. Killingsworth also has held Health Alliance Plan WILFREDJ. SCHROL'DER,JR.

. Vice President, senior management positions with ROGER W. KOBER Human Resources other health care organizations, Former Chairman of the Board Ag>> 57, Years of Service, 36 including the Rochester-based Blue and Chief Executive Officer, Cross and Blue Shield of Western Rochester Gas and Electric Corporation WILLLUIJ. REDDV New York. He is a graduate of Comroller CoxsTAxcE M. VIITCHELLt, il.I.T. and Yale University. Age 5 I. Years of Service, 3I Former Program Director, Industrial.'clanagement Council of .VLARI; KEoGH Rochester. Xecv York. Inc. Treasurer Age 53. Years ol'Service. 2, CoRVELIUs J. VILRPII)"g Senior Vice President. JEssicA S. RAixES Goodrich 2 Shervvood Company AuJitor Age 4I. hears ot Service. 3 CHARLES L PLossER;

, Dean.md Jc)hn al. Olin Distinguished Protessor of Economic an J Puhlic Policy of ENERGETIX, INC, the ))i illiam E. Simon Cra Jurue Schc)ol of Business Administration, Lniversiiy ot A IICHAELJ. BovAuxo Ro hester President an J Chief Executive Ofticer Age 43. Years of Service. 2 THoa )As S. RIcHARDs.

Chairntan ot the BoarJ. President anJ Chiet JOHx A. HAS IILTox Exccutiv<<0()car. Vice Preii Jem.

Rochester G.is an J Fle tric Cc)rpc)ration Operations Aye 44. Years of Service. I c'.')Icmhvr of Eve:utive anJ Flluillce Cc)nlnlcccee

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>ester Gas and Electric Corporatiou ast Aueuue, Rochester, NV 14649;0001

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