<PAGE>
 
                       SECURITIES AND EXCHANGE COMMISSION

                            WASHINGTON, D.C.  20549

                                   FORM 10-K


(Mark One)
[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
     ACT OF 1934

                 For the fiscal year ended:  December 31, 1997
                                             -----------------

                                      OR

[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

     For the transition period from _________________ to ________________

                        Commission file number:  1-672-2
                                                 -------

                     Rochester Gas and Electric Corporation
             -----------------------------------------------------
             (Exact name of registrant as specified in its charter)

                 New York                         16-0612110
     -------------------------------          -------------------
     (State or other jurisdiction of          (I.R.S. Employer
     incorporation or organization)           identification No.)

                      89 East Avenue, Rochester, NY           14649
              --------------------------------------------------------
              (Address of principal executive offices)      (Zip Code)

Registrant's telephone number, including area code:  (716) 546-2700
                                                     --------------


          Securities registered pursuant to Section 12(b) of the Act:

                                         Name of each exchange
     Title of each class                   on which registered
     -------------------                  ---------------------

     Common Stock, $5 par value          New York Stock Exchange
<PAGE>
 
                       SECURITIES AND EXCHANGE COMMISSION

                            WASHINGTON, D.C.  20549

                                   FORM 10-K


              ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
                        SECURITIES EXCHANGE ACT OF 1934


Securities registered pursuant to Section 12(g) of the Act:

     Preferred Stock, $100 par value

     4%     Series F     4.95%  Series K
     4.10%  Series H     4.55%  Series M
     4.75%  Series I
     4.10%  Series J


     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.    [X]

     On January 1, 1998 the aggregate market value of the voting stock held by
nonaffiliates of the Registrant was approximately $1,312,000,000.

     Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

     YES    X       NO  
           ---          ---   

     Indicate the number of shares outstanding of each of the registrant's
classes of common stock as of the latest practicable date.

     Common Stock, $5 par value, at January 1, 1998, 38,862,347.


     Documents Incorporated by Reference      Part of Form 10-K
     -----------------------------------      -----------------

     Definitive proxy statement in connection      III
     with annual meeting of shareholders to be
     held April 15, 1998.
<PAGE>
 
                     ROCHESTER GAS AND ELECTRIC CORPORATION

                       Information Required on Form 10-K



Item
Number      Description                                        Page
------      -----------                                        ----
 
Part I
------ 
 
Item 1      Business                                              1
Item 2      Properties                                           12
Item 3      Legal Proceedings                                    14
Item 4      Submission of Matters to a Vote of Security Holders  14
Item 4A     Executive Officers of the Registrant                 14
 
 
Part II
-------
 
Item 5      Market for the Registrant's Common Equity and
            Related Stockholder Matters                          16
Item 6      Selected Financial Data                              17
Item 7      Management's Discussion and Analysis of Financial
            Condition and Results of Operations                  20
Item 8      Financial Statements and Supplementary Data          34
Item 9      Changes in and Disagreements with Accountants on
            Accounting and Financial Disclosure                  68
 
 
Part III
--------
 
Item 10     Directors and Executive Officers of the Registrant   69
Item 11     Executive Compensation                               69
Item 12     Security Ownership of Certain Beneficial Owners and
            Management                                           69
Item 13     Certain Relationships and Related Transactions       69
 

Part IV
-------

Item 14     Exhibits, Financial Statement Schedules and 
            Reports on Form 8-K                                 70


            Signatures                                          75
<PAGE>
 
                                       1

                                     PART I

Item 1.  BUSINESS


     The following are discussed under the general heading of "Business".
Reference is made to the various other Items as applicable.

     CAPTION                                       PAGE
     -------                                       ----
 
     General                                          1
     Regulatory Matters                               2
     Electric Operations                              3
     Gas Operations                                   5
     Fuel Supply                                      6
     Financing and Capital Requirements Program       7
     Environmental Quality Control                    8
     Research and Development                         9
     Operating Statistics                            10
 
GENERAL

          Incorporated in 1904 in the State of New York, the Company supplies
electric and gas service wholly within that State.  It produces and distributes
electricity and distributes gas in parts of nine counties centering about the
City of Rochester.  At December 31, 1997 the Company had 1,958 employees.

          The Company's service area has a population of approximately one
million and is well diversified among residential, commercial and industrial
consumers. In addition to the City of Rochester, which is the third largest city
and a major industrial center in New York State, it includes a substantial
suburban area with commercial growth and a large and prosperous farming area.  A
majority of the industrial firms in the Company's service area manufacture
consumer goods.  Many of the Company's industrial customers are nationally
known, such as Xerox Corporation, Eastman Kodak Company, General Motors
Corporation, and Bausch & Lomb Incorporated.

          The business of the Company is seasonal.  With respect to electricity,
winter peak loads are attained due to spaceheating sales and shorter daylight
hours and summer peak loads are reached due to the use of air-conditioning and
other cooling equipment.  With respect to gas, the greatest sales occur in the
winter months due to spaceheating usage.  The Company also plans to enter into
unregulated businesses that will bring energy products and services to the
marketplace both within and outside the Company's franchise area.
 
          In each of the communities in which it renders service, the Company,
with minor exceptions, holds the necessary municipal franchises, none of which
contains burdensome restrictions.  The franchises are non-exclusive, and are
either unlimited as to time or run for terms of years.  The Company anticipates
renewing franchises as they expire on a basis substantially the same as at
present.

          Information concerning revenues, operating profits and identifiable
assets for significant industry segments is set forth in Note 4 of the Notes to
the Company's financial statements under Item 8.  Information relating to the
principal classes of service from which electric and gas revenues are derived
and other operating data are included herein under "Operating Statistics".  A
discussion of the causes of significant changes in revenues is presented in Item
7 - Management's Discussion and Analysis of Financial Condition and Results of
<PAGE>
 
                                       2

Operations.  Percentages of the Company's operating revenues derived from
electric and gas operations for each of the last three years are as follows:

<TABLE>
<CAPTION>
                                1997    1996   1995
                               -----   -----  -----
                  <S>         <C>     <C>     <C>
                   
                  Electric     67.6%   67.1%  71.1%
                  Gas          32.4%   32.9%  28.9%
                               -----   -----  -----
                   
                               100.0%  100.0%  100.0%
</TABLE>

          The Company is operating in a rapidly changing competitive marketplace
for electric and gas service.  This competitive environment includes a federal
and State trend toward deregulation and promotion of open-market choices for
consumers.  In November 1997 the New York State Public Service Commission (PSC)
approved a Settlement Agreement among the Company, PSC staff and other parties
which sets the framework for the introduction and development of open
competition in the electric energy marketplace in New York State over the next
five years.

          Regarding the Company's electric business, in early 1996 the Federal
Energy Regulatory Commission (FERC) issued new rules to facilitate the
development of competitive wholesale markets.  In 1997 the Company together with
other New York utilities filed with FERC a "Comprehensive Proposal to
Restructure the New York Wholesale Market" and requested approval of their
restructuring plan in early 1998.  At the State level, the PSC endorsed a
fundamental restructuring of the electric utility industry in the State in its
"Competitive Opportunities Proceeding".  The Company's Competitive Opportunities
Settlement in 1997, including its proposed retail access program called "Energy
Choice",  allows for a phase-in to open electric markets while lowering customer
prices and establishing an opportunity for competitive returns on shareholder
investments. Although the Company is just beginning to receive applications from
potential competitors under its distribution tariff, it expects more to be
filed, particularly from companies with strong retailing and customer service
capabilities and wholesale power trading expertise.

          With the unbundling of services as directed by FERC Order 636, primary
responsibility for reliable natural gas has shifted from interstate pipeline
companies to local distribution companies, such as the Company.  All gas
customers have a choice of suppliers since November 1996, subject to certain
phase-in limitations through 1998 for loss of gas commodity sales.  Some of
these companies are large, nationally known, publicly held marketers or
suppliers.  In 1997 the Company commenced negotiations with the staff of the PSC
and other parties with the objective of developing a multi-year settlement of
issues pertaining to the Company's gas business.

          See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations under the heading "Competition" for further
information on the Competitive Opportunities Settlement and the competitive
challenges the Company faces in its electric and gas business and how it is
responding to those challenges.


REGULATORY MATTERS

          The Company is subject to PSC regulation of rates, service, and sale
of securities, among other matters.  The Company is also regulated by the FERC
on a limited basis, in the areas of interstate sales and exchanges of
electricity, intrastate sales of electricity for resale, transmission wheeling
service for other utilities, and licensing of hydroelectric facilities. As a
licensee and operator of nuclear facilities, the Company is also subject to
regulation by the
<PAGE>
 
                                       3

Nuclear Regulatory Commission (NRC).  The impact of regulation is discussed
throughout this report.

          See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations under the heading "Rates and Regulatory
Matters" for summaries of recent PSC rate decisions and its flexible pricing
tariff for major industrial and commercial electric customers.


ELECTRIC OPERATIONS

          Electric System.  The total net generating capacity of the Company's
electric system is 1,239,000 Kw.  In addition the Company purchases 120,000 Kw
of firm power under contract and 35,000 Kw of non-contractual peaking power from
the New York Power Authority, 150,000 Kw of a 1,000,000 Kw pumped storage plant
owned by the Power Authority in Schoharie County, New York, 50,000 Kw of firm
power from the Power Authority's 821,000 Kw FitzPatrick Nuclear Power Plant near
Oswego, New York and 20,000 Kw of firm power from Hydro-Quebec purchased through
the Power Authority.  The Company's net peak load of 1,425,000 Kw occurred on
August 15, 1995.

          The percentages of electricity actually generated and purchased for
the years 1993-1997 are as follows:

<TABLE>
<CAPTION>
 
                                            1997    1996    1995    1994    1993
                                           ------  ------  ------  ------  ------
<S>                                        <C>     <C>     <C>     <C>     <C>
Sources of Generated Energy:
Nuclear                                     61.6%   49.4%   52.8%   55.3%   57.6%
Fossil                                      20.0    18.2    18.6    18.1    19.5
Hydro and Other                              2.7     3.0     2.0     2.7     2.6
                                           -----   -----   -----   -----   -----
  Total Generated Net                       84.3    70.6    73.4    76.1    79.7
Purchased                                   15.7    29.4    26.6    23.9    20.3
                                           -----   -----   -----   -----   -----
Total Electric Energy                      100.0%  100.0%  100.0%  100.0%  100.0%
                                           =====   =====   =====   =====   =====
</TABLE>

          The Company, six other New York utilities and the Power Authority are
members of the New York Power Pool (NYPP).  The primary purposes of the NYPP are
to coordinate inter-utility sales of bulk power, long range planning of
generation and transmission facilities, and inter-utility operating and
emergency procedures in order to better assure reliable, adequate and economic
electric service throughout the State.  For a discussion on potential changes to
the NYPP, see Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations - "FERC Open Transmission Orders and
Company filings".

          Generating Facilities.  The Company's five major generating facilities
are two nuclear units, the Ginna Nuclear Plant (Ginna Plant) and the Company's
14% share of Nine Mile Point Nuclear Plant Unit No. 2 (Nine Mile Two), and three
fossil fuel generating stations, the Russell and Beebee Stations and the
Company's 24% share of Oswego Unit Six.  In terms of capacity these comprise
39%, 13%, 20%, 7% and 15%, respectively, of the Company's current electric
generating system.
 
          On December 1, 1997 Niagara Mohawk Power Corporation (Niagara)
announced a plan to sell its fossil-fueled and hydroelectric generating stations
by auction in 1998. This plan was agreed to as part of Niagara's Power Choice
Settlement currently under review by the PSC.  The Company intends to include
its 24 percent share of Niagara's Oswego Steam Station Unit 6 (Oswego 6) for
sale as part of Niagara's auction.  Any gains or losses realized by the Company
from the sale of its share of Oswego 6 would be treated in accordance with the
terms of the Settlement under the Competitive Opportunities Proceeding.  The
Company would
<PAGE>
 
                                       4

include its share of Oswego 6 in these efforts as well. The gross and net book
cost of the Company's share of Oswego 6 as of December 31, 1997 are $99 million
and $58 million, respectively

          On January 21, 1998 the Company decided to retire Beebee Station by
mid-1999.  Factors such as the plant's age, location in an area no longer
consistent with the surrounding development, 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 will be fully depreciated at the time of
retirement. The Settlement provides that all prudently incurred incremental
costs associated with the shut down and decommissioning of the plant are
recoverable through the Company's distribution access tariff.  The electric
capability and energy currently provided by the plant is expected to be replaced
by purchased power as needed.

          Nine Mile Two, a nuclear generating unit in Oswego County, New York
with a designed capability of 1,143 megawatts (Mw) as estimated by Niagara, was
completed and entered commercial service in Spring 1988.  Niagara is operating
the Unit on behalf of all owners pursuant to a full power operating license
which the NRC issued on July 2, 1987 for a 40-year term beginning October 31,
1986. Under arrangements dating from September 1975, ownership, output and cost
of the project are shared by the Company (14%), Niagara (41%) Long Island
Lighting Company (18%), New York State Electric & Gas Corporation (18%) and
Central Hudson Gas & Electric Corporation (9%).  Under the operating Agreement,
Niagara serves as operator of Nine Mile Two, but all five cotenant owners share
certain policy, budget and managerial oversight functions.  The base term of the
Operating Agreement is 24 months from its effective date, with automatic
extension, unless terminated by written notice of one or more of the cotenant
owners to the other cotenant owners; such termination becomes effective six
months from the receipt of any such notice of termination by all the cotenant
owners receiving such notice.  The gross and net book cost of the Company's
share of Nine Mile Two including $374 million of disallowed costs previously
written off, as of December 31, 1997 are $879 million and $399 million,
respectively.

          The Company's Ginna Plant, which has been in commercial operation
since July 1, 1970, provides 480 Mw of the Company's electric generating
capacity.  In August 1991 the NRC approved the Company's application for
amendment to extend the Ginna Plant operating license expiration date from April
25, 2006 to September 18, 2009.

          The gross and net book cost of the Ginna Plant as of December 31, 1997
are $560 million and $309 million, respectively.  From time to time the NRC
issues directives requiring all or a certain group of reactor licensees to
perform analyses as to their ability to meet specified criteria, guidelines or
operating objectives and where necessary to modify facilities, systems or
procedures to conform thereto.  Typically,  these directives are premised on the
NRC's obligation to protect the public health and safety.  The Company reviews
such directives and implements a variety of modifications based on these
directives and resulting analyses.  Expenditures at the Ginna Plant, including
the cost of these modifications, are estimated to be $10.1 million, $10.4
million and $6.4 million for the years 1998, 1999 and 2000, respectively, and
are included in the capital expenditure amounts presented under Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations.

          The Company has four licensed hydroelectric generating stations with
an aggregate capability of 47 megawatts.  Although applications for renewal of
those licenses were timely made in 1991, the FERC was unable to complete
processing of many such applications by the December 31, 1993 license
expiration.  The FERC, therefore, issued annual licenses that essentially extend
the terms of the old licenses year-to year until processing of the new ones can
be completed.  The
<PAGE>
 
                                       5

Company received final licenses for Stations 2 and 5 in February of 1996.  The
license for Station 26 was received in October, 1997.  Overly stringent
environmental conditions, governmental requirements and high property taxes have
nullified the economic viability of the fourth station, number 160 (less than
one megawatt net capacity).  It will not be relicensed.

          Joint Nuclear Operating Company.  See Item 7 - Management's Discussion
and Analysis of Financial Condition and Results of Operations under Competition
-Nuclear Operating Company regarding formation of a joint nuclear operating
company to support and manage the operations of nuclear plants in New York State
including Nine Mile Two and the Company's Ginna Plant described below.

          Insurance. The Price-Anderson Act establishes a federal program
insuring against public liability in the event of a nuclear accident at a
licensed U.S. reactor.  Under the program, claims would first be met by
insurance which licensees are required to carry in the maximum amount available
(currently $200 million).  If claims exceed that amount, licensees are subject
to a retrospective assessment up to $79.3 million per licensed facility for each
nuclear incident, payable at a rate not to exceed $10 million per year.  Those
assessments are subject to periodic inflation-indexing and a surcharge for New
York State premium taxes.  The Company's interests in two nuclear units could
thus expose it to a potential liability for each accident of $90.4 million
through retrospective assessments of $11.4 million per year in the event of a
sufficiently serious nuclear accident at its own or another U.S. commercial
nuclear reactor.

          As a licensee of a commercial nuclear power plant in the United
States, the Company is required to have and maintain financial protection to
cover radiation injury claims of certain nuclear workers.  The Company purchases
primary insurance to meet this requirement.  On January 1, 1998, a new insurance
policy was issued that applies to claims first reported on or after January 1,
1998. This policy has a limit of $200 million (reinstated annually if certain
conditions are met) for radiation injury claims against the Company, or against
other licensees who are insured by this policy.  If these claims exceed the $200
million limit of primary coverage, the provisions of the Price-Anderson Act
(discussed above) would apply.  Since reserves for outstanding claims under
former policies could be insufficient and certain claims may still be made under
former policies due to a discovery period, the Company could be assessed under
these former policies along with the other policyholders.  The Company's share
could be up to $3.0 million in any one year.

          The Company is a member of Nuclear Electric Insurance Limited, which
provides insurance coverage for the cost of replacement power during certain
prolonged accidental outages of nuclear generating units and coverage for
property losses in excess of $500 million at nuclear generating units.  If an
insuring program's losses exceeded its other resources available to pay claims,
the Company could be subject to maximum assessments in any one policy year of
approximately $3.0 million and $10.9 million in the event of losses under the
replacement power and property damage coverages, respectively.


GAS OPERATIONS

          As of December 31, 1997 the Company's daily city gate resource
capability is 4,380,000 therms and its daily contracted transportation capacity
is 4,080,000 therms (where one Therm is equivalent to 100,000 British Thermal
Units).  The Company optimizes its assets by contracting for gas resources that
align with its system requirements.  The Company experienced on January 19,
1994, its maximum daily throughput of approximately 4,740,000 therms, (3,910,000
therms sold to retail customers and 830,000 therms delivered for transportation
customers).

          The Company purchases all of its required gas supply from numerous
marketers and producers under contracts containing various terms and conditions.
<PAGE>
 
                                       6

See Item 7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations under the caption "Energy Management and Costs - Gas" for
a discussion of that topic.

          The Company continues to provide new and additional gas service.  Of
243,264 residential gas spaceheating customers at December 31, 1997, 2,579 were
added during 1997.

          Approximately 31% of the gas delivered to customers by the Company
during 1997 was purchased directly by commercial, industrial and municipal
customers from brokers, producers and pipelines.  The Company provided the
transportation of gas on its system to these customers' premises.


FUEL SUPPLY

          Nuclear.  Generally, the nuclear fuel cycle consists of the following:
(1) the procurement of uranium concentrate (yellowcake), (2) the conversion of
uranium concentrate to uranium hexafluoride, (3) the enrichment of the uranium
hexafluoride, (4) the fabrication of fuel assemblies, (5) the utilization of the
nuclear fuel in generating station reactors and (6) the appropriate storage or
disposition of spent fuel and radioactive wastes.  Arrangements for nuclear fuel
materials and services for the Ginna Plant and Nine Mile Two have been made to
permit operation of the units through the years indicated:

<TABLE>
<CAPTION>
                                   Ginna Plant            Nine Mile Two/(1)/
                                   -----------            ------------------
         <S>                       <C>                    <C>       
         Uranium Concentrate         2000/(3)/                 2002/(2)/
         Conversion                  2000/(4)/                 2002/(2)/
         Enrichment                   (5)                       (6)
         Fabrication                 2001                      2003
</TABLE>

(1)  Information was supplied by Niagara Mohawk Power Corporation.

(2)  Arrangements have been made for procuring the majority of the uranium and
     conversion requirements through 2002, leaving the remaining portion of the
     requirements uncommitted.

(3)  The Company has a contract under which it may procure up to 80 percent of
     the annual Ginna Plant uranium requirements.  A second contract is in place
     to supply about 30% of the annual requirements for 1998 through 1999, and
     100% of requirements in 2000.  The remaining requirements are uncommitted.

(4)  Seventy percent of the conversion requirements have been procured through
     1997 under one contract.  A second contract is in place covering 70% of
     requirements in 1998 and 1999,  and 100% in 2000.  Twenty percent of
     requirements for 1998 are covered by a contract for delivery of UF6
     (uranium plus conversion).  Ten percent of requirements for 1998 will be
     filled from inventory.

(5)  The Company has a contract with United States Enrichment Corporation (USEC)
     for nuclear fuel enrichment services which assures provision of 70% of the
     Ginna Plant's requirements through 1999.  A second enrichment contract is
     in place which assures 30% of the Ginna Plant's requirements through 1999
     and 100% of requirements in 2000 and 2001.

(6)  Nine Mile Two is covered for 100% of requirements through 1998 and for 75%
     (with an option to increase to 100%) from 1999 through 2003.
<PAGE>
 
                                       7

          With appropriate lead times, the Company will pursue arrangements for
the supply of uranium requirements and related services beyond those years for
which arrangements have been made as shown above.

          The average annual cost of nuclear fuel per million BTU used for
electric generation for the last five years is as follows:

<TABLE>
<CAPTION>
                                 1997   1996   1995   1994   1993         
                                 -----  -----  -----  -----  -----        
          <S>                    <C>    <C>    <C>    <C>    <C>          
                                                                          
          Ginna Plant            $.461  $.424  $.410  $.403  $.400        
          Nine Mile Two          $.485  $.512  $.503  $.481  $.515         
</TABLE>

          See Note 10 of the Notes to Financial Statements under Item 8 for
additional information regarding nuclear fuel disposal costs, nuclear plant
decommissioning and DOE uranium enrichment facility decontamination and
decommissioning.

          Coal. The Company's 1998 coal requirements are expected to be
approximately 800,000 tons.  In 1997 100% of its requirements were purchased
under contract. To meet the additional coal burn requirements and meet its
current reserve supply of coal ranging from 30-60 days supply at maximum burn
rates, it is anticipated that the Company will purchase spot market coal to
supplement it contract supply.

          The sulfur content of the coal utilized in the Company's existing
coal-fired facilities ranges from 1.0 to 1.9 pounds per million BTU.  Under
existing New York State regulations, the Company's coal-fired facilities may not
burn coal which exceeds 2.5 pounds per million BTU, and must average no higher
than 1.7 pounds per million BTU over a 12-month period or 1.9 pounds per million
BTU over a three-month period.

          The average annual delivered cost of coal used for electric
generation was as follows:

<TABLE>
<CAPTION>
                                 1997   1996   1995   1994   1993         
                                 -----  -----  -----  -----  -----        
          <S>                    <C>    <C>    <C>    <C>    <C>          

          Per Million BTU        $1.34  $1.34  $1.31  $1.38  $1.42
</TABLE>


FINANCING AND CAPITAL REQUIREMENTS PROGRAM

          A discussion of the Company's capital requirements, financial
objectives and the resources available to meet such requirements may be found in
Item 7 - Management's Discussion and Analysis of Financial Condition and Results
of Operations.  The sale of additional securities depends on regulatory approval
and the Company's ability to meet certain requirements contained in its mortgage
and Restated Certificate of Incorporation.

          Under the New York State Public Service Law, the Company is required
to secure authorization from the Public Service Commission of the State of New
York (PSC) prior to issuance of any stock or any debt having a maturity of more
than one year.

          The Company's First Mortgage Bonds are issued under a General Mortgage
dated September 1, 1918, between the Company and Bankers Trust Company, as
Trustee, which has been amended and supplemented by thirty-nine supplemental
indentures.  Before additional First Mortgage Bonds are issued, the following
financial requirements must be satisfied:
<PAGE>
 
                                       8

(a)  The First Mortgage prohibits the issuance of additional First Mortgage
     Bonds unless earnings (as defined) for a period of twelve months ending not
     earlier than sixty days prior to the issue date of the additional bonds are
     at least 2.00 times the annual interest charges on First Mortgage Bonds,
     both those outstanding and those proposed to be outstanding.  The ratio
     under this test for the twelve months ended December 31, 1997 was 6.99.

(b)  The First Mortgage also provides that, if additional First Mortgage Bonds
     are being issued on the basis of property additions (as defined), the
     principal amount of the bonds may not exceed 60% of available property
     additions.  As of December 31, 1997 the amount of additional First Mortgage
     Bonds which could be issued on that basis was approximately $398,393,000.
     In addition to issuance on the basis of property additions, First Mortgage
     Bonds may be issued on the basis of 100% of the principal amount of other
     First Mortgage Bonds which have been redeemed, paid at maturity, or
     otherwise reacquired by the Company.  As of December 31, 1997, the Company
     could issue $321,669,000 of Bonds against Bonds that have matured or been
     redeemed.

     The Company's Restated Certificate of Incorporation (Charter) provides
that, without consent by two-thirds of the votes entitled to be cast by the
preferred stockholders, the Company may not issue additional preferred stock
unless in a 12-month period within the preceding 15 months:  (a) net earnings
applicable to payment of dividends on preferred stock, after taxes, have been at
least 2.00 times the annual dividend requirements on preferred stock, including
the shares both outstanding and proposed to be issued, and (b) net earnings
available for interest on indebtedness, after taxes, have been at least 1.50
times the annual interest requirements on indebtedness and annual dividend
requirements on preferred stock, including the shares both outstanding and
proposed to be issued.  For the twelve months ended December 31, 1997, the
coverage ratio under (b) above (the more restrictive provision) was 2.83.

     For information with respect to short-term borrowing arrangements and
limitations see Item 8, Note 9 - Short-Term Debt.

     The Company's Charter does not contain any financial tests for the issuance
of preference or common stock.

     The Company's securities ratings at December 31, 1997 were:

<TABLE>
<CAPTION>
                                       First
                                      Mortgage  Preferred
                                       Bonds      Stock
                                      --------  ---------
     <S>                              <C>       <C>
 
     Standard & Poor's Corporation      BBB+       BBB
     Moody's Investors Service          Baa1       baa2
     Duff & Phelps                      BBB+       BBB
</TABLE>

     The securities ratings set forth in the table are subject to revision
and/or withdrawal at any time by the respective rating organizations and should
not be considered a recommendation to buy, sell or hold securities of the
Company.


ENVIRONMENTAL QUALITY CONTROL

     Operations at the Company's facilities are subject to various federal,
state and local environmental standards.  To assure the Company's compliance
with these requirements, the Company expended approximately $0.6 million on a
variety of projects and facility additions during 1997.
<PAGE>
 
                                       9

     The federal Low Level Radioactive Waste Policy Act (Act), as amended in
1985, provides for states to join compacts or individually develop their own low
level radioactive waste disposal sites.  The Company can provide no assurance as
to what disposal arrangements, if any, New York will have in place.  The State
has not passed legislation that would designate a site for the disposal of low
level radioactive waste.  The Company has interim storage capacity at the Ginna
Plant through 2002.  Efforts are being pursued to extend storage capacity beyond
2002, if necessary, at this plant.  A low level radioactive waste management and
contingency plan is currently ongoing to provide assurance that Nine Mile Two
will be properly prepared to handle interim storage of low level radioactive
waste for the next ten years and beyond, if necessary.

     The Company has wastewater discharge permits from NYSDEC for its Ginna,
Beebee and Russell Stations, which were renewed in July 1997, February 1994, and
June 1994, respectively.  These permits are each effective for a period of five
years.  Consistent with these permits, no significant changes to the wastewater
discharge treatment systems are currently required, nor anticipated.

     The Company believes that additional expenditures and costs made necessary
by mandated environmental protection programs will be fully allowable for
ratemaking purposes under cost of service rate regulation.  Capital expenditures
for meeting various federal, State and local environmental standards are
estimated to be $9 million for the year 1998, $2 million for the year 1999 and
$1 million for the year 2000.  These expenditures are included under Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations, in the table entitled "Capital Requirements".

     See Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations and Item 8, Note 10 - Commitments and Other Matters,
with respect to other environmental matters.


RESEARCH AND DEVELOPMENT

     The Company's research activities are designed to improve existing energy
technologies and to develop new technologies for the production, distribution,
utilization and conservation of energy while preserving environmental quality.
Research and development expenditures in 1997, 1996 and 1995 were $4.5 million,
$4.9 million, and $5.2 million, respectively.  These expenditures represent the
Company's contribution to research administered by Electric Power Research
Institute,  Empire State Electric Energy Research Corporation and an assessment
for state government sponsored research by the New York State Energy Research
and Development Authority, as well as internal research projects.
<PAGE>
 
                                       10

Electric Department Statistics

<TABLE>
<CAPTION>
 
Year Ended December 31                                1997         1996*         1995*         1994*         1993*          1992
                                                  ------------  ------------  ------------  ------------  ------------  -----------
<S>                                               <C>           <C>           <C>           <C>           <C>           <C>       
Electric Revenue (000's)   
Residential                                        $  252,464    $  254,885    $  256,294    $  243,961    $  234,866    $  222,210
Commercial                                            210,643       215,763       215,696       206,545       196,100       187,262
Industrial                                            144,305       153,337       157,464       150,372       148,084       141,507
Municipal and Other                                    72,061        66,898        67,128        57,270        59,905        57,288
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Electric revenue from our customers                   679,473       690,883       696,582       658,148       638,955       608,267
Other electric utilities                               20,856        16,885        25,883        16,605        16,361        25,541 
                                                   ----------    ----------    ----------    ----------    ----------    ----------
    Total electric revenue                            700,329       707,768       722,465       674,753       655,316       633,808
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Electric Expense (000's)   
Fuel used in electric generation                       47,665        40,938        44,190        44,961        45,871        48,376
Purchased electricity                                  28,347        46,484        54,167        37,002        31,563        29,706
Other operation                                       205,058       204,746       199,524       192,360       192,749       183,118
Maintenance                                            41,217        41,429        44,032        47,295        52,464        53,714
Depreciation and amortization                         103,395        92,615        78,812        75,211        72,326        73,213
Taxes - local, state and other                         91,111        95,010       102,380        97,919        96,043        94,841
                                                   ----------    ----------    ----------    ----------    ----------    ----------
    Total electric expense                            516,793       521,222       523,105       494,748       491,016       482,968
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Operating Income before    
    Federal Income Tax                                183,536       186,546       199,360       180,005       164,300       150,840
Federal income tax                                     61,837        61,901        59,500        52,842        43,845        38,046
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Operating Income from      
    Electric Operations (000's)                    $  121,699    $  124,645    $  139,860    $  127,163    $  120,455    $  112,794
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Electric Operating Ratio %                               46.0          47.1          47.3          47.7          49.2          49.7
Electric Sales - KWH (000's)                   
Residential                                         2,139,064     2,132,902     2,144,718     2,117,168     2,123,277     2,084,705
Commercial                                          2,118,991     2,061,625     2,064,813     2,028,611     1,986,100     1,938,173
Industrial                                          2,010,613     2,010,963     1,964,975     1,860,833     1,892,700     1,929,720
Municipal and Other                                   537,051       520,885       531,311       513,675       504,987       503,388
                                                   ----------    ----------    ----------    ----------    ----------    ----------
    Total customer sales                            6,805,719     6,726,375     6,705,817     6,520,287     6,507,064     6,455,986
Other electric utilities                            1,218,794       994,842     1,484,196     1,021,733       743,588     1,062,738
                                                   ----------    ----------    ----------    ----------    ----------    ----------
    Total electric sales                            8,024,513     7,721,217     8,190,013     7,542,020     7,250,652     7,518,724
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Electric Customers at December 31               
Residential                                           308,909       307,181       306,601       304,494       302,219       300,344
Commercial                                             30,940        30,620        30,426        29,984        29,635        29,339
Industrial                                              1,300         1,325         1,347         1,361         1,382         1,386
Municipal and Other                                     2,824         2,688         2,711         2,670         2,638         2,605
                                                   ----------    ----------    ----------    ----------    ----------    ----------
    Total electric customers                          343,973       341,841       341,085       338,509       335,874       333,674
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Electricity Generated and  
    Purchased - KWH (000's) 
Fossil                                              1,664,914     1,512,513     1,631,933     1,478,120     1,520,936     2,197,757
Nuclear                                             5,119,544     4,094,272     4,645,646     4,527,178     4,495,457     4,191,035
Hydro                                                 227,867       248,990       171,886       218,129       199,239       278,318
Pumped storage                                        238,900       246,726       237,904       247,550       233,477       226,391
Less energy for pumping                              (358,350)     (370,097)     (361,144)     (371,383)     (355,725)     (344,245)
Other                                                     890           936         1,565         1,245         2,559           811
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Total generated - net                               6,893,765     5,733,340     6,327,790     6,100,839     6,095,943     6,550,067
Purchased                                           1,301,636     2,437,433     2,343,484     1,998,882     1,646,244     1,389,875
                                                   ----------    ----------    ----------    ----------    ----------    ----------
    Total electric energy                           8,195,401     8,170,773     8,671,274     8,099,721     7,742,187     7,939,942
                                                   ----------    ----------    ----------    ----------    ----------    ----------
System Net Capability -    
    KW at December 31          
Fossil                                                526,000       529,000       529,000       532,000       541,000       541,000
Nuclear                                               638,000       638,000       640,000       617,000       620,000       617,000
Hydro                                                  47,000        47,000        47,000        47,000        47,000        47,000
Other                                                  28,000        28,000        28,000        29,000        29,000        29,000
Purchased                                             375,000       375,000       375,000       375,000       347,000       348,000
                                                   ----------    ----------    ----------    ----------    ----------    ----------
    Total system net capability                     1,614,000     1,617,000     1,619,000     1,600,000     1,584,000     1,582,000
                                                   ----------    ----------    ----------    ----------    ----------    ----------
Net Peak Load - KW                                  1,421,000     1,305,000     1,425,000     1,374,000     1,333,000     1,252,000
Annual Load Factor - Net %                               56.1          61.9          57.6          58.8          59.1          62.5
</TABLE>
* Reclassified for comparative purposes.
<PAGE>
 
                                       11

Gas Department Statistics

<TABLE>
<CAPTION>
 
Year Ended December 31                              1997         1996*        1995*        1994*        1993*        1992
                                                 -----------  -----------  -----------  -----------  -----------  ----------
<S>                                              <C>          <C>          <C>          <C>          <C>          <C>
Gas Revenue (000's)
Residential                                       $    5,852  $    6,010   $    4,081   $    5,935   $    5,526   $    6,456
Residential spaceheating                             249,101     246,945      230,934      215,974      201,129      186,710
Commercial                                            51,893      52,073       51,117       49,115       46,321       44,395
Industrial                                             5,800       6,175        6,686        7,088        6,368        6,284
Municipal and other                                   23,663      35,076        1,045       47,949       34,364       17,879
                                                  ----------  ----------   ----------   ----------   ----------   ----------
     Total gas revenue                               336,309     346,279      293,863      326,061      293,708      261,724
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Gas Expense (000's)
Gas purchased for resale                             196,579     202,297      167,762      194,390      166,884      141,291
Other operation                                       63,416      61,348       59,684       49,312       47,593       43,506
Maintenance                                            5,418       5,634        5,194        7,774        9,229        9,006
Depreciation                                          13,127      12,999       12,781       12,250       11,851       11,815
Taxes - local, state and other                        30,685      31,858       31,514       31,859       30,849       29,411
                                                  ----------  ----------   ----------   ----------   ----------   ----------
     Total gas expense                               309,225     314,136      276,935      295,585      266,406      235,029
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Operating Income before
     Federal Income Tax                               27,084      32,143       16,928       30,476       27,302       26,695
Federal income tax                                     3,442       7,600        6,715        8,403        5,485        5,545
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Operating Income from
     Gas Operations (000's)                       $   23,642  $   24,543   $   10,213   $   22,073   $   21,817   $   21,150
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Gas Operating Ratio %                                   78.9        77.8         79.2         77.1         76.2         74.1
 
Gas Sales - Therms (000's)
Residential                                            5,773       6,455        7,167        6,535        6,871        8,780
Residential spaceheating                             285,395     299,085      280,763      283,039      295,093      287,623
Commercial                                            65,675      70,543       68,380       72,410       78,887       78,996
Industrial                                             7,828       9,334        9,560       11,420       12,030       12,438
Municipal                                              7,331       8,086        8,219       10,230       12,188       11,410
                                                  ----------  ----------   ----------   ----------   ----------   ----------
 
     Total gas sales                                 372,002     393,503      374,089      383,634      405,069      399,247
Transportation of customer-owned gas                 166,060     167,779      146,149      136,372      124,436      126,140
                                                  ----------  ----------   ----------   ----------   ----------   ----------
     Total gas sold and transported                  538,062     561,282      520,238      520,006      529,505      525,387
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Gas Customers at December 31
Residential                                           16,265      16,718       17,443       17,836       18,389       19,114
Residential spaceheating                             243,264     240,685      238,267      235,313      231,937      228,096
Commercial                                            19,118      19,045       18,978       18,742       18,636       18,378
Industrial                                               829         857          879          905          924          932
Municipal                                              1,117         961          981          988        1,001        1,010
Transportation                                           836         744          655          558          466          424
                                                  ----------  ----------   ----------   ----------   ----------   ----------
    Total gas customers                              281,429     279,010      277,203      274,342      271,353      267,954
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Gas - Therms (000's)
Purchased for resale                                 274,430     279,353      237,728      262,267      347,778      360,493
Gas from storage                                     104,317     122,843      152,852      134,802       76,378       53,757
Other                                                  1,410       1,082        1,800        2,959        1,039        1,061
                                                  ----------  ----------   ----------   ----------   ----------   ----------
     Total gas available                             380,157     403,278      392,380      400,028      425,195      415,311
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Cost of gas per therm                             51.70(cent) 52.30(cent)  45.80(cent)  50.00(cent)  36.79(cent)  35.35(cent) 
Total Daily Capacity -
     Therms at December 31**                       4,380,000   4,480,000    5,230,000    5,625,000    5,625,000    4,485,000
                                                  ----------  ----------   ----------   ----------   ----------   ----------
Maximum daily throughput - Therms                  4,114,290   4,022,600    3,980,000    4,735,690    3,864,850    3,768,470
Degree Days (Calendar Month)
For the period                                         6,921       6,998        6,535        6,699        7,044        6,981
Percent colder (warmer) than normal                      2.8         3.9         (3.0)        (0.6)         4.4          3.4
</TABLE>

 * Reclassified for comparative purposes.

** Method for determining daily capacity, based on current network analysis,
   reflects the maximum demand which the transmission systems can accept
   without a deficiency.
<PAGE>
 
                                       12

Item 2.   PROPERTIES


ELECTRIC PROPERTIES

          The net capability of the Company's electric generating plants in
operation as of December 31, 1997  the net generation of each plant for the year
ended December 31, 1997, and the year each plant was placed in service are as
set forth below:

<TABLE>
<CAPTION>
 
Electric Generating Plants
 
                                                                        Net
                                           Year Unit       Net      Generation
                                           Placed in    Capability   thousands
                            Type of Fuel    Service        (Mw)        (kwh)
                            ------------   ---------    ----------  ----------
<S>                         <C>            <C>          <C>         <C> 
Beebee Station                                                          
  (Steam)                       Coal          1959          80         418,139
                                                                    
Beebee Station                                                      
  (Gas Turbine)                 Oil           1969          14             425
                                                                    
Russell Station                                                     
  (Steam)                       Coal        1949-1957      257       1,237,958
                                                                    
Ginna Station                                                       
  (Steam)                       Nuclear       1970         480       3,894,652
                                                                    
Oswego Unit 6/(1)/                                                  
  (Steam)                       Oil           1980         189           8,817
                                                                    
Nine Mile Point                                                     
  Unit No. 2/(2)/                                                   
  (Steam)                       Nuclear       1988         158       1,224,892
                                                                    
Station No. 9                                                       
  (Gas Turbine)                 Gas           1969          14             465
                                                                    
Station 5                                                           
  (Hydro)                       Water         1917          39         173,487
                                                                    
5 Other Stations                                                    
  (Hydro)                       Water      1906-1960         8          54,380
                                                      --------        ---------
                                                                     7,013,215
Pumped Storage /(3)/                                                   238,900
Less: energy for pumping                                              (358,350)
                                                                     ---------
                                                         1,239       6,893,765
                                                      ========       =========
</TABLE>

(1)  Represents 24% share of jointly-owned facility.
(2)  Represents 14% share of jointly-owned facility.
(3)  Owned and operated by the Power Authority.
<PAGE>
 
                                       13

          The Company owns 147 distribution substations having an aggregate
rated transformer capacity of 2,149,754 Kva, of which 138, having an aggregate
rated capacity of 1,970,588 Kva, were located on lands owned in fee, and nine of
which, having an aggregate rated capacity of 179,166 Kva, were located on land
under easements, leases or license agreements.  The Company also has 72,881 line
transformers with a capacity of 2,903,304 Kva.  The Company also owns 24
transmission substations having an aggregate rated capacity of 3,052,017 Kva of
which 23, having an aggregate rated capacity of 2,977,350 Kva, were located on
land owned in fee and one, having a rated capacity of 74,667 Kva, was located on
land under easements.  The Company's transmission system consists of
approximately 716 circuit miles of overhead lines and approximately 400 circuit
miles of underground lines.  The distribution system consists of approximately
16,262 circuit miles of overhead lines, approximately 3,857 circuit miles of
underground lines and 353,220 installed meters.  The electric transmission and
distribution system is entirely interconnected and, in the central portion of
the City of Rochester, is underground.  The electric system of the Company is
directly interconnected with other electric utility systems in New York and
indirectly interconnected  with most of the electric utility systems in the
United States and Canada.  (See Item 1 - Business, "Electric Operations".)


GAS PROPERTIES

          The gas distribution systems consists of 4,257 miles of gas mains and
292,392 installed meters.  (See Item 1 - Business, "Gas Operations" and "Gas
Department Statistics".)


OTHER PROPERTIES

          The Company owns a ten-story office building centrally located in
Rochester and other structures and property.  The Company also leases
approximately 475,000 square feet of facilities for administrative offices and
operating activities in the Rochester area.

          The Company has good title in fee, with minor exceptions, to its
principal plants and important units, except rights of way and flowage rights,
subject to restrictions, reservations, rights of way, leases, easements,
covenants, contracts, similar encumbrances and minor defects of a character
common to properties of the size and nature of those of the Company.  The
electric and gas transmission and distribution lines and mains are located in
part in or upon public streets and highways and in part on private property,
either pursuant to easements granted by the apparent owner containing in some
instances removal and relocation provisions and time limitations, or without
easements but without objection of the owners.  The First Mortgage securing the
Company's outstanding bonds is a first lien on substantially all the property
owned by the Company (except cash and accounts receivable).  A mortgage securing
the Company's revolving credit agreement is also a lien on substantially all the
property owned by the Company (except cash and accounts receivable) subject and
subordinate to the lien of the First Mortgage.  The Company has credit
agreements with a domestic bank under which short-term borrowings are secured by
the Company's accounts receivable.
<PAGE>
 
                                       14

Item 3.   LEGAL PROCEEDINGS


          See Item 8, Note 10 - Commitments and Other Matters.


Item 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS


          There were no matters submitted to a vote of security holders during
the fourth quarter of the fiscal year ended December 31, 1997.


Item 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT

                                                                        
                     Age   Positions, Offices and Business Experience   
Name               1/1/98               1993 to date                    
----               ------  --------------------------------------------  
                         
                         
Thomas S. Richards   54    Chairman of the Board, President and Chief
                           Executive Officer - January 1998 to date.
                         
                           President and Chief Operating Officer - March   
                           1996 to December 1997.
                         
                           Senior Vice President, Energy Services -
                           August 1995 to March 1996.
                         
                           Senior Vice President, Corporate Services and General
                           Counsel - August, 1994 to August 1995.
                         
                           Senior Vice President, Finance and General Counsel -
                           October 1993 to August, 1994.
                         
                           General Counsel - January, 1993 to October, 1993.
                         
Michael J. Bovalino  42    President, Energetix, Inc (a wholly owned subsidiary
                           of the Company) January 1998 to date.
                         
                           Senior Vice President, Energy Services - January 1997
                           to December 1997.
                         
                           Vice President, Retail Services for Plum Street
                           Enterprises (a wholly owned subsidiary of Niagara
                           Mohawk Power Corporation, 300 Erie Boulevard West,
                           Syracuse, NY 13202) prior to joining the Company.
                         
Robert E. Smith      60    Senior Vice President, Energy Operations - August
                           1995 to date.
                         
                           Senior Vice President, Customer Operations - August,
                           1994 to August, 1995.
                         
                           Senior Vice President, Production and Engineering -
                           1993 to August, 1994.
<PAGE>
 
                                       15

                     Age   Positions, Offices and Business Experience   
Name               1/1/98               1993 to date                    
----               ------  -------------------------------------------

J. Burt Stokes       54    Senior Vice President, Corporate Services and Chief
                           Financial Officer - January 1, 1996 to date.

                           Chief Financial Officer and acting Chief Executive
                           Officer for General Railway Signal Corporation, 150
                           Sawgrass Dr., Rochester, NY 14692 prior to joining
                           the Company.

Michael T. Tomaino   60    Senior Vice President and General Counsel - October,
                           1997 to Date.

                           Vice President, General Counsel and Secretary
                           for Goulds Pumps, Inc., 300 Willowbrook Office Park,
                           Fairport, NY 14450 prior to joining the Company.

William J. Reddy     50    Controller - May, 1997 to Date.

                           Group Manager, Public Affairs Services - January
                           1995 to April 1997.

                           Division Manager, Public Affairs Services - October
                           1994 to January 1995.

                           Department Manager, Forecasts and Budgets -
                           1993 to September 1994.

     The term of office of each officer extends to the meeting of the Board of
Directors following the next annual meeting of shareholders and until his or her
successor is elected and qualifies.
<PAGE>
 
                                       16

                                    PART II

Item 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
         MATTERS

COMMON STOCK AND DIVIDENDS

<TABLE>
<CAPTION>
------------------------------------------------------    --------------------------------------------------
Earnings/Dividends            1997     1996     1995      Shares/Shareholders          1997    1996    1995
------------------           -------  -------  -------    -------------------         ------  ------  ------
<S>                          <C>      <C>      <C>        <C>                         <C>     <C>     <C>
Earnings per share                                        Number of shares (000's) 
  - basic                    $  2.30  $  2.32  $  1.69    Weighted average - basic    38,853  38,762  38,113
  - diluted                  $  2.30  $  2.32  $  1.69                     - diluted  38,909  38,762  38,113
Dividends paid                                            Actual number at
 per share                   $  1.80  $  1.80  $  1.80      December 31               38,862  38,851  38,453
                                                          Number of shareholders                                  
                                                            at December 31            31,337  33,675  35,356 
------------------------------------------------------    --------------------------------------------------
</TABLE>

TAX STATUS OF CASH DIVIDENDS

   Cash dividends paid in 1997, 1996 and 1995 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 1998, the Company paid a
cash dividend of $.45 per share on its Common Stock. The January 1998 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".

<TABLE>
<CAPTION>
 
Common Stock - Price Range      1997        1996       1995
--------------------------    --------     ------     ------
<S>                           <C>          <C>        <C>
                                                  
 High                                             
    1st quarter                20  3/8     23 3/4     23
    2nd quarter                21  7/16    21 7/8     22 5/8
    3rd quarter                24 15/16    21 3/8     24 1/8
    4th quarter                34  1/2     19 5/8     24 1/8
                                                  
 Low                                              
    1st quarter                18  7/8     21 1/4     20 3/8
    2nd quarter                18          19 7/8     20 1/8
    3rd quarter                20  5/8     18         20           
    4th quarter                23  3/4     17 7/8     22 3/8
                                                  
 At December 31                34          19 1/8     22 5/8
</TABLE>
<PAGE>
 
                                       17

ITEM 6 - SELECTED FINANCIAL DATA

CONSOLIDATED SUMMARY OF OPERATIONS

<TABLE>
<CAPTION>
(Thousands of Dollars)               Year Ended December 31       1997                1996*         1995*         1994*
--------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>                 <C>           <C>           <C>
Operating Revenues
  Electric                                                       $679,473            $690,883      $696,582      $658,148
  Gas                                                             336,309             346,279       293,863       326,061
                                                              ------------        ------------  ------------  ------------
                                                                1,015,782           1,037,162       990,445       984,209
  Electric sales to other utilities                                20,856              16,885        25,883        16,605
                                                              ------------        ------------  ------------  ------------

      Total Operating Revenues                                  1,036,638           1,054,047     1,016,328     1,000,814

Operating Expenses
  Fuel Expenses
    Fuel for electric generation                                   47,665              40,938        44,190        44,961
    Purchased electricity                                          28,347              46,484        54,167        37,002
    Gas purchased for resale                                      196,579             202,297       167,762       194,390
                                                              ------------        ------------  ------------  ------------

      Total Fuel Expenses                                         272,591             289,719       266,119       276,353
                                                              ------------        ------------  ------------  ------------

Operating Revenues Less Fuel Expenses                             764,047             764,328       750,209       724,461

  Other Operating Expenses
    Operations excluding fuel expenses                            268,474             266,094       259,207       241,672
    Maintenance                                                    46,635              47,063        49,226        55,069
    Depreciation and amortization                                 116,522             105,614        91,593        87,461
    Taxes - local, state and other                                121,796             126,868       133,895       129,778
    Federal income tax - current                                   69,812              65,757        65,368        35,658
                       - deferred                                  (4,533)              3,744           847        25,587
                                                              ------------        ------------  ------------  ------------

      Total Other Operating Expenses                              618,706             615,140       600,136       575,225
                                                              ------------        ------------  ------------  ------------

Operating Income                                                  145,341             149,188       150,073       149,236

Other (Income) and Deductions
  Allowance for other funds used during
    construction                                                     (351)               (684)         (585)         (396)
  Federal income tax                                               (3,704)             (3,450)      (16,948)      (16,259)
  Regulatory disallowances                                              -                   -        26,866           600
  Pension Plan Curtailment                                              -                   -             -        33,679
  Other, net                                                        3,308                (712)        9,631          (923)
                                                              ------------        ------------  ------------  ------------

      Total Other (Income) and Deductions                            (747)             (4,846)       18,964        16,701

Interest Charges
  Long term debt                                                   44,615              48,618        53,026        53,606
  Short term debt                                                      47                  21           398         1,808
  Other, net                                                        6,629               9,307         8,658         4,758
  Allowance for borrowed funds used during
    construction                                                     (563)             (1,423)       (2,901)       (2,012)
                                                              ------------        ------------  ------------  ------------

      Total Interest Charges                                       50,728              56,523        59,181        58,160

Net Income                                                         95,360              97,511        71,928        74,375

Dividends on Preferred Stock
   at required rates                                                5,805               7,465         7,465         7,369
                                                              ------------        ------------  ------------  ------------
Earnings Applicable to Common Stock                               $89,555             $90,046       $64,463       $67,006
                                                              ============        ============  ============  ============

Earnings per Common Share - Basic                                   $2.30               $2.32         $1.69         $1.79

Earnings per Common Share - Diluted                                 $2.30               $2.32         $1.69         $1.79

Cash Dividends Declared per Common Share                            $1.80               $1.80         $1.80         $1.77
</TABLE>

* Reclassified for comparative purposes.


ITEM 6 - SELECTED FINANCIAL DATA

CONSOLIDATED SUMMARY OF OPERATIONS

<TABLE>
<CAPTION>

(Thousands of Dollars)             Year Ended December 31             1993*               1992
---------------------------------------------------------------------------------------------------
<S>                                                               <C>                 <C>
Operating Revenues
  Electric                                                            $638,955            $608,267
  Gas                                                                  293,708             261,724
                                                                  ------------        ------------
                                                                       932,663             869,991
  Electric sales to other utilities                                     16,361              25,541
                                                                  ------------        ------------

      Total Operating Revenues                                         949,024             895,532

Operating Expenses
  Fuel Expenses
    Fuel for electric generation                                        45,871              48,376
    Purchased electricity                                               31,563              29,706
    Gas purchased for resale                                           166,884             141,291
                                                                  ------------        ------------

      Total Fuel Expenses                                              244,318             219,373
                                                                  ------------        ------------

Operating Revenues Less Fuel Expenses                                  704,706             676,159

  Other Operating Expenses
    Operations excluding fuel expenses                                 240,342             226,624
    Maintenance                                                         61,693              62,720
    Depreciation and amortization                                       84,177              85,028
    Taxes - local, state and other                                     126,892             124,252
    Federal income tax - current                                        33,453              36,101
                       - deferred                                       15,877               7,490
                                                                  ------------        ------------

      Total Other Operating Expenses                                   562,434             542,215
                                                                  ------------        ------------

Operating Income                                                       142,272             133,944

Other (Income) and Deductions
  Allowance for other funds used during
    construction                                                          (153)               (164)
  Federal income tax                                                    (9,827)             (4,195)
  Regulatory disallowances                                               1,953               8,215
  Pension Plan Curtailment                                               8,179                   -
  Other, net                                                             2,113              (6,155)
                                                                  ------------        ------------

      Total Other (Income) and Deductions                                2,265              (2,299)

Interest Charges
  Long term debt                                                        56,451              60,810
  Short term debt                                                        1,487               1,950
  Other, net                                                             5,220               5,228
  Allowance for borrowed funds used during
    construction                                                        (1,714)             (2,184)
                                                                  ------------        ------------

      Total Interest Charges                                            61,444              65,804

Net Income                                                              78,563              70,439

Dividends on Preferred Stock
   at required rates                                                     7,300               8,290
                                                                  ------------        ------------

Earnings Applicable to Common Stock                                    $71,263             $62,149
                                                                  ============        ============

Earnings per Common Share - Basic                                        $2.00               $1.86

Earnings per Common Share - Diluted                                      $2.00               $1.86

Cash Dividends Declared per Common Share                                 $1.73               $1.69
</TABLE>

* Reclassified for comparative purposes.
<PAGE>
 
                                       18


 CONDENSED CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>

 (Thousands of Dollars)                  At December 31    1997                1996                1995 *              1994 *     
 <S>                                                     <C>                 <C>                 <C>                 <C>          
 Assets                                                                                                                           
 Utility Plant                                          $3,234,077          $3,159,759          $3,068,103          $2,981,151   
 Less: Accumulated depreciation and                                                                                               
     amortization                                        1,714,368           1,569,078           1,518,878           1,423,098    
                                                        ----------         -----------         -----------         -----------  
                                                         1,519,709           1,590,681           1,549,225           1,558,053    
 Construction work in progress                              74,018              69,711             121,725             128,860    
                                                        ----------         -----------         -----------         -----------  
 Net utility plant                                       1,593,727           1,660,392           1,670,950           1,686,913    
 Current Assets                                            242,371             250,461             292,596             236,519    
 Investment in Empire                                           -                   -               38,879              38,560    
 Deferred Debits                                           432,191             450,623             453,726             484,962    
                                                        ----------         -----------         -----------         -----------  
       Total Assets                                     $2,268,289          $2,361,476          $2,456,151          $2,446,954   
                                                        ==========         ===========         ===========         ===========
 CAPITALIZATION AND LIABILITIES                                                                                                   
 Capitalization                                                                                                                   
 Long term debt                                           $587,334            $646,954            $716,232            $735,178    
 Preferred stock redeemable at option                                                                                             
   of Company                                               47,000              67,000              67,000              67,000    
 Preferred stock subject to mandatory                                                                                             
   redemption                                               35,000              45,000              55,000              55,000    
 Common shareholders' equity:                                                                                                     
   Common stock                                            699,031             696,019             687,518             670,569    
   Retained earnings                                       109,313              90,540              70,330              74,566    
                                                        ----------         -----------         -----------         -----------  
 Total common shareholders' equity                         808,344             786,559             757,848             745,135    
                                                        ----------         -----------         -----------         -----------  
       Total Capitalization                              1,477,678           1,545,513           1,596,080           1,602,313    
                                                        ----------         -----------         -----------         -----------  
                                                                                                                                  
 Long Term Liabilities (Department                                                                                                
   of Energy)                                               96,726              93,752              90,887              87,826    
 Current Liabilities                                       189,317             158,217             182,338             181,327    
 Deferred Credits and Other Liabilities                    504,568             563,994             586,846             575,488    
                                                        ----------         -----------         -----------         -----------  
       Total Capitalization and Liabilities             $2,268,289          $2,361,476          $2,456,151          $2,446,954   
                                                        ==========         ===========         ===========         ===========
</TABLE>

 CONDENSED CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>

 (Thousands of Dollars)                     At December 31                   1993 *            1992 *
<S>                                                                      <C>                <C>
 Assets                                                                               
 Utility Plant                                                            $2,890,799         $2,798,581
 Less: Accumulated depreciation and
     amortization                                                          1,335,083          1,253,117
                                                                         -----------        -----------
                                                                           1,555,716          1,545,464
 Construction work in progress                                               112,750             83,834 
                                                                         -----------        -----------
 Net utility plant                                                         1,668,466          1,629,298            
 Current Assets                                                              248,589            209,621
 Investment in Empire                                                         38,560              9,846
 Deferred Debits                                                             488,527            181,434
                                                                         -----------        -----------

       Total Assets                                                       $2,444,142         $2,030,199
                                                                         ===========        ===========
 CAPITALIZATION AND LIABILITIES                                                       
 Capitalization                           
 Long term debt                                                             $747,631           $658,880 
 Preferred stock redeemable at option
   of Company                                                                 67,000             67,000
 Preferred stock subject to mandatory
   redemption                                                                 42,000             54,000
 Common shareholders' equity:        
   Common stock                                                              652,172            591,532         
   Retained earnings                                                          75,126             66,968              
                                                                         -----------        -----------
                    
 Total common shareholders' equity                                           727,298            658,500
                                                                         -----------        -----------
       Total Capitalization                                                1,583,929          1,438,380
                                                                         -----------        -----------
 Long Term Liabilities (Department                                                    
   of Energy)                                                                 89,804             94,602
 Current Liabilities                                                         234,530            267,276
 Deferred Credits and Other Liabilities                                      535,879            229,941
                                                                         -----------        -----------
       Total Capitalization and Liabilities                               $2,444,142         $2,030,199
                                                                         ===========        ===========
</TABLE>

 * Reclassified for comparative purposes.
<PAGE>
 
                                       19

FINANCIAL DATA

<TABLE>
<CAPTION>
                                       At December 31    1997    1996    1995    1994    1993    1992
                                                        ------  ------  ------  ------  ------  ------
<S>                                                     <C>     <C>     <C>     <C>     <C>     <C>
 
Capitalization Ratios (a) (percent)
Long-term debt                                            43.0    44.7    47.4    48.2    49.4    48.2
Preferred Stock                                            5.2     6.9     7.3     7.3     6.6     8.0
Common shareholders' equity                               51.8    48.4    45.3    44.5    44.0    43.8
                                                        ------  ------  ------  ------  ------  ------
 Total                                                   100.0   100.0   100.0   100.0   100.0   100.0
                                                    
Book Value per Common Share - Year End                  $20.80  $20.24  $19.71  $19.78  $19.70  $18.92
Rate of Return on Average Common Equity (b)         
 (percent)                                               11.00   11.41    8.37    8.92   10.25    9.94
Embedded Cost of Senior Capital (percent)           
Long-term debt                                            7.32    7.33    7.38    7.40    7.36    7.91
Preferred stock                                           5.80    6.26    6.26    6.26    6.69    6.98
Effective Federal Income Tax Rate (percent)               39.2    40.4    40.7    37.7    33.5    35.9
Depreciation Rate (percent) - Electric                    3.12    2.99    2.76    2.69    2.62    2.69
                            - Gas                         2.60    2.60    2.59    2.62    2.60    2.78
Interest Coverages                                  
Before federal income taxes (incld. AFUDC)                4.06    3.82    2.95    2.98    2.87    2.62
                            (excld. AFUDC)                4.04    3.79    2.90    2.94    2.84    2.58
After federal income taxes (incld. AFUDC)                 2.86    2.68    2.16    2.24    2.24    2.04
                           (excld. AFUDC)                 2.84    2.65    2.10    2.20    2.21    2.00
Interest Coverages Excluding Non-Recurring          
 Items (c)                                          
Before federal income taxes (incld. AFUDC)                4.06    3.82    3.66    3.55    3.03    2.74
                            (excld. AFUDC)                4.04    3.79    3.61    3.51    3.00    2.70
After federal income taxes (incld. AFUDC)                 2.86    2.68    2.62    2.61    2.35    2.12
                           (excld. AFUDC)                 2.84    2.65    2.57    2.57    2.32    2.08
</TABLE>

(a) Includes Company's long-term liability to the Department of Energy (DOE) for
    nuclear waste disposal.  Excludes DOE long-term liability for uranium
    enrichment decommissioning and amounts due or redeemable within one year.

(b) The return on average common equity for 1995 excluding effects of the 1995
    Gas Settlement is 12.10%.  The rate of return on average common equity
    excluding effects of retirement enhancement programs recognized by the
    Company in 1994 and 1993 is 11.90% and 11.20%, respectively.

(c) Recognition by the Company in 1992 of disallowed ice storm costs as approved
    by the PSC has been excluded from 1992 coverages.  Coverages for 1994 and
    1993 exclude the effects of retirement enhancement programs recognized by
    the Company during each year and certain gas purchase undercharges written
    off in 1994 and 1993. Coverages in 1995 exclude the economic effect of the
    1995 Gas Settlement ($44.2 million, pretax).
<PAGE>
 
                                       20

Item 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS


     The following is Management's assessment of certain significant factors
affecting the financial condition and operating results of the Company.  This
assessment contains forward-looking statements which are subject to various
risks and uncertainties.  The Company's actual results could differ from those
anticipated in such forward-looking statements as a result of numerous factors
which may be beyond the Company's control by reason of factors such as electric
and gas utility restructuring, future economic conditions, and developments in
the legislative, regulatory and competitive environments in which the Company
operates.  Shown below is a listing of the principal items discussed.

     Earnings Summary                                      Page 20

     Competition                                           Page 21
     PSC Competitive Opportunities Case Settlement
          Business and Financial Strategy
          PSC Position Paper on Nuclear Generation
          FERC Open Transmission Orders
          Gas Restructuring and PSC Negotiations
          Prospective Financial Position
 
     Rates and Regulatory Matters                          Page 27
          1996 Electric Rate Settlement
          1995 Gas Settlement
          Flexible Pricing Tariff
 
     Liquidity and Capital Resources                       Page 27
          Capital and Other Requirements
          Redemption of Securities
          Financing
 
     Results of Operations                                 Page 30
          Operating Revenues and Sales
          Fossil Unit Ratings and Status
          Operating Expenses
 
     Dividend Policy                                       Page 33

EARNINGS SUMMARY

     Despite rate reductions in July 1996 and 1997, earnings applicable to
Common Stock were nearly unchanged in 1997 due, in part, to the increased
availability of the Company's Ginna nuclear generating facility following the
1996 refueling and steam generator replacement outage.  Increased Company
generation allowed the Company to reduce purchased electric expense , while
increasing available power for customer consumption and resale.  A decrease in
financing costs as a result of discretionary redemptions and refinancing
activities during the year also helped to increase earnings.  In addition to
rate reductions, offsetting a gain in 1997 earnings were a warmer heating season
during the first quarter of the year coupled with a cooler summer which affected
air conditioning load.

     Basic and dilutive earnings per share of $2.30 in 1997 are down two cents
compared to a year ago.  In February 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 128 ("SFAS-128"),
"Earnings per Share," which changes the methodology of calculating earnings per
share.  The Company adopted SFAS No. 128 during the fourth quarter of 1997.  The
impact on earnings per share for prior periods is not material. A discussion of
the calculation of earnings per share is presented in Note 1 to the Notes to
Financial Statements.

     Basic and dilutive earnings per share of $1.69 reported in 1995 reflect a
pretax reduction of $44.2 million, or $.75 per share net-of-tax, in connection
<PAGE>
 
                                       21

with a negotiated settlement (see 1995 Gas Settlement discussed below) reached
between the Company, Staff of the New York State Public Service Commission (PSC)
and other parties resolving various proceedings to review issues affecting the
Company's gas costs.

     The impact of developing competition in the energy marketplace will affect
future earnings. The Competitive Opportunities Case Settlement (the
"Settlement", see description below) allows for a phase-in to open electric
markets while lowering customer prices and establishing an opportunity for
competitive returns on shareholder investments. The nature and magnitude of the
potential impact of the Settlement on the business of the Company will depend on
the availability of qualified energy suppliers, the degree of customer
participation and ultimate selection of an alternative energy supplier,  the
Company's ability to be competitive by controlling its operating expenses, and
the Company's ultimate success in development of its unregulated business
opportunities as permitted under the Settlement.

     Future earnings will also be affected, in part, by the Company's degree of
success in remarketing its excess gas capacity as set under the terms of the
1995 Gas Settlement and in controlling its local gas distribution costs.  The
Company believes it will be successful in meeting the 1995 Gas Settlement
targets over the remaining year of the Settlement period, although no assurance
may be given.

 
COMPETITION

     Overview.  During 1996 and 1997, the Company, the Staff of the PSC, and
several other parties negotiated an agreement which was approved by the PSC in
November 1997.  This agreement sets the framework for the introduction and
development of open competition in the electric energy marketplace and lasts
through the year 2002.  Over this time, the way electricity is delivered to
customers will fundamentally change.  In phases, the Company will open its
electric system to other suppliers.  The system will be fully open to
competitors by July of 2001.  These suppliers will compete to package and sell
energy and related services to customers.  The Company and its subsidiaries will
be among the supplier choices.  Competing suppliers will pay the Company a fee
to use its electric distribution system and the Company will remain responsible
for maintaining it and responding to most emergencies.


     PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT.  Through its "Competitive
Opportunities Proceeding," the PSC has embarked on a fundamental restructuring
of the electric utility industry in the State.  Among other elements, the PSC's
goals included lower rates for consumers and increased customer choice in
obtaining electricity and other energy services.

     The Company's proceeding was completed on November 26, 1997 with the PSC
approval of a Settlement Agreement among the Company, the PSC Staff and other
parties.  The PSC's November 26, 1997 order of approval was confirmed by a full
Opinion and Order (No. 98-1) issued January 14, 1998.

     Summary.  The Settlement provides for a transition to competition during
its five-year term (July 1, 1997 through June 30, 2002) and establishes the
Company's electric rates for each annual period.  A Retail Access Program will
be phased in, allowing customers to purchase electricity, and later electricity
and capacity commitments, from sources other than the Company.  The Company will
be provided a reasonable opportunity to recover prudently incurred costs,
including those pertaining to generation and purchased power.

     The Settlement also requires the Company to functionally separate its
component operations:  distribution, generation, and retailing.  Any unregulated
retail operations must be structurally separate from the regulated utility
functions but may be funded with up to $100 million.  In addition, the Company
would have the option after receiving the necessary regulatory approvals to
establish a holding company structure.  Although the Settlement provides
incentives for the sale of generating assets, it requires neither divestiture of
generating or other assets, nor write off of "stranded costs" (the above-market
costs, presumed to result from competition).
<PAGE>
 
                                       22

     The Company believes that the Settlement will not adversely affect its
eligibility to continue to apply Statement of Financial Accounting Standards No.
71 ("SFAS-71"), with the exception of certain "to-go costs" associated with non-
nuclear generation.  If, contrary to the Company's view, such eligibility were
adversely affected, a material write-down of assets, the amount of which is not
presently determinable, could be required.

     Rate Plan.  Over the five year term of the Settlement, the cumulative rate
reductions will be as follows:  Rate Year 1:  $3.5 million; Rate Year 2:  $12.8
million; Rate Year 3:  $27.6 million; Rate Year 4:  $39.5 million; and Rate Year
5:  $64.6 million.

     The Rate Plan permits the Company to offset against the foregoing total
reductions certain inflation-related expenses, and certain amounts related to a
power purchase agreement with Kamine/Besicorp Allegany L.P.(Kamine), including
seven-eighths of any difference between Kamine costs currently included in rates
and any increased amount resulting from enforcement of such agreement with any
balance not recovered during the term of the Settlement subject to deferral for
recovery after such term. The agreement is subject to litigation, as discussed
in Note 10 of the Notes to Financial Statements.  In the event of a settlement
of the Kamine matter, the Settlement permits the Company to offset against rate
reductions, the following amounts: Rate Year 2, $3.5 million; Rate Year 3, $8.4
million; Rate Year 4 and continuing until Settlement payments are complete or
July 1, 2002, whichever is later, $10.5 million.

     In the event that the Company earns a return on common equity in excess of
an effective rate of 11.50 percent over the entire five-year term of the
Settlement, 50 percent of such excess will be used to write down deferred costs
accumulated during the term.  The other 50 percent of the excess will be used to
write down accumulated deferrals or investment in electric plant or Regulatory
Assets (which are deferred costs whose classification as an asset on the balance
sheet is permitted by SFAS-71).  If certain extraordinary events occur,
including a rate of return on common equity below 8.5 percent or above 14.5
percent, or a pretax interest coverage below 2.5 times, then either the Company
or any other party to the Settlement would have the right to petition the PSC
for review of the Settlement and appropriate remedial action.

     Retail Access. RG&E's Energy Choice Program will be available to all of its
customers, without regard to customer class, on an equal basis up to certain
usage caps.  On July 1, 1998, customers whose electric loads represent
approximately 10 percent of the Company's total annual retail sales will be
eligible to purchase electricity (but not capacity commitments) from alternative
suppliers.  On July 1, 1999, customers with 20 percent of total sales will be
eligible and as of July 1, 2000, 30 percent of total sales will be eligible.  As
of July 1, 2001, all retail customers will be eligible to purchase energy and
capacity from alternative suppliers.

     During the initial, energy only stage of the Retail Access Program, the
Company's distribution rate will be set by deducting 2.3 cents per kilowatt hour
("KWH") from its full service ("bundled") rates and Load Serving Entities acting
as retailers in the Company's service area will be entitled to purchase
electricity from the Company at a rate of 1.9 cents per KWH.  During the energy
and capacity stage, the rate will generally equal the bundled rate less the cost
of the electric commodity and the Company's non-nuclear generating capacity.
These commodity and capacity costs, generally referred to as "contestable
costs," are estimated to be 3.2 cents per KWH, inclusive of gross receipts
taxes.

     Generating Assets. The Company will not be required to divest any of its
generation facilities. To the extent that the Company sells any generating
assets during the term of the Settlement, gains on such sales will be shared
between the Company and customers.  With regard to losses on such sales, the
Settlement acknowledges an intent that the Company will be permitted to recover
such losses through distribution rates during the term of the Settlement.
Future rate treatment is to be consistent with the principle that the Company is
to have a reasonable opportunity to recover such costs.

     "To-go costs" of the Company's non-nuclear resources (i.e., capital costs
incurred after February 28, 1997, operation and maintenance expenses, and
property, payroll and other taxes) are to be recovered through the distribution
<PAGE>
 
                                       23

access tariff.  The fixed portion of To-Go Costs would be recovered in full
through the distribution access tariff until July 1, 1999 and subject to the
market thereafter in accordance with the phase-in schedule for the Retail Access
Program described above.  The variable portion of non-nuclear to-go costs would
also be subject to the market in accordance with the phase-in Schedule described
above.  Upon extension of eligibility for the Retail Access Program to all
retail customers on July 1, 2001, the Company would be authorized to modify its
distribution access rates, so as to hold constant the degree to which its to-go
costs are at risk for recovery through the market.  Thus, while the recovery of
non-nuclear to-go Costs would continue to be through the market, recovery of
nuclear costs would remain recoverable through regulated rates.  No change in
such treatment of nuclear facilities would be implemented prior to the PSC's
resolution of the issues raised in its Staff Report on nuclear generation (see
PSC Position Paper on Nuclear Generation).  Shutdown and decommissioning costs
would be recovered during the term of the Settlement in a manner consistent with
past ratemaking treatment.

     Pilot Program. Consistent with a PSC order issued June 23, 1997 in a
separate proceeding involving establishment of pilot programs for farmers and
food processors, the Settlement provides that the Company's Retail Access
Program will commence on February 1, 1998 for those groups within the Company's
service area.

     Tariff Filing.  On December 1, 1997, the Company submitted to the PSC its
proposed tariffs and a Distribution Operating Agreement to establish "Energy
Choice", the Company's proposed retail access program to implement the terms of
the Settlement.  In an order issued January 21, 1998, the PSC approved certain
provisions of the December 1, 1997 tariff filing and required the Company to
revise others.  In late January 1998 the Company filed revisions to the tariff
to incorporate the changes required by the PSC's order.

     Miscellaneous.  After approval of the Settlement becomes final and non-
appealable, the Company will withdraw legal appeals which challenge various PSC
Orders regarding the PSC Competitive Opportunities Proceeding, establishment of
a pilot program pursuant to those proceedings, and certain provisions of the
1996 Electric Rate Settlement.

     The present Settlement supersedes the 1996 Rate Settlement.  Various
incentive and penalty provisions in the 1996 Electric Rate Settlement are
eliminated.


     BUSINESS AND FINANCIAL STRATEGY: THE COMPANY'S RESPONSE. Under the terms of
the Settlement, the Company will functionally separate its generation,
distribution, and regulated energy services businesses.  As permitted by the
Settlement, the Company has established a separate unregulated subsidiary called
Energetix which will be able to compete for energy, energy services and products
both in and outside the Company's existing franchise service territory.  The
Company has also developed an integrated financial strategy which includes new
business development initiatives and a Common Stock share repurchase program.

     Energy Choice.  Within the framework of the Energy Choice Program, the
Company will unbundle traditional utility services.  Retail electric customers
in the Company's service territory will have the opportunity to purchase energy,
capacity, and retailing services from competitive energy service companies,
referred to as Load Serving Entities (LSEs). They may also continue to purchase
fully-bundled electric service from the Company under existing retail tariffs.

     General Structure.  Energy Choice  adopts the "single-retailer" model for
the relationship between RG&E, the LSEs, and retail customers.  Under the
"single-retailer" model the regulated utility's customer is the LSE, whose
customers are the retail customers.  The relationship between the regulated
utility and retail customers is substantially eliminated.  The LSE assumes
responsibility for providing its retail customers with bundled energy and
delivery services, and for virtually all related retailing functions, including
direct contact and communications with retail customers.   With the exception of
transmission and distribution service, the LSE will procure for its customers,
or will itself create and provide them with, all necessary components of fully
bundled service on a competitive basis.
<PAGE>
 
                                       24


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

     Until the development of a wholesale market for generating capacity, there
will be no suitable mechanism for the reallocation, from the regulated utility
to the LSE, of responsibility for ensuring adequate installed reserve capacity.
Accordingly,  during the initial "Energy Only" stage of the Energy Choice
Program (July 1, 1998 to July 1, 1999), LSEs will be able to choose their own
sources of energy supply, while RG&E will provide to LSEs, and will be
compensated for, the generating capacity (installed reserve) needed to serve
their retail customers reliably.  During the "Energy and Capacity" stage
commencing July 1, 1999, the LSEs will be able to select, and will be
responsible for procuring, generating capacity, as well as energy, to serve the
loads of their retail  customers, and distribution charges will be accordingly
reduced as hereinafter described.  If by July 1, 1998 there is not a functioning
Statewide energy and capacity market (see discussion under FERC Open
Transmission Orders), the Company may petition the PSC for deferral of the
scheduled commencement of the Energy and Capacity stage.

     Summary.  The availability of LSEs to serve eligible customers and how
quickly they decide to become involved cannot be determined. Likewise, the
Company is not able to predict the number of customers that may chose to no
longer be served under the Company's regulated tariffs.

     The proposed tariffs for Energy Choice as filed by the Company are expected
to become effective February 1, 1998 for the pilot program.  The PSC has not set
a decision-making date for the full-scale program.  The Company is unable to
predict what final rules or regulations will ultimately be adopted by the PSC
for this program.

     Unregulated Energy Services Company.  It is part of the Company's financial
strategy to stimulate growth by entering into unregulated businesses.  The first
step in this direction was the formation and operation of Energetix effective
January 1, 1998. Energetix is an unregulated subsidiary of the Company that will
bring energy products and services to the marketplace both within and outside
the Company's franchise area.

     The Settlement approved by the PSC in November allows for the investment of
up to $100 million in unregulated businesses during the next five years.  During
1998, the Company expects to determine the actual level of the initial
investments to be made in unregulated business opportunities.

     On July 1, 1997 the Company and Energetix filed with the Federal Energy
Regulatory Commission (FERC) seeking authorization to engage in the wholesale
sale of electric energy and capacity at market-based rates.  These applications
were accepted by FERC on September 12, 1997.  The Company must seek separate
authorization in order to sell electric energy to Energetix at market-based
rates.

     Stock Repurchase Plan.  In December 1997 the Company's Board of Directors
approved a Stock Repurchase Plan.  This plan, which is subject to approval by
the PSC, provides for the repurchase over the next three years of up to 4.5
million shares of Common Stock, representing approximately 11.5 percent of the
Company's outstanding shares of Common Stock at December 31, 1997.  The Company
expects a PSC decision in early 1998.

     Nuclear Operating Company.  In October 1996, the Company and Niagara Mohawk
Power Corporation (Niagara) announced plans to establish a nuclear operating
company to be known as the New York Nuclear Operating Company (NYNOC).  Since
that time NYNOC has been organized as a New York Limited Liability Company and
the Consolidated Edison Company of New York and New York Power Authority have
announced their desire to move forward with the Company and Niagara with plans
to implement NYNOC.  It is envisioned that NYNOC would eventually assume
responsibility for operation of all the nuclear plants in New York State,
including the Company's totally owned Ginna Nuclear Plant and jointly owned Nine
Mile Two.  The Company believes that NYNOC could contribute to maintaining a
high level of operational performance, contribute to continued satisfactory
Nuclear
<PAGE>
 
                                       25

Regulatory Commission (NRC) compliance, provide opportunities for continued cost
reduction and provide the basis for satisfactory economic regulation by the PSC.
Various groups are now involved in the detailed studies and analyses required
before a definitive decision to proceed with NYNOC can be made.  The organizing
utilities have submitted comments on the PSC Staff position paper on nuclear
generation (discussed below under the heading PSC Position Paper on Nuclear
Generation) noting that the Staff proposal would nullify the potential benefits
of NYNOC.


     PSC POSITION PAPER ON NUCLEAR GENERATION.  On August 27, 1997, the PSC
requested comments from interested parties on a PSC Staff position paper
concerning the treatment of nuclear generation after a transition period.  The
Staff paper concludes that (1) nuclear generation should operate on a
competitive basis, (2) sale of generation plants at auction to third parties is
the preferred means of determining market value and offers the greatest
potential for mitigation of stranded costs and the elimination of anti-
competitive subsidies, and (3) where third party sales are not feasible, "to-go"
costs (fuel, labor and other operating costs, prospective capital additions,
property taxes and insurance) must be recovered in the wholesale market price of
power.

     On October 15, 1997, the Company and four other utilities jointly responded
to the PSC. The utilities believe that the inherent operating characteristics of
nuclear generation and the implications of NRC regulation require that nuclear
plants have access to an adequate revenue stream and that such plants should be
treated for dispatch purposes as baseload, must run units.  The utilities urge
the PSC to adopt a process that would enable all parties to fully develop the
necessary facts and analyses and to invite the NRC to participate in addressing
the future of nuclear generation in New York State. Certain other parties have
filed comments on the position paper, some of which oppose full recovery of
"stranded costs" that could result from sales of plants at less than book costs.
The Company is unable to predict the outcome of the PSC's consideration.


     FERC OPEN TRANSMISSION ORDERS AND COMPANY FILINGS.  In early 1996 FERC
issued new rules to facilitate the development of competitive wholesale markets
by requiring electric utilities to offer "open-access" transmission service on a
non-discriminatory basis in tariffs.  The Company filed its required
transmission service tariff on July 9, 1996. The new tariff would apply to
wholesale purchases and sales made by the Company and the financial impact will
depend on prevailing energy prices in the wholesale market.  The near-term
impacts of this tariff are not expected to be significant.  On March 6, 1997,
the Company reached a settlement in principle with the other parties respecting
rate issues. FERC approval of the settlement was granted on June 25, 1997.

     On January 31, 1997, the utilities filed a "Comprehensive Proposal To
Restructure the New York Wholesale Electric Market" with the FERC.  As proposed,
the existing New York Power Pool (NYPP) will be dissolved and an independent
system operator (ISO) will administer a state-wide open access tariff and
provide for the short-term reliable operation of the bulk power system in the
state. In addition to proposing a FERC-endorsed ISO, the proposal calls for
creation of  a New York Power Exchange and a New York State Reliability Council.
An additional supplemental filing with FERC was made on December 19,1997 which
lays out a specific timeframe for the implementation of a competitive wholesale
electricity market in New York State.  The utilities have requested FERC
approval of their restructuring plan no later than March 31, 1998, which would
allow the ISO to be operational by June 30, 1998. The timetable for retail
competition will be determined for each utility in accordance with individual
settlements in the Competitive Opportunities Proceeding.

     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.


     GAS RESTRUCTURING AND PSC NEGOTIATIONS.  In March 1996 the PSC issued an
Order and approved utility restructuring plans designed to open up the local
<PAGE>
 
                                       26

natural gas market to competition and thereby allow residential, small business
and commercial/industrial users the same ability to purchase their gas supplies
from a variety of sources, other than the local utility, that larger industrial
customers already have.  During a three-year phase-in period the State's gas
utilities would be permitted to require customers converting from sales service
to take associated pipeline capacity for which the utilities had originally
contracted.  The PSC has indicated that it will address the issue of how the
costs of such capacity would be recovered after the three-year period during the
third year of the phase-in period.  The PSC Staff has recently issued a position
paper on The Future of the Natural Gas Industry in which the Staff proposes that
local distribution companies (such as the Company) exit the merchant function in
five years.  Treatment of existing pipeline capacity contracts and Provider of
Last Resort responsibilities are substantial issues to be worked out between the
PSC, the local gas distribution companies and other stakeholders. See Note 10 of
the Notes to Financial Statements for further information about the PSC gas
restructuring proceedings and the PSC Staff position paper.

     Gas customers have had a choice of suppliers since November 1, 1996.  Under
separate transportation tariffs, the Company distributes the gas and charges for
the distribution as well as associated services.  The Company believes its
position in the market is such that it will maintain its distribution system
margins.  Under a phase-in limitation, loss of gas commodity sales may be
limited to five percent of the Company's annual gas volume the first year, and
then five additional percent for each of the following two years.  The phase-in
will be reviewed as experience is gained with the program.  The Company
anticipates that the use of transportation gas service will increase.  Through
December 31, 1997, 150 customers were being served under this service.

     In July 1997, the Company commenced negotiations with the PSC Staff and
other parties with the objective of developing a multi-year settlement of issues
pertaining to the Company's gas business that would take effect upon expiration
of the current 1995 Gas Settlement (see Rates and Regulatory Matters) on June
30, 1998.  A further objective of these negotiations is to maximize the
efficiencies of the entire business by structuring a settlement that will be as
consistent as possible with the provisions of the Settlement in the Competitive
Opportunities Proceeding, as discussed earlier.  Negotiations are at an early
stage; accordingly, the Company can make no prediction as to their outcome.


     COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION.  With PSC
approval, the Company has deferred certain costs rather than recognize them on
its books when incurred.  Such deferred costs are then recognized as expenses
when they are included in rates and recovered from customers.  Such deferral
accounting is permitted by SFAS-71. These deferred costs are shown as Regulatory
Assets on the Company's Balance Sheet and a discussion and summarization of such
Regulatory Assets is presented in Note 10 of the Notes to Financial Statements.

     In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates.  Estimates of
such strandable assets are highly sensitive to the competitive wholesale market
price assumed in the estimation.  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.  A discussion
of strandable assets is presented in Note 10 of the Notes to Financial
Statements.

     At December 31, 1997 the Company believes that its regulatory and
strandable assets, if any, are not impaired and are probable of recovery.  The
Settlement in the Competitive Opportunities Proceeding does not impair the
opportunity of the Company to recover its investment in these assets.  However,
the PSC has published a Staff paper to address issues surrounding nuclear
generation, including the determination of fair market value for facilities
after a five year restructuring transition period.  It appears that the PSC may
seek to apply similar principles to other types of generating facilities. A
determination in this proceeding could have an impact on strandable assets.
<PAGE>
 
                                       27

RATES AND REGULATORY MATTERS


     1996 ELECTRIC RATE SETTLEMENT.  The PSC approved a Settlement Agreement
(1996 Rate Settlement) among the Company, PSC Staff and several other parties
which set rates for a three-year period commencing July 1, 1996.  The
Competitive Opportunities Settlement (Settlement) supersedes the 1996 Rate
Settlement. A rate reduction for the first rate year under the Settlement of 0.5
percent ($3.5 million) commencing July 1, 1997 is equal to the previously
approved planned reduction under the 1996 Rate Settlement. After approval of the
Settlement becomes final and non-appealable, the Company will terminate its
petition seeking judicial review of the 1996 Rate Settlement.


     1995 GAS SETTLEMENT.  In October of 1995, a settlement of various gas rate
and management issues was finalized (the 1995 Gas Settlement).  This settlement
affects the rate treatment of various gas costs through October 31, 1998.

     Highlights of the 1995 Gas Settlement are:

-    The Company will forego, for three years ending in mid-1998, gas rate
     increases exclusive of the cost of natural gas and certain cost increases
     imposed by interstate pipelines.

-    The Company has agreed not to charge customers for pipeline capacity costs
     in 1996, 1997 and 1998 of $22.5 million, $24.5 million, and $27.2 million,
     respectively. The Company may sell its excess transportation capacity in
     the market under FERC rules.

-    The Company agreed to write off excess gas pipeline capacity and other
     costs incurred through 1995.

     The economic effect of the 1995 Gas Settlement on the Company's 1995
results of operations was to reduce earnings by $.75 per share.

      The Company has entered into several agreements to help manage its
pipeline capacity costs and has successfully met settlement targets for capacity
remarketing for the twelve months' periods ending October 31, 1997 and October
31, 1996, thereby avoiding negative financial impacts for those periods.  The
Company believes that it will also be successful in meeting the Settlement
targets in the remaining year of the Settlement period, although no assurance
may be given.


     FLEXIBLE PRICING TARIFF. Under its flexible pricing tariff for major
industrial and commercial electric customers, the Company may negotiate
competitive electric rates at discount prices to compete with alternative power
sources, such as customer-owned generation facilities.  Pursuant to the terms of
the Settlement under the Competitive Opportunities Proceeding, the Company will
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
that would otherwise apply.  Approximately 27 percent of all electric sales
(KWHs) to customers are made under long-term contracts, primarily to large
industrial customers.  These contracts represent approximately 42 percent of the
Company's revenues from its commercial and industrial customers.  The Company
has not experienced any significant customer loss due to competitive alternative
arrangements.  Certain provisions of a flexible rate contract with the
University of Rochester have been challenged by the Antitrust Division of the
United States Department of Justice as discussed in Note 10 to the Financial
Statements under the heading Litigation.


LIQUIDITY AND CAPITAL RESOURCES

          Cash flow, mainly from operations, provided the funds for construction
expenditures, debt reductions, redemption of Preferred Stock and the payment of
dividends during 1997 (see Consolidated Statement of Cash Flows).
<PAGE>
 
                                       28

          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 and the repayment of existing debt. In 1996
the Company completed replacement of the two steam generators at the Ginna
Nuclear Plant which resulted in improved plant efficiency.  The Company spent
approximately $46 million on this project in 1996 and $29 million in 1995.  The
Company has no plans to install additional baseload generation.

          Purchased Power Requirement.  Under federal and New York State laws
and regulations, the Company is required to purchase the electrical output of
unregulated cogeneration facilities which meet certain criteria (Qualifying
Facilities).  The Company was compelled by regulators to enter into a contract
with Kamine for approximately 55 megawatts of capacity, the circumstances of
which are discussed in Note 10 of the Notes to Financial Statements. The Company
has no other long-term obligations to purchase energy from Qualifying
Facilities.

          Year 2000 Computer Issues.  As the year 2000 approaches many companies
face a potentially serious information systems (computer) problem because most
software application and operational programs written in the past will not
properly recognize calendar dates beginning with the year 2000. At this time,
the Company believes that the problem is being addressed properly to prevent any
adverse operational or financial impacts.  The Company believes it will incur
approximately $15 million of costs through January 1, 2000, associated with
making the necessary modifications identified to date.  Total costs incurred in
1997 were approximately $1.4 million.


          ENVIRONMENTAL ISSUES.  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.  A more detailed discussion concerning the Company's
environmental matters, including a discussion of the federal Clean Air Act
Amendments, 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 $1 million in 1995, $49 million
in 1996, and approximately $152 million in 1997.  Included in discretionary
redemptions for 1997 were nearly $102 million of tax-exempt securities which
were refinanced with new multi-mode tax-exempt bonds as discussed under
Financing.
<PAGE>
 
                                       29


          CAPITAL REQUIREMENTS - SUMMARY. Capital requirements for the three-
year period 1995 to 1997 and the current estimate of capital requirements
through 2000 are summarized in the Capital Requirements table.

          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 warrant, the redemption or refinancing of certain outstanding
long-term securities.

<TABLE>
<CAPTION>

Capital Requirements
-------------------------------------------------------------------------------
                                            Actual              Projected

                                      1995  1996  1997      1998  1999  2000
Type of Facilities                           (Millions of Dollars)
-------------------------------------------------------------------------------
<S>                                   <C>   <C>   <C>       <C>   <C>   <C>
Electric Property                                     
   Production                         $ 48  $ 57  $  9      $ 19  $ 17  $ 13
   Energy Delivery                      25    23    28        43    32    28
                                      ----  ----  ----      ----  ----  ----
    Subtotal                            73    80    37        62    49    41
  Nuclear Fuel                          17    16    19        15    16    27
                                      ----  ----  ----      ----  ----  ----
    Total Electric                      90    96    56        77    65    68
Gas Property                            14    17    22        23    17    18
Common Property                          4     6     9        24    18     6
                                      ----  ----  ----      ----  ----  ----
    Total                              108   119    87       124   100    92
                                                      
Carrying Costs                                        
   Allowance for Funds Used During                    
    Construction                         3     2     1         1     1     1
                                      ----  ----  ----      ----  ----  ----
 Total Construction Requirements       111   121    88       125   101    93
Securities Redemptions, Maturities                    
   and Sinking Fund Obligations*         1    67   182        40    10    30
                                      ----  ----  ----      ----  ----  ----
    Total Capital Requirements        $112  $188  $270      $165  $111  $123
                                      ----  ----  ----      ----  ----  ----
</TABLE>
* Excludes prospective refinancings.


          FINANCING.  Capital requirements in 1997, including the discretionary
redemption of $49.7 million of securities, were satisfied primarily with
internally generated funds.  In addition, the Company at its option refinanced
$101.9 million of outstanding tax-exempt securities with the proceeds from the
sale on August 19, 1997 of $101.9 million of New York State Energy Research and
Development Authority (NYSERDA) multi-mode tax-exempt bonds due August 1, 2032.
Interest rates on these bonds may be set weekly or may be set for varying
periods based on market conditions at the time. The weighted average interest
rate on these bonds was 3.65 percent for 1997.

          On September 16, 1997, the Company completed arrangements for the
delivery in September 1998 of $25.5 million of 5.95% NYSERDA tax-exempt bonds
due September 1, 2033. Proceeds will be used to redeem an issue of tax-exempt
first mortgage bonds which is not redeemable until December 1998.

          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 1997, Common Stock shares outstanding increased
by 10,883 shares as a result of those options which were actually exercised
during the year. These were the only shares of Common Stock issued by the
Company during 1997.

          The Company foresees modest near-term financing requirements. With an
increasingly competitive environment, the Company believes maintaining a high
degree of financial flexibility is critical.  In this regard, the Company's
long-term objective is to control capital expenditures. Moreover, in 1998 the
Company may begin funding a stock repurchase program and investments in
unregulated businesses as discussed under Competition.
<PAGE>
 
                                       30

          Capital and other cash requirements during 1998 are anticipated to be
satisfied primarily from a combination of internally generated funds and the use
of short-term credit arrangements.  The Company may refinance maturing long-term
debt and Preferred Stock obligations during 1998 depending on prevailing
financial market conditions.

          The Company anticipates utilizing its credit agreements and unsecured
lines of credit to meet any interim external financing needs prior to issuing
any long-term securities. For information with respect to short-term borrowing
arrangements and limitations, see Note 9 of the Notes to Financial Statements.
As financial market conditions warrant, the Company may also, from time to time,
redeem higher cost senior securities.


RESULTS OF OPERATIONS

          The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing 1997 to 1996 and 1996
to 1995. The Notes to Financial Statements contain additional information.


          OPERATING REVENUES AND SALES. Operating revenues in 1997 were lower
than 1996 with the effect of electric base rate decreases in July 1996 and 1997
and lower therm sales of gas due to milder weather than last year partially
offset by higher customer electric kilowatt-hour sales resulting from increased
customers and higher electric sales to other utilities.  Despite lower operating
revenues, operating revenues less fuel expenses were nearly unchanged reflecting
primarily a decline in purchased electricity expense as a result of increased
availability of the Company's generating facilities.

          The effect of weather variations on operating revenues is most
measurable in the Gas Department, where revenues from spaceheating customers
comprise about 90 to 95 percent of total gas operating revenues.  Compared to a
year earlier, weather in the Company's service area was 9.0 percent warmer
during the first three months of 1997 and 1.1 percent warmer for the entire year
on a calendar month heating degree day basis.  In contrast, weather during 1996
was 7.1 percent colder than 1995 on a calendar month heating degree day basis.
With elimination of a weather normalization clause in the Company's gas tariff
effective November 1, 1995, abnormal weather variations may have a more
pronounced effect on gas revenues.  Cooler than normal summer weather during
1997 and 1996 hampered the demand for air conditioning usage, with a more
pronounced effect in 1997 with the 1997 weather being approximately 27 percent
cooler than 1996.

          Compared with a year earlier, kilowatt-hour sales of energy to retail
customers were up 1.2 percent in 1997, following a 0.3 percent increase in 1996.
Sales to commercial customers achieved the largest gain in 1997.  Sales to
industrial customers led the increase in 1996 compared to a year earlier and
were driven by one large industrial customer who purchased more electric power
as an alternative to power produced at its own plant. Decreased electric demand
for air conditioning usage caused by cooler summer weather had an impact on
kilowatt-hour sales in 1996 and 1997.

          Fluctuations in revenues from electric sales to other utilities are
generally related to the Company's customer energy requirements, the wholesale
energy market, availability of transmission, and the availability of electric
generation from Company facilities.  Revenues from electric sales to other
utilities rose in 1997 due to increased sales resulting from greater
availability of our combined nuclear and fossil generation, a favorable
wholesale market in the second half of the year, and increased marketing of
available capacity.  In contrast to 1997, revenues from sales to other electric
utilities declined in 1996 reflecting decreased kilowatt-hour sales to such
utilities and less generation from the Company's Ginna Nuclear Plant.

          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 mix.  Company facilities are used to
distribute this gas, which amounted to 16.6 million dekatherms in 1997 and 16.8
million dekatherms in 1996.  These purchases by eligible customers have caused
decreases in Company revenues, with offsetting decreases in purchased gas
<PAGE>
 
                                       31

expenses and, in general, do not adversely affect earnings because
transportation customers are billed at rates which, except for the cost of
buying and transporting gas to the Company's city gate, approximate the rates
charged the Company's retail gas service customers.  Gas supplies transported in
this manner are not included in Company therm sales, depressing reported gas
sales to non-residential customers.

          Therms of gas sold and transported were down 4.1 percent in 1997,
after increasing nearly eight percent in 1996.  These changes reflect,
primarily, the effect of weather variations on therm sales to customers with
spaceheating.  If adjusted for normal weather conditions, residential gas sales
would have decreased about 1.5 percent in 1997 over 1996, while non-residential
sales, including gas transported, would have increased approximately two percent
in 1997.  The average use per residential gas customer, when adjusted for normal
weather conditions, showed a modest decrease in 1996 and 1997.


          FOSSIL UNIT RATINGS AND STATUS.  Several of the Company's fossil-
fueled generating units have been temporarily derated since February 1997 to
maintain acceptable opacity levels while the Company investigates additional
engineering solutions to address the opacity of the Units' emissions ( see Note
10 of the Notes to Financial Statements under the heading "Environmental
Matters, Opacity Issue").  The financial impact of the deratings includes the
lost opportunity associated with energy sales and, at times, the need to make
additional purchases to meet system requirements.  While the deratings have
decreased earnings, and will continue to do so, the amount is not expected to be
material.

          The NYPP is in the process of evaluating new rules for its system load
regulation.  Opacity limitations are expected to reduce the ability of the
Company to react to changes in load and provide system load regulation services
when called upon by the NYPP, resulting in additional costs.  Depending on the
new NYPP requirements, and whether the deratings remain in effect, the revised
rules could result in the Company having to purchase additional regulation
services which may cost between $500,000 and $2,500,000 annually.  The Company
intends to make a $2.7 million capital upgrade to the precipitator of one of its
fossil-fueled generating units which is expected to remove a substantial portion
of the opacity exceedance which led to the derating.

          On January 21, 1998 the Company decided to retire Beebee Station by
mid-1999.  Factors such as the plant's age, location in an area no longer
consistent with the surrounding development, 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 will be fully depreciated at the time of
retirement. The Settlement provides that all prudently incurred incremental
costs associated with the shut down and decommissioning of the plant are
recoverable through the Company's distribution access tariff.  The electric
capability and energy currently provided by the plant is expected to be replaced
by purchased power as needed.

          On December 1, 1997 Niagara announced a plan to sell its fossil-fueled
and hydroelectric generating stations by auction in 1998. This plan was agreed
to as part of Niagara's Power Choice Settlement currently under review by the
PSC.  The Company intends to include its 24 percent share of the Oswego Steam
Station Unit 6 (Oswego 6) for sale as part of Niagara's auction.  Any gains or
losses realized by the Company from the sale of its share of Oswego 6 would be
treated in accordance with the terms of the Settlement under the Competitive
Opportunities Proceeding.


OPERATING EXPENSES

          Energy Costs - Electric.  Higher fuel expense for electric generation
in 1997 compared with a year earlier reflects increased generation from both
fossil and nuclear-fueled plants.  Total Company electric generation was up
approximately 21 percent in 1997 over 1996. For the 1996 comparison period,
lower electric fuel costs resulted from less electric generation.  The fuel cost
adjustment clause has been eliminated effective July 1, 1996. Company
<PAGE>
 
                                       32

shareholders will assume the full benefits and detriments realized from actual
electric fuel costs and generation mix compared with PSC-approved forecast
amounts.

          The Company normally purchases electric power to supplement its own
generation when needed to meet load or reserve requirements, and when such power
is available at a cost lower than the Company's production cost.  Increased
availability and efficiencies following the 1996 installation of new steam
generators at the Ginna nuclear plant resulted in lower kilowatt-hour purchases
of electricity in 1997 which led to a decline in purchased electric power
expense.  Despite an increase in kilowatt-hours purchased in 1996, electric
purchased power expense was also down in 1996 reflecting, in part, lower
purchases from the higher-cost Kamine facility as discussed below.

          Under a contract with Kamine, the Company has been required to
purchase unneeded energy at uneconomical rates (see Note 10 of the Notes to
                                                         --                
Financial Statements).  The Company purchased 337 thousand megawatt-hours of
energy from Kamine at a total price of $16.6 million in 1995.  The Kamine
facility has been out of service since the middle of February 1996 which helped
to lower the unit cost for purchased electricity in 1996 compared to 1995.

          Energy Management and Costs - Gas.  The Company acquires gas supply
and transportation capacity based on its requirements to meet peak loads which
occur in the winter months.  The Company is committed to transportation capacity
on the Empire State Pipeline (Empire) and the CNG Transmission Corporation (CNG)
pipeline systems, as well as to upstream pipeline transportation and storage
services.  The combined CNG and Empire transportation capacity is adequate to
meet the Company's current requirements.

          For the 1997 comparison period, gas purchased for resale expense
declined driven by a reduced volume of purchased gas resulting from a warmer
heating season.  Higher commodity costs and increased volumes of purchased gas
caused an increase in gas purchased for resale expense in 1996 compared to 1995.

          Operations Excluding Fuel Expenses.  For the 1997 comparison period,
the increase in operations excluding fuel expenses reflects mainly higher
outside services expenses, recognition of obsolete and unproductive materials
inventory, storm costs, and regulatory compliance costs partially offset by
lower payroll costs and decreased expense associated with uncollectible
accounts. For the 1996 comparison period, the increase in operations excluding
fuel expenses reflects mainly higher payroll costs and an increase in
amortization expense beginning July 1, 1996 for customer information system
enhancements. Higher payroll costs for this period reflects amortization of
additional early retirement costs for programs concluded in October 1994 and
greater employee redeployment/outplacement costs.  An additional expense accrual
for doubtful accounts increased operating expenses by $15.0 million in 1995.

          The Company is continuing to take aggressive steps to improve its
collection efforts.  Uncollectible expense in 1997 was $18 million, compared
with $20 million in 1996. In 1995, uncollectible expense was $23 million.

          For both comparison periods, the increase in depreciation expense
reflects primarily results from depreciation of the new Ginna nuclear plant
steam generators (approximately $800,000 additional expense per month) and
recovery of increased nuclear decommissioning expense of approximately $3.2
million per quarter beginning July 1, 1996.

          Taxes Charged To Operating Expenses.  Local, state and other taxes
decreased in 1997 reflecting mainly lower property taxes due to decreases in
assessments and/or rates and lower revenue taxes due to decreases in revenues
and the New York State revenue tax surcharge rate.  The decrease in these taxes
for 1996 reflects mainly lower property taxes due to decreases in assessments.

          The decrease in federal income tax in 1997 reflects mainly the
reversal of a prior provision for the in-service date of Nine Mile Two as a
result of an agreement reached with the Internal Revenue Service.
<PAGE>
 
                                       33

          OTHER STATEMENT OF INCOME ITEMS.  For the 1996 comparison period, the
variation in non-operating federal income tax reflects mainly accounting
adjustments related to regulatory disallowances.

          Recorded under the caption Other Income and Deductions is the
recognition of regulatory disallowances in connection with the 1995 Gas
Settlement (see Rates and Regulatory Matters).

          Other (Income) and Deductions, Other--net decreased in 1997 due mainly
to recognition of expense associated with management performance awards and the
Company's Performance Stock Option Plan. For the 1996 comparison period, Other
(Income) and Deductions, Other -- net increased mainly due to the elimination in
1996 of two accrued expenses in 1995 related to depreciation expense for the
Empire State Pipeline and amortization of certain employee early retirement
costs.

          Both mandatory redemptions and the optional redemptions of certain
higher-cost long-term debt have helped to reduce long-term debt interest expense
over the three-year period 1995-1997.  Compared to the prior year, the average
short-term debt outstanding was up slightly in 1997 following a decrease in
1996.

          Preferred Stock dividends decreased in 1997 due to the Company's
discretionary redemption in April of its 7.50% Preferred Stock, Series N and the
mandatory sinking fund 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.
<PAGE>
 
                                       34

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


A.   FINANCIAL STATEMENTS

     Report of Independent Accountants

     Consolidated Statement of Income for each of the three years ended December
     31, 1997.

     Consolidated Statement of Retained Earnings for each of the three years
     ended December 31, 1997.

     Consolidated Balance sheet at December 31, 1997 and 1996.

     Consolidated Statement of Cash Flows for each of the three years ended
     December 31, 1997.

     Notes to Consolidated Financial Statements.

     Financial Statement Schedules:

     The following Financial Statement Schedule is submitted as part of Item 14,
     Exhibits, Financial Statement Schedules and Reports on Form 8-K, of this
     Report.  (All other Financial Statement Schedules are omitted because they
     are not applicable, or the required information appears in the Financial
     Statements or the Notes thereto.)

     Schedule II - Valuation and Qualifying Accounts.


B.   SUPPLEMENTARY DATA

     Interim Financial Data.
<PAGE>
 
                                       35


                       REPORT OF INDEPENDENT ACCOUNTANTS



To the Shareholders and
Board of Directors of
Rochester Gas and Electric Corporation


     In our opinion, the consolidated financial statements listed under Item 8A
in the index appearing on the preceding page present fairly, in all material
respects, the financial position of Rochester Gas and Electric Corporation and
its subsidiaries at December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements based
on our audits.  We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation.  We
believe that our audits provide a reasonable basis for the opinion expressed
above.



/s/ PRICE WATERHOUSE LLP
    PRICE WATERHOUSE LLP


Rochester, New York
January 23, 1998
<PAGE>
 
                                       36

CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>

(Thousands of Dollars)            Year Ended December 31    1997        1996        1995
--------------------------------------------------------- ---------  ----------  ----------
<S>                                                       <C>        <C>         <C>
Operating Revenues
  Electric                                                $679,473    $690,883    $696,582
  Gas                                                      336,309     346,279     293,863
                                                         ----------  ----------  ----------
                                                         1,015,782   1,037,162     990,445
  Electric sales to other utilities                         20,856      16,885      25,883
                                                         ----------  ----------  ----------

      Total Operating Revenues                           1,036,638   1,054,047   1,016,328
                                                         ----------  ----------  ----------

Operating Expenses
  Fuel Expenses
    Fuel for electric generation                            47,665      40,938      44,190
    Purchased electricity                                   28,347      46,484      54,167
    Gas purchased for resale                               196,579     202,297     167,762
                                                         ----------  ----------  ----------

      Total Fuel Expenses                                  272,591     289,719     266,119
                                                         ----------  ----------  ----------

Operating Revenues Less Fuel Expenses                      764,047     764,328     750,209

  Other Operating Expenses
    Operations excluding fuel expenses                     268,474     266,094     259,207
    Maintenance                                             46,635      47,063      49,226
    Depreciation and amortization                          116,522     105,614      91,593
    Taxes - local, state and other                         121,796     126,868     133,895
    Federal income tax                                      65,279      69,501      66,215
                                                         ----------  ----------  ----------

      Total Other Operating Expenses                       618,706     615,140     600,136
                                                         ----------  ----------  ----------

Operating Income                                           145,341     149,188     150,073

Other (Income) and Deductions
  Allowance for other funds used during construction          (351)       (684)       (585)
  Federal income tax                                        (3,704)     (3,450)    (16,948)
  Regulatory disallowances                                       -           -      26,866
  Other, net                                                 3,308        (712)      9,631

                                                         ----------  ----------  ----------
      Total Other (Income) and Deductions                     (747)     (4,846)     18,964

Interest Charges
  Long term debt                                            44,615      48,618      53,026
  Other, net                                                 6,676       9,328       9,056
  Allowance for borrowed funds used during construction       (563)     (1,423)     (2,901)

                                                         ----------  ----------  ----------
      Total Interest Charges                                50,728      56,523      59,181
                                                         ----------  ----------  ----------

Net Income                                                  95,360      97,511      71,928
                                                         ----------  ----------  ----------

Dividends on Preferred Stock                                 5,805       7,465       7,465
                                                         ----------  ----------  ----------

Earnings Applicable to Common Stock                        $89,555     $90,046     $64,463
                                                         ----------  ----------  ----------


Earnings per Common Share - Basic                            $2.30       $2.32       $1.69

Earnings per Common Share - Diluted                          $2.30       $2.32       $1.69
                                                         ==========  ==========  ==========
</TABLE>

CONSOLIDATED STATEMENT OF RETAINED EARNINGS

<TABLE>
<CAPTION>

(Thousands of Dollars)            Year Ended December 31    1997        1996        1995
--------------------------------------------------------- ---------  ----------  ----------
<S>                                                       <C>        <C>         <C>
Balance at Beginning of Period                             $90,540     $70,330     $74,566
Add
   Net Income                                               95,360      97,511      71,928
   Adjustment Associated with Stock Redemption                (846)          -           -
                                                         ----------  ----------  ----------
       Total                                               185,054     167,841     146,494
                                                         ----------  ----------  ----------

Deduct
   Dividends declared on capital stock
     Cumulative preferred stock - at required rates          5,805       7,465       7,465
     Common Stock                                           69,936      69,836      68,699
                                                         ----------  ----------  ----------
       Total                                                75,741      77,301      76,164
                                                         ----------  ----------  ----------

Balance at End of Period                                  $109,313     $90,540     $70,330
                                                         ==========  ==========  ==========


Cash Dividends Declared per Common Share                     $1.80       $1.80       $1.80
                                                         ==========  ==========  ==========
</TABLE>

The accompanying notes are an integral part of the financial statements.
<PAGE>
 
                                       37

<TABLE>
<CAPTION>

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)                                          At December 31     1997            1996
<S>                                                                            <C>              <C>
Assets
Utility Plant
Electric                                                                       $2,439,108       $2,413,881
Gas                                                                               416,989          391,231
Common                                                                            134,938          129,946
Nuclear fuel                                                                      243,042          224,701
                                                                              ------------     ------------
                                                                                3,234,077        3,159,759
Less: Accumulated depreciation                                                  1,510,074        1,381,908
          Nuclear fuel amortization                                               204,294          187,170
                                                                              ------------     ------------
                                                                                1,519,709        1,590,681
Construction work in progress                                                      74,018           69,711
                                                                              ------------     ------------
      Net Utility Plant                                                         1,593,727        1,660,392
                                                                              ------------     ------------

Current Assets
Cash and cash equivalents                                                          25,405           21,301
Accounts receivable, net of allowance for doubtful accounts:
  1997 - $ 26,926; 1996 - $ 17,502                                                104,781          112,908
Unbilled revenue receivable                                                        48,438           53,261
Materials, supplies and fuels                                                      39,929           39,888
Prepayments                                                                        23,818           23,103
                                                                              ------------     ------------
      Total Current Assets                                                        242,371          250,461
                                                                              ------------     ------------

Deferred Debits
Nuclear generating plant decommissioning fund                                  $  132,540       $   91,195
Nine Mile Two deferred costs                                                       30,309           31,360
Unamortized debt expense                                                           16,943           14,820
Other deferred debits                                                              20,411           28,759
Regulatory assets                                                                 231,988          284,489
                                                                              ------------     ------------
      Total Deferred Debits                                                       432,191          450,623
                                                                              ------------     ------------
      Total Assets                                                             $2,268,289       $2,361,476
                                                                              ============     ============

Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds                                                   485,434          555,054
               - promissory notes                                                 101,900           91,900
Preferred stock redeemable at option of Company                                    47,000           67,000
Preferred stock subject to mandatory redemption                                    35,000           45,000
Common shareholders' equity:
  Common stock                                                                    699,031          696,019
  Retained earnings                                                               109,313           90,540
                                                                              ------------     ------------
      Total Common Shareholders' Equity                                           808,344          786,559
                                                                              ------------     ------------
      Total Capitalization                                                      1,477,678        1,545,513
                                                                              ------------     ------------

Long Term Liabilities (Department of Energy)
  Nuclear waste disposal                                                           83,261           79,057
  Uranium enrichment decommissioning                                               13,465           14,695
                                                                              ------------     ------------
      Total Long Term Liabilities                                                  96,726           93,752
                                                                              ------------     ------------

Current Liabilities
Long term debt due within one year                                                 30,000           20,000
Preferred stock redeemable within one year                                         10,000           10,000
Short term debt                                                                    20,000           14,000
Accounts payable                                                                   53,195           49,462
Dividends payable                                                                  18,791           19,349
Taxes accrued                                                                       5,041            4,694
Interest accrued                                                                    8,593           10,317
Other                                                                              43,697           30,395
                                                                              ------------     ------------
      Total Current Liabilities                                                   189,317          158,217
                                                                              ------------     ------------

Deferred Credits and Other Liabilities
Accumulated deferred income taxes                                                 344,969          370,028
Pension costs accrued                                                              67,361           69,806
Other                                                                              92,238          124,160
                                                                              ------------     ------------
      Total Deferred Credits and Other Liabilities                                504,568          563,994
                                                                              ------------     ------------

Commitments and Other Matters                                                           -                -
                                                                              ------------     ------------
      Total Capitalization and Liabilities                                     $2,268,289       $2,361,476
                                                                              ============     ============
The accompanying notes are an integral part of the financial statements.

</TABLE>
<PAGE>
 
                                       38

ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>

(Thousands of Dollars)                  Year Ended December 31          1997          1996          1995
<S>                                                               <C>           <C>            <C>
CASH FLOW FROM OPERATIONS                                            
Net income                                                         $   95,360    $    97,511    $    71,928
Adjustments to reconcile net income to net cash provided                                        
  from operating activities:                                                                    
Depreciation and amortization                                         133,942        121,824        109,575
Deferred fuel                                                             489         (6,501)         3,432
Deferred income taxes                                                 (10,064)         6,391         (8,047)
Allowance for funds used during construction                             (914)        (2,107)        (3,486)
Unbilled revenue, net                                                   4,823         10,908         (9,899)
Stock option plan                                                       2,399             -              -
Nuclear generating plant decommissioning fund                         (20,331)       (11,732)        (8,837)
Pension costs accrued                                                  (3,398)        (2,494)         6,280
Post employment benefit internal reserve                                6,189          6,626          4,636
Regulatory disallowance                                                    -              -          26,866
Provision for doubtful accounts                                         5,078          4,987         14,893
Changes in certain current assets and liabilities:                                              
  Accounts receivable                                                   3,049          3,228        (25,599)
  Materials, supplies and fuels                                           (41)        (1,238)         6,837
  Taxes accrued                                                           347        (13,944)        15,167
  Accounts payable                                                      3,733         (3,116)         9,644
  Other current assets and liabilities, net                             7,344         (5,186)         9,639
Other, net                                                              6,847         (3,931)        28,762
                                                                   -----------   ------------   ------------
       Total Operating                                                234,852        201,226        251,791
                                                                   ===========   ===========    ===========
                                                                                                
CASH FLOW FROM INVESTING ACTIVITIES                                                             
Net additions to utility plant                                        (84,068)      (114,274)      (109,547)
Other, net                                                                 (1)         9,204         11,124
                                                                   -----------   ------------   ------------
       Total Investing                                                (84,069)      (105,070)       (98,423)
                                                                   ===========   ===========    ===========
                                                                                                
CASH FLOW FROM FINANCING ACTIVITIES                                                             
Proceeds from:                                                                                  
  Sale/Issuance of common stock                                           272          8,612         17,074
  Issuance of long term debt                                          101,900              -              -
  Short term borrowings, net                                            6,000         14,000        (51,600)
Retirement of long term debt                                         (151,568)       (67,332)        (1,000)
Retirement of preferred stock                                         (30,000)             -              -
Dividends paid on preferred stock                                      (6,366)        (7,465)        (7,465)
Dividends paid on common stock                                        (69,933)       (69,657)       (68,347)
Other, net                                                              3,016          2,866           (719)
                                                                   -----------   ------------   ------------
       Total Financing                                               (146,679)      (118,976)      (112,057)
                                                                   -----------   ------------   ------------
       Increase (Decrease) in cash and cash equivalents            $    4,104    $   (22,820)   $    41,311
       Cash and cash equivalents at beginning of year              $   21,301    $    44,121    $     2,810
                                                                   -----------   ------------   ------------
       Cash and cash equivalents at end of year                    $   25,405    $    21,301    $    44,121
                                                                   ===========   ===========    ===========
</TABLE>

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

<TABLE>
<CAPTION>

(Thousands of Dollars)                  Year Ended December 31          1997          1996          1995
<S>                                                                <C>           <C>           <C>
Cash Paid During the Year                                       
Interest paid (net of capitalized amount)                          $   50,681    $    55,545    $    56,592
Income taxes paid                                                  $   70,500    $    76,890    $    43,500
                                                                   ===========   ===========    ===========
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
 
                                       39

NOTES TO FINANCIAL STATEMENTS


Note 1.   SUMMARY OF ACCOUNTING PRINCIPLES

     GENERAL.  The Company supplies electric and gas services wholly within the
State of New York. It produces and distributes electricity and distributes gas
in parts of nine counties centering about the City of Rochester. The Company is
subject to regulation by the Public Service Commission of the State of New York
(PSC) under New York statutes and by the Federal Energy Regulatory Commission
(FERC) as a licensee and public utility under the Federal Power Act.  The
Company's accounting policies conform to generally accepted accounting
principles as applied to New York State public utilities giving effect to the
ratemaking and accounting practices and policies of the PSC.

     The preparation of 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
revenues 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.  The consolidated financial statements include
the accounts of the Company and its wholly-owned subsidiaries Roxdel (now
"Energetix") and Energyline.  All intercompany balances and transactions have
been eliminated.

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.

     The Roxdel (now "Energetix") activity is insignificant to the Company's
financial position and results of operation.

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

     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 in connection with a rate settlement agreement
with the PSC.

     In prior years, retail customers who used gas for spaceheating were subject
to a weather normalization adjustment to reflect the impact of variations from
normal weather on a billing month basis for the months of October through May,
inclusive.  On January 25, 1995, the Company suspended the weather normalization
adjustment in an effort to mitigate high billings due to the warm weather, and
the suspension became permanent. This decreased 1995 pre-tax earnings from gas
operations by $5.8 million.

     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.

     UTILITY PLANT, DEPRECIATION AND AMORTIZATION.  The cost of additions to
utility plant and replacement of retirement units of property is capitalized.
Cost includes labor, material, and similar items, as well as indirect charges
such as engineering and supervision, and is recorded at original cost.  The
Company capitalizes an Allowance for Funds Used During Construction (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 Statement of Income as
Allowance for Borrowed Funds Used During Construction, an offset to Interest
Charges, and
<PAGE>
 
                                       40

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, 1997.  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.

     CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of cash and
short-term commercial paper. These investments have original maturity not
exceeding three months. Such investments are stated at cost, which approximates
fair value, and are considered cash equivalents for financial statement
purposes.

     INVESTMENTS IN DEBT AND EQUITY SECURITIES.  The Company's accounting
policy, as prescribed by the PSC, with respect to its nuclear decommissioning
trusts is to reflect the trusts' assets at market value and reflect unrealized
gains and losses as a change in the corresponding accrued decommissioning
liability.

     GAS SUPPLY.  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 withdrawn from storage
and delivered to customers.

     RESEARCH AND DEVELOPMENT COST.  Research and Development costs were charged
to expense as incurred.  Expenditures for the years 1997, 1996, and 1995 were
$4.5 million, $4.9 million and $5.2 million respectively.

     ENVIRONMENTAL REMEDIATION COSTS.  The Company accrues for losses associated
with environmental remediation obligations when such losses are probable and
reasonably estimable.  Accruals for estimated losses from environmental
remediation obligations generally are recognized no later than completion 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.
Fuel inventories are valued at average cost.  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 withdrawn from storage and delivered to customers.

     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
approximates $1.0 million annually in 1996 and 1995, and approximates $8.2
million in 1997.  Additional information on the PSOP is included in Note 8.

     RECLASSIFICATIONS.  Certain amounts in the prior years' financial
statements were reclassified to conform with current year presentation.

     EARNINGS PER SHARE.  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 with 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 of common shares outstanding for the period.  Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue
<PAGE>
 
                                       41

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, 1997:

<TABLE>
<CAPTION>
                                Income          Shares         Per-Share
                              (Numerator)     (Denominator)      Amount
<S>                           <C>           <C>              <C>  
Basic EPS:
----------

Net Income                      $95,360
Less:

Preferred Stock Dividends        (5,805)

Income available to
    Common Shareholders          89,555         38,853           $2.30
                                                                 -----

Diluted EPS:
------------

Effect of Dilutive Securities
    Stock Option Plan                               56
                                                ------

Income available to
    Common Shareholders plus
    assumed conversions         $89,555         38,909           $2.30
                                                                 =====
</TABLE>

As there were no dilutive shares in prior years, basic and dilutive earnings per
share were the same for 1996 and 1995.
<PAGE>
 
                                       42

Note 2.  FEDERAL INCOME TAXES


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

<TABLE>
<CAPTION>
 
                                                (Thousands of Dollars)
 
                                               1997      1996       1995
<S>                                          <C>        <C>        <C>
Charged (Credited) to operating expense:
 Current                                     $69,812    $65,757   $ 65,368
 Deferred                                     (4,533)     3,744        847
                                             -------    -------   --------
  Total                                       65,279     69,501     66,215
 
Charged (Credited) to other income:
 Current                                       1,828     (6,097)    (9,996)
 Deferred                                     (3,100)     5,079     (4,520)
 Deferred investment tax credit               (2,432)    (2,432)    (2,432)
                                             -------    -------   --------
  Total                                       (3,704)    (3,450)   (16,948)
 
Total federal income tax expense             $61,575    $66,051   $ 49,267
 
</TABLE>

The following is a reconciliation of the difference between the amount of
federal income tax expense reported in the Consolidated Statement of Income and
the amount computed at the statutory tax rate of 35%.

<TABLE>
<CAPTION>
 
                                                    (Thousands of Dollars)
 
                                                   1997      1996       1995
<S>                                             <C>        <C>        <C>
Net Income                                      $ 95,360   $ 97,511   $ 71,928
Add:  federal income tax expense                  61,575     66,051     49,267
                                                --------   --------   --------
 
Income before federal income tax                $156,935   $163,562   $121,195
 
Computed tax expense at statutory tax rate      $ 54,927   $ 57,247   $ 42,418
Increases (decreases) in tax resulting from:
 Difference between tax depreciation
 and amount deferred                              10,772     10,796      7,197
 Deferred investment tax credit                   (2,432)    (2,432)    (2,432)
 Miscellaneous items, net                         (1,692)       440      2,084
 
Total federal income tax expense                $ 61,575   $ 66,051   $ 49,267
 
</TABLE>


     A summary of the components of the net deferred tax liability is as
follows:

<TABLE>
<CAPTION>

                                              (Thousands of Dollars)
                                              1997      1996       1995
<S>                                       <C>        <C>        <C>
 
Nuclear decommissioning                   $(20,807)  $(17,880)  $(14,797)
Accelerated depreciation                   216,704    213,907    197,952
Deferred investment tax credit              27,981     29,562     31,143
Depreciation previously flowed through     157,538    169,562    183,077
Pension                                    (23,166)   (24,570)   (24,241)
Other                                      (13,281)      (553)     4,518
                                          --------   --------   --------
 
Total                                     $344,969   $370,028   $377,652
</TABLE>
<PAGE>
 
                                       43


          SFAS-109 "Accounting for Income Taxes" requires that a deferred tax
liability must be recognized on the balance sheet for tax differences previously
flowed through to customers.  Substantially all of these flow-through
adjustments relate to property, plant and equipment and related investment tax
credits and will be amortized consistent with the depreciation of these
accounts.  The net amount of the additional liability at December 31, 1997 and
1996 was $160 million and $175 million, respectively.  In conjunction with the
recognition of this liability, a corresponding regulatory asset was also
recognized.
<PAGE>
 
                                       44

Note 3.  PENSION PLAN AND OTHER POST EMPLOYMENT BENEFITS


         The Company has a defined benefit pension plan covering substantially
all of its employees.  The benefits are based on years of service and the
employee's compensation. The Company's funding policy is to contribute annually
an amount consistent with the requirements of the Employee Retirement Income
Security Act and the Internal Revenue Code.  These contributions are intended to
provide for benefits attributed to service to date and for those expected to be
earned in the future.

         The plan's funded status and amounts recognized on the Company's
balance sheet are as follows:

<TABLE>
<CAPTION>
                                                   (Millions)

                                                 1997        1996
                                               --------    -------
<S>                                            <C>         <C>
Accumulated benefit obligation, including
 vested benefits of $384.7 in 1997 and
 $374.6 in 1996                                $ (404.0)*  $(392.6)*
                                               ========    =======
 
Projected benefit obligation for service
 rendered to date                              $ (499.3)*  $(480.2)*
 
Less: Plan assets at fair value, primarily
 listed stocks and bonds                          638.4      567.1
                                               --------    -------
 
Plan assets in excess of projected benefits       139.1       86.9
 
Unrecognized net loss (gain) from past
 experience different from that assumed
 and effects of changes in assumptions           (219.0)    (170.7)
 
Prior service cost not yet recognized in
 net periodic pension cost                         10.7       11.6
 
Unrecognized net obligation at December 31          1.8        2.4
                                               --------    -------
 
 Pension costs accrued                         $  (67.4)   $ (69.8)
                                               ========    =======
</TABLE>

* Actuarial present value.


Net pension cost included the following components:

<TABLE>
<CAPTION>
                                                            (Millions)

                                                      1997      1996     1995
                                                    --------  -------  -------
<S>                                                 <C>       <C>      <C>
Service cost - benefits earned during the period    $   6.2   $  7.4   $   6.0
Interest cost on projected benefit obligation          33.0     33.4      35.4
Actual return on plan assets                         (104.3)   (80.8)   (101.1)
Net amortization and deferral                          63.1     39.0      56.1
                                                    -------   ------   -------
Net periodic pension (credit) cost                  $  (2.0)  $ (1.0)  $  (3.6)
                                                    =======   ======   =======
</TABLE>

          The projected benefit obligation at December 31, 1997 and December 31,
1996 assumed discount rates of 6.75% and 7.25%, respectively, and a long-term
rate of increase in future compensation levels of 5.00%.  The assumed long-term
rate of return on plan assets was 8.50%.  The unrecognized net obligation is
being amortized over 15 years beginning January 1986.

          In addition to providing pension benefits, the Company provides
certain health care and life insurance benefits to retired employees and health
care coverage for surviving spouses of retirees.  Substantially all of the
Company's employees are eligible provided that they retire as employees of the
Company.  In
<PAGE>
 
                                       45

1997, the health care benefit consisted of a contribution of up to $200 per
retiree per month towards the cost of a group health policy provided by the
Company.  The life insurance benefit consists of a Basic Group Life benefit,
covering substantially all employees, providing a death benefit equal to one-
half of the retiree's final pay. In addition, certain employees and retirees,
employed by the Company at December 31, 1982, are entitled to a Special Group
Life benefit providing a death benefit equal to the employee's December 31, 1982
pay.

          SFAS-106, "Accounting for Postretirement Benefits Other than
Pensions", allows the Company to amortize the initial unrecognized, unfunded
Accumulated Postretirement Benefit Obligation at January 1992 estimated at $56
million over twenty years.  The Company intends to continue funding these
benefits as the benefit becomes due.


          The plan's funded status reconciled with the Company's balance sheet 
is as follows:
 
<TABLE>
<CAPTION>
                                                         (Millions)
                                                 
                                                       1997        1996
                                                     --------    -------
<S>                                                  <C>         <C>
Accumulated postretirement benefit obligation:
 Retired employees                                   $(73.9)      $(65.6)
 Active employees                                     (15.1)       (13.5)
                                                     ------       ------
                                                     $(89.0)      $(79.1) 
Less - Plan assets at fair value                        0.0          0.0
                                                     ------       ------
Accumulated postretirement benefit                           
 obligation (in excess of) less than                         
 fair value of assets                                 (89.0)       (79.1)
                                                             
Unrecognized net loss (gain) from past experience            
 different from that assumed and effects                     
 of changes in assumptions                              8.4          3.7
                                                             
Prior service cost not yet recognized in                     
 net periodic pension cost                              8.9          7.1
Unrecognized net obligation at December 31             39.5         42.3
                                                     ------       ------
                                                             
Accrued postretirement benefit cost                  $(32.2)      $(26.0)
                                                     ======       ======
</TABLE>

     Net periodic postretirement benefit cost included the following components:

 
<TABLE>
<CAPTION>
                                                         (Millions)
                                                 
                                                       1997        1996
                                                     --------     ------
<S>                                                  <C>          <C>
  
Service cost - benefits attributed to the period     $ 0.9        $ 1.0
Interest cost on accumulated postretirement                
 benefit obligation                                    5.8          5.4
Actual return on plan assets                           0.0          0.0
Net amortization and deferral                          3.5          4.2
                                                     -----        -----
  
 Net periodic postretirement benefit cost            $10.2        $10.6
                                                     =====        =====
 </TABLE>
 
          The Accumulated Postretirement Benefit Obligation at December 31, 1997
and 1996 assumed discount rates of 6.75% and 7.25%, respectively, and long-term
rate of increase in future compensation levels of 5.00%.

          SFAS-112, "Employers' Accounting for Postemployment Benefits",
requires the Company to recognize the obligation to provide postemployment
benefits to former or inactive employees after employment but before retirement.
The Company has been allowed to recover this cost in rates.
<PAGE>
 
                                       46

Note 4.  DEPARTMENTAL FINANCIAL INFORMATION


  The Company's records are maintained by operating departments, in accordance
with PSC accounting policies. The following is the operating data for each of
the Company's departments, and no interdepartmental adjustments are required to
arrive at the operating data included in the Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                        (Thousands of Dollars)
 
                                     1997       1996        1995
                                 ----------  ----------  ----------
<S>                              <C>         <C>         <C>
Electric
 
Operating Information
Operating revenues               $  700,329  $  707,768  $  722,465
Operating expenses, excluding
 provision for income taxes         516,793     521,222     523,105
                                 ----------  ----------  ----------
 
Pretax operating income             183,536     186,546     199,360
Provision for income taxes           61,837      61,901      59,500
                                 ----------  ----------  ----------
 
Net operating income             $  121,699  $  124,645  $  139,860
                                 ----------  ----------  ----------
 
Other Information
Depreciation and amortization    $  103,395  $   92,615  $   78,812
Nuclear fuel amortization        $   17,419  $   16,209  $   17,982
Capital expenditures             $   58,522  $   95,334  $   93,634
 
Investment Information,
 Identifiable assets (a)         $1,783,825  $1,877,224  $1,913,762
 

Gas
 
Operating Information
Operating revenue                $  336,309  $  346,279  $  293,863
Operating expenses, excluding
 provision for income taxes         309,225     314,136     276,935
                                 ----------  ----------  ----------
 
Pretax operating income              27,084      32,143      16,928
Provision for income taxes            3,442       7,600       6,715
                                 ----------  ----------  ----------
 
Net operating income             $   23,642  $   24,543  $   10,213
                                 ----------  ----------  ----------
 
Other Information
Depreciation                     $   13,127  $   12,999  $   12,781
Capital expenditures             $   25,546  $   18,940  $   15,913
 
Investment Information
 Identifiable assets (a)         $  441,849  $  447,865  $  477,758
</TABLE>

(a)  Excludes cash, unamortized debt expense, and other common items.
<PAGE>
 
                                       47

Note 5.    JOINTLY-OWNED FACILITIES


          The following table sets forth the jointly-owned electric generating
facilities in which the Company is participating.  Both Oswego Unit No. 6 and
Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are operated
by Niagara Mohawk Power Corporation.  Each participant must provide its own
financing for any additions to the facilities.  The Company's share of direct
expenses associated with these two units is included in the appropriate
operating expenses in the Consolidated Statement of Income.  Various
modifications will be made throughout the lives of these plants to increase
operating efficiency or reliability, and to satisfy changing environmental and
safety regulations.

<TABLE>
<CAPTION>
 
                                            Oswego     Nine Mile Point
                                          Unit No. 6  Nuclear Unit No. 2
                                          ----------  ------------------
<S>                                       <C>         <C>
 
Net megawatt capability (summer)               788          1,128
                                                            
RG&E's share - megawatts                       189            158
             - percent                          24             14
                                                            
Year of completion                            1980           1988
 
 
                                               (Millions of Dollars)
                                                 December 31, 1997
                                          ------------------------------
 
Plant In Service Balance                     $98.9         $879.3
Accumulated Provision For Depreciation       $41.4         $478.7
Plant Under Construction                     $ 0.6         $  3.3

</TABLE>

          The Plant in Service and Accumulated Provision for Depreciation
balances for Nine Mile Point Nuclear Unit No. 2 shown above include disallowed
costs of $374.3 million.  Such costs, net of income tax effects, were previously
written off in 1987 and 1989.
<PAGE>
 
                                       48

Note 6.  LONG-TERM DEBT
<TABLE>
<CAPTION>
 
 
FIRST MORTGAGE BONDS
 
                                                                          (Thousands of Dollars)
                                                                             Principal Amount
                                                                               December 31
 
  %                          Series                      Due                1997          1996
---------------------------  ----------------------      --------------   --------      --------
<S>                          <C>                         <C>              <C>           <C>
6 1/4                        W                           Sept. 15, 1997   $   -         $ 20,000
6.7                          X                           July 1, 1998       30,000        30,000
8.00                         Y                           Aug. 15, 1999        -           29,668
6 1/2                        EE                          Aug. 1, 2009         -           10,000
8 3/8                        OO/(a)/                     Dec. 1, 2028       25,500        25,500
9 3/8                        PP                          Apr. 1, 2021      100,000       100,000
8 1/4                        QQ/(b)/                     Mar. 15, 2002     100,000       100,000
6.35                         RR/(a)/                     May 15, 2032       10,500        10,500
6.50                         SS/(a)/                     May 15, 2032       50,000        50,000
7.00                         (b)(c)                      Jan. 14, 2000      30,000        30,000
7.15                         (b)(c)                      Feb. 10, 2003      39,000        39,000
7.13                         (b)(c)                      Mar. 3, 2003        1,000         1,000
7.64                         (c)                         Mar. 15, 2023      33,000        33,000
7.66                         (c)                         Mar. 15, 2023       5,000         5,000
7.67                         (c)                         Mar. 15, 2023      12,000        12,000
6.375                        (b)(c)                      July 30, 2003      40,000        40,000
7.45                         (c)                         July 30, 2023      40,000        40,000
                                                                          --------      --------
                                                                          $516,000      $575,668
Net bond discount                                                             (566)         (614)
Less: Due within one year                                                   30,000        20,000
                                                                          --------      --------
  Total                                                                   $485,434      $555,054
                                                                          ========      ========
</TABLE>

(a)  The Series OO, Series RR and Series SS First Mortgage Bonds equal the
     principal amount of and provide for all payments of principal, premium and
     interest corresponding to the Pollution Control Revenue Bonds, Series 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 MBIA Insurance Corporation.

(b)  The Series QQ First Mortgage Bonds and the 7%, 7.15%, 7.13% and 6.375%
     medium-term notes described below are generally not redeemable prior to
     maturity.

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

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

     Sinking and improvement fund requirements aggregate $333,540 per annum
under the First Mortgage, excluding mandatory sinking funds of individual
series. Such requirements may be met by certification of additional property or
by depositing cash with the Trustee. The 1997 and 1996 requirements were met
with funds deposited with the Trustee, and these funds were used for redemption
of outstanding bonds of Series Y.

     On May 1, 1997 the Company redeemed all its outstanding First Mortgage 8%
Bonds, Series Y, due August 15, 1999 and all its outstanding First Mortgage
6 1/4% Bonds, Series W, due September 15, 1997.  On October 15, 1997, the
Company redeemed all its outstanding First Mortgage 6 1/2% Bonds, Series EE.
<PAGE>
 
                                       49

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

<TABLE>
<CAPTION>
 
                      (Thousands of Dollars)
 
                  1998      1999      2000      2001      2002
                --------  --------  --------  --------  --------
<S>             <C>        <C>       <C>      <C>       <C>
Series X        $ 30,000
7% Series                           $ 30,000
Series QQ                                               $100,000
                --------  --------  --------  --------  --------
                $ 30,000  $   -     $ 30,000  $   -     $100,000
 
</TABLE>

PROMISSORY NOTES

<TABLE>
<CAPTION>
 
                                                (Thousands of Dollars)
                                                      December 31
Issued                    Due                      1997         1996
------                    ---                   --------      --------
<S>                       <C>                   <C>           <C>
November 15, 1984/(d)/    October 1, 2014        $  -         $51,700
December 5, 1985/(e)/     November 15, 2015         -          40,200
August 19, 1997/(f)/      August 1, 2032          101,900        -
                                                 --------     -------
Total                                            $101,900     $91,900
                                                 ========     =======
</TABLE>

(d)  The $51.7 million Promissory Note was issued in connection with NYSERDA's
     Floating Rate Monthly Demand Pollution Control Revenue Bonds (Rochester Gas
     and Electric Corporation Project), Series 1984.  On October 1, 1997, the
     Company redeemed all the outstanding Series 1984 Bonds.   The average
     interest rate was 3.43% through September 30, 1997, 3.38% for 1996 and
     3.68% for 1995.

(e)  The $40.2 million Promissory Note was issued in connection with NYSERDA's
     Adjustable Rate Pollution Control Revenue Bonds (Rochester Gas and Electric
     Corporation Project), Series 1985.  On November 15, 1997 the Company
     redeemed all the outstanding Series 1985 Bonds.  The annual interest rate
     was adjusted to 3.60% effective November 15, 1996 and to 3.75% effective
     November 15, 1995.

(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 rates by allowing for the interest rates to
     be based on a daily rate, a weekly rate, a commercial paper rate, an
     auction rate or a multi-year fixed rate.  Payment of the principal of, and
     interest on the Multi-mode Revenue Bonds is guaranteed under Bond Insurance
     Policies by MBIA Insurance Corporation.  At 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 3.65%.


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

     Based on an estimated borrowing rate at year-end 1997 of 6.62% for long-
term debt with similar terms and average maturities (13 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $655 million at December 31, 1997.
<PAGE>
 
                                       50

     Based on an estimated borrowing rate at year-end 1996 of 7.30% for long-
term debt with similar terms and average maturities (13 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $670 million at December 31, 1996.

     On September 16, 1997, the Company completed arrangements for the delivery
in September 1998 of $25.5 million of 5.95% NYSERDA tax-exempt bonds due
September 1, 2033. Proceeds are expected to be used to redeem the Series OO,
tax-exempt, first mortgage bonds which are not redeemable until December 1998.


Note 7.   PREFERRED AND PREFERENCE STOCK

<TABLE>
<CAPTION>
 
                                 Par      Shares      Shares
Type by Order of Seniority      Value   Authorized  Outstanding
------------------------------  -----   ----------  -----------
<S>                             <C>     <C>         <C>
Preferred Stock (cumulative)      $100   2,000,000    920,000*
Preferred Stock (cumulative)        25   4,000,000       -
Preference Stock                     1   5,000,000       -
</TABLE>

* See below for mandatory redemption requirements.

    No shares of preferred or preference stock are reserved for employees,
or for options, warrants, conversions, or other rights.


A.  PREFERRED STOCK, NOT SUBJECT TO MANDATORY REDEMPTION:

<TABLE>
<CAPTION>
 
                            Shares            (Thousands)        Optional
                         Outstanding          December 31,      Redemption
  %        Series      December 31, 1997    1997       1996     (per share) #
------     ------      -----------------  -------    -------    -------------
<S>        <C>         <C>                <C>        <C>        <C>
4            F              120,000       $12,000    $12,000        $105
4.10         H               80,000         8,000      8,000         101
4 3/4        I               60,000         6,000      6,000         101
4.10         J               50,000         5,000      5,000         102.5
4.95         K               60,000         6,000      6,000         102
4.55         M              100,000        10,000     10,000         101
7.50         N                 -             -        20,000         102
                            -------       -------    -------
Total                       470,000       $47,000    $67,000
                            =======       =======    =======
</TABLE>

# May be redeemed at any time at the option of the Company on 30 days minimum
  notice, plus accrued dividends in all cases.  The Series N were redeemed on
  April 22, 1997.

B.    PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:

<TABLE>
<CAPTION>
                            Shares            (Thousands)            Optional
                         Outstanding          December 31,          Redemption
  %        Series      December 31, 1997    1997       1996        (per share) #
------     ------      -----------------  -------    -------    ------------------
<S>        <C>         <C>                <C>        <C>        <C>
7.45         S                 -          $  -       $10,000    Not applicable
7.55         T              100,000        10,000     10,000    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                       450,000       $45,000    $55,000
Less: Due within one year   100,000        10,000     10,000
                            -------       -------    -------
Total                       350,000       $35,000    $45,000
                            =======       =======    =======
</TABLE>
+ Thereafter at $100.00
<PAGE>
 
                                       51

MANDATORY REDEMPTION PROVISIONS

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

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

          Series V.  The Series V is subject to a mandatory sinking fund
sufficient to redeem on each March 1 beginning in 2004 to and including 2008,
12,500 shares at $100 per share and on March 1, 2009, the balance of the
outstanding shares. The Company has the option to redeem up to an additional
12,500 shares on the same terms and dates as applicable to the mandatory sinking
fund.

          Based on an estimated dividend rate at year-end 1997 of 5.67% for
Preferred Stock, subject to mandatory redemption, with similar terms and average
maturities (5.92 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $48 million at December 31,
1997.

          Based on an estimated dividend rate at year-end 1996 of 6.50% for
Preferred Stock, subject to mandatory redemption, with similar terms and average
maturities (5.66 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $57 million at December 31,
1996.
<PAGE>
 
                                       52

Note 8.  COMMON STOCK AND STOCK OPTIONS

          In December 1997, the Board of Directors of the Company authorized the
repurchase of up to 4.5 million shares of the Company's Common Stock on the open
market.  None of the shares were purchased prior to year end.

          At December 31, 1997, there were 50,000,000 shares of $5 par value
Common Stock authorized, of which 38,862,347 were outstanding.  No shares of
Common Stock are reserved for warrants, conversions, or other rights.  There
were 1,445,141 shares of Common Stock reserved for employees under the 1996
Performance Stock Option Plan, as further described below.  There were 1,026,840
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 RG&E Savings Plus Plan.



COMMON STOCK

<TABLE>
<CAPTION>
                                               Shares               Amount
                                             Outstanding         (Thousands)
                                             -----------         -----------
<S>                                          <C>                 <C>
Balance, January 1, 1995                      37,669,963          $670,569
  Shares Issued through Stock Plans              783,200            17,074
 
  Decrease (Increase) in
  Capital Stock Expense                                               (125)
                                             -----------          --------
Balance, December 31, 1995                    38,453,163          $687,518
 
  Shares Issued through Stock Plans              398,301             8,612

  Decrease (Increase) in
  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, December 31, 1997                    38,862,347           699,031
</TABLE>

PERFORMANCE STOCK OPTION PLAN

          Effective January 22, 1997, the Company adopted 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 $5 par value
Common Stock to executive officers and other key employees.  No participant
shall be granted options for 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 (the Committee).  The Committee may in its sole
discretion grant the right to receive a cash payment upon any exercise of an
option equal to the quarterly dividend payment per share of Common Stock paid
from the date the option was granted to the date of exercise.

          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
<PAGE>
 
                                       53

at $25 per share, 50% at $30 per share, 75% at $35 per share, and 100% at $40
per share.

          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 FAS 123, compensation expense associated
with the options granted is reflected in 1997 net income.  For calendar 1997,
the compensation expense recorded was $2.4 million.  In applying FAS 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%, expected dividend yield of
9.44%, and expected stock volatility of 17%.


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

<TABLE>
<CAPTION>
 
 
                                                        Weighted
                                           Options    Average Price
                                          ----------  -------------
<S>                                       <C>         <C>
 
Options granted 1997                        554,859      $19.577
Options exercised                           (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
</TABLE>
<PAGE>
 
                                       54

Note 9.   SHORT-TERM DEBT


          On December 31, 1997, the Company had short-term debt outstanding of
$20.0 million.  At December 31, 1996 the Company had short-term debt outstanding
of $14.0 million. The weighted average interest rate in 1997 on short-term debt
outstanding at year end was 6.64% and was 6.07% for borrowings during the year.
The weighted average interest rate on short-term debt borrowed during 1996 was
5.86%.

          In December 1997 the Company's $90 million revolving credit agreement
was amended extending its term to five years, terminating December 31, 2002.
Commitment fees related to this facility amounted to $113,000 in 1997 and 1996,
and $165,000 in 1995.

          The Company's Charter provides that the Company may not issue
unsecured debt if immediately after such issuance the total amount of unsecured
debt outstanding would exceed 15 percent of the Company's total secured
indebtedness, capital, and surplus without the approval of at least a majority
of the holders of outstanding Preferred Stock.  As of December 31, 1997, the
Company would be able to incur approximately $103.8 million of additional
unsecured debt under this provision.  The Company has unsecured lines of credit
totaling $27 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 otherwise 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 $10 million for the exclusive
purpose of financing Federal Energy Regulatory Commission Order 636 transition
costs(636 Notes) and 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.

          At December 31, 1997, borrowings outstanding were $4.34 million of 636
Notes (recorded on the Balance Sheet as a liability under Deferred Credits and
Other Liabilities).
<PAGE>
 
                                       55

Note 10.  COMMITMENTS AND OTHER MATTERS


COMPETITION


          OVERVIEW.  The PSC, through its Competitive Opportunities Proceeding,
has embarked on a fundamental restructuring of the electric utility industry in
the state.  Among other elements, the PSC's goals included lower rates for
consumers and increased customer choice in obtaining electricity and other
energy services. During 1996 and 1997, the Company, the Staff of the PSC, and
several other parties negotiated a Settlement Agreement (the "Settlement") which
was approved by the PSC in November 1997.  The Settlement sets the framework for
the introduction and development of open competition in the electric energy
marketplace.


          PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT.  The Settlement
provides for a transition to competition during its five year term (July 1, 1997
to June 30, 2002) and establishes the Company's electric rates for each annual
period.  A Retail Access Program will be phased in, allowing customers to
purchase electricity, and later electricity and capacity commitments, from
sources other than the Company.   The Company will be given a reasonable
opportunity to recover prudently incurred costs, including those pertaining to
generation and purchased power.  The Settlement also requires the Company to
functionally separate its component operations: distribution, generation, and
retailing.  Any unregulated retail operations must be structurally separate from
the regulated utility functions but may be funded with up to $100 million.
Although the Settlement provides incentives for the sale of generating assets,
it requires neither divestiture of generating or other assets nor write off of
stranded costs.  The Company believes that the Settlement will not adversely
affect its eligibility to continue to apply SFAS 71 with the exception of
certain to-go costs associated with non-nuclear generation.  If, contrary to the
Company's view, such eligibility were adversely affected, a material write-down
of assets, the amount of which is not presently determinable, could be required.

          Rate Plan.   Over the five year term of the Settlement, cumulative
rate reductions will be: Rate Year 1: $3.5 million; Rate Year 2: $12.8 million;
Rate Year 3: $27.6 million; Rate Year 4: $39.5 million; and Rate Year 5: $64.6
million.  The Rate Plan permits the Company to offset against the foregoing
reductions certain inflation-related expenses and certain amounts related to a
purchase power agreement with Kamine.  In the event that the Company earns a
return on common equity in excess of 11.50% over the entire five year term of
the Settlement, 50% of such excess will be used to write down deferred costs
accumulated during the term, and 50% will be used to write down accumulated
deferrals or investment in electric plant or regulatory assets.

          Retail Access.   The Company's Energy Choice Program will be available
to all of its customers on an equal basis up to certain usage caps.  On July 1,
1998, customers whose electric loads represent approximately 10% of the
Company's total annual retail sales will be eligible to purchase electricity
(but not capacity commitments) from alternative suppliers.  On July 1, 1999, the
percent of total sales moves to 20%, and customers would purchase both
electricity and capacity commitments.  On July 1, 2000, the percent moves to
30%, and on July 1, 2001, all retail customers will be eligible to purchase
energy and capacity from alternative suppliers.

          During the initial, energy only stage of the Retail Access Program,
the Company's distribution rate will be set by deducting 2.3 cents per kilowatt
hour ("KWH") from its full service ("bundled") rates and Load Serving Entities
acting as retailers in the Company's service area will be entitled to purchase
electricity from the Company at a rate of 1.9 cents per KWH.  During the energy
and capacity stage, the rate will generally equal the bundled rate less the cost
of the electric commodity and the Company's non-nuclear generating capacity.
These commodity and capacity costs, generally referred to as "contestable
costs," are estimated to be 3.2 cents per KWH, inclusive of gross receipts
taxes.

          Generating Assets.   The Company will not be required to divest any of
its generation facilities.  To the extent that the Company sells any generating
<PAGE>
 
                                       56

assets  during the term of the Settlement, gains on such sales will be shared
between the Company and customers.  With regard to losses on such sales, the
Settlement acknowledges an intent that the Company will be permitted to recover
such losses through distribution rates during the term of the Settlement.
Future rate treatment is to be consistent with the principle that the Company is
to have a reasonable opportunity to recover such costs.

          "To-go costs" of the Company's non-nuclear resources (i.e., capital
costs incurred after February 28, 1997, operation and maintenance expenses, and
property, payroll and other taxes) are to be initially recovered through
distribution rates.  The fixed portion of to-go costs would be recovered in full
until July 1, 1999, and be subject to the market thereafter in accordance with
the phase-in schedule for the Retail Access program.  The variable portion of
non-nuclear to-go costs would also be subject to the market in accordance with
the phase-in schedule.  Under the Settlement, nuclear costs would remain
recoverable through regulated rates.

          Miscellaneous.   The present Settlement supersedes the 1996 Rate
Settlement.  Various incentive and penalty provisions in the 1996 Rate
Settlement are eliminated.


          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 utilities' transition
plans for moving to more competitive environments and provided guidance on when
utilities with transition plans will need to discontinue the application of
SFAS-71, "Accounting for the Effects of Certain Types of Regulation".

          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 (including stranded costs) and liabilities of the
separable portion of the business that is discontinuing the application 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.

          The 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 liabilities 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".
As noted previously, the fixed portion of the non-nuclear generation 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 SFAS-71. The Company's net investment at December 31, 1997 in
nuclear generating assets is $698.4 million and in non-nuclear generating assets
is $122.0 million.


REGULATORY AND STRANDABLE ASSETS

          With PSC approval the Company has deferred certain costs rather than
recognize them on its books when incurred.  Such deferred costs are then
recognized as expenses when they are included in rates and recovered from
customers.  Such deferral accounting is permitted by SFAS-71.  These deferred
costs are shown as Regulatory Assets on the Company's Balance Sheet.  Such cost
<PAGE>
 
                                       57

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 not 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,
1997 and 1996:

<TABLE>
<CAPTION>
 
                                                 (Millions of Dollars)
                                                    1997      1996
                                                  -------    -------
<S>                                                <C>       <C>
Income Taxes                                       $159.6    $174.6
Uranium Enrichment Decommissioning Deferral          16.4      17.7
Deferred Ice Storm Charges                           11.5      14.0
FERC 636 Transition Costs                            11.0      32.3
Demand Side Management Costs Deferred                 4.4       8.4
Gas Deferred Fuel                                     7.1       7.7
Other, net                                           22.0      29.8
                                                   ------    ------
Total - Regulatory Assets                          $232.0    $284.5
                                                   ======    ======
</TABLE>

-  Income Taxes:  This amount represents the unrecovered portion of tax
   benefits from accelerated depreciation and other timing differences which
   were used to reduce tax expense in past years.  The recovery of this
   deferral is anticipated over the remaining life of the related property
   when the effect of the past deductions reverses in future years.

-  Uranium Enrichment Decommissioning Deferral:  The Energy Policy Act of 1992
   requires utilities to contribute such amounts based on the amount of
   uranium enriched by DOE for each utility.  This amount is mandated to be
   paid to DOE through the year 2007.  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 following the March 1991 ice storm.  The recovery of
   these costs has been approved by the PSC through the year 2002.

-  FERC 636 Transition Costs:   These costs are payable to gas supply and
   pipeline companies which are passing various restructuring and other
   transition costs on to the Company, as ordered by FERC.  The majority of
   these costs will be recovered through the Company's gas cost adjustment by
   the year 2000.

-  Demand Side Management Costs Deferred:  These costs are Demand Side
   Management costs which relate to programs initiated to increase efficiency
   with which electricity is used.  These costs are recoverable by the Company
   through the year 2002.

-  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 customers during a
   subsequent period.

     In a competitive electric market, strandable assets would arise 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 (e.g., the Kamine/Besicorp Allegany L.P.
contract), or
<PAGE>
 
                                       58

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, 1997 depends 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 to
strandable assets.  Regulatory developments discussed under " GAS RESTRUCTURING
PROCEEDING," 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, 1997 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 does not impair
the opportunity of the Company to recover its investment in these assets.
However, the PSC has published a Staff paper to address issues surrounding
nuclear generation, including the determination of fair market value for
facilities after a five year restructuring transition period.  It appears that
the PSC may seek to apply similar principles to other types of generating
facilities. A determination in this proceeding could have an impact on
strandable assets.


CAPITAL EXPENDITURES


     The Company's 1998 construction expenditures program is currently estimated
at $124 million.  The Company has entered into certain commitments for purchase
of materials and equipment in connection with that program.


NUCLEAR-RELATED MATTERS


     DECOMMISSIONING TRUST. The Company is collecting amounts in its electric
rates for the eventual decommissioning of its Ginna Plant and for its 14% share
of the decommissioning of Nine Mile Two.  The operating licenses for these
plants expire in 2009 and 2026, respectively.

     Under accounting procedures approved by the PSC, the Company has collected
decommissioning costs of approximately $116.1 million through December 31, 1997
and is authorized to collect approximately $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 estimates 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 share.   Since 1990, the Company has
contributed $86.4 million to this fund and, including realized and unrealized
investment returns, the fund has a balance of $132.5 million as of December 31,
1997.  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, 1997 is $29.7 million.

     The NRC is currently considering proposals which may impact financial
funding requirements for decommissioning of nuclear power plants.  Under current
<PAGE>
 
                                       59

NRC regulations electric utilities provide for decommissioning funds annually
over the estimated life of a plant. If state regulatory authorities were to
adopt a program to remove electric generation (including nuclear plants) from
cost-based rate regulation, an action which the New York PSC is currently
considering, such plants would operate in a competitive electric market and
would have no assured source of revenue from energy sales.  Under current
regulations, the NRC can require the owners of nuclear plants lacking such
assured revenue streams to provide assurance that the full estimated cost of
decommissioning will ultimately be available through some guarantee mechanism.

     The NRC is seeking public comment on a number of questions, including the
likely timetable for utility restructuring and deregulation and to what extent
costs will be recoverable if a large baseload plant is deemed to be non-
competitive because of high construction costs and what funding sources will be
used to shut down a plant prematurely and safely.

     The NRC has released for comments a notice of proposed rulemaking (NOPR)
modifying certain aspects of the financial assurance requirements for
decommissioning nuclear power reactors.  The NOPR includes, among other things,
changes to the definition of "electric utility" for the purposes of providing
financial assurance for decommissioning as well as new reporting requirements
regarding each licensee's progress on external funding.  The Company does not
anticipate a material impact from the application of these rules in their
proposed form; however it cannot predict the impact of these rules as resolution
of stranded asset issues proceed in New York.

     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 could compete with other forms of generation.
In Fall 1997, the Company and others commented on these and other facets of the
report. Through mid-January 1998, the PSC had taken no action on the report and
comments.

     The Staff of the Financial Accounting Standards Board are studying the
recognition, measurement and classification of decommissioning costs for nuclear
generating stations in the financial statements of electric utilities.  If
current accounting practices for such costs were changed, the annual provisions
for decommissioning costs 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 accounts could be increased
and trust fund income from the external decommissioning trusts could be reported
as investment income rather than as a reduction to decommissioning expense.

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


     URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND.  Under the
National Energy Act, utilities with nuclear generating facilities are assessed
an annual fee payable over 15 years for the decommissioning of federally owned
uranium enrichment facilities.  The assessments for Ginna and the Company's
share of Nine Mile Two are estimated to total $22.1 million, excluding inflation
and interest. Installments aggregating approximately $9.4 million have been paid
through 1997.  A liability has been recognized on the financial statements along
with a corresponding regulatory asset.  For the two facilities the Company's
liability at December 31, 1997 is $15.1 million ($13.4 million as a long-term
liability and $1.7 million as a current liability). The Company is recovering
costs through base rates of fuel.

     In July 1996, the Company joined other utilities in a civil action against
the U.S. Department of Energy (DOE), concerning these assessments.  After a
favorable initial decision in a parallel case, the Court of Appeals for the
Federal Circuit in May 1997 reversed the lower court and held that the federal
<PAGE>
 
                                       60

government could assess licensees for the clean-up of these federal facilities.
In January 1998, the U.S. Supreme Court refused to hear the case, effectively
upholding the dismissal of the utility claims.


     NUCLEAR FUEL DISPOSAL COSTS.  The Nuclear Waste Policy Act (Nuclear Waste
Act) of 1982, as amended, requires the DOE to establish a nuclear waste disposal
site and to take title to nuclear waste.  A permanent DOE high-level nuclear
waste repository is not expected to be operational before the year 2010.  The
DOE is proposing to establish an interim storage facility which may allow it to
take title to and possession of nuclear waste prior to the establishment of a
permanent repository.  In December 1996 the DOE notified the Company that the
DOE will not start acceptance of Ginna spent fuel in 1998.  In January 1997 the
DOE released a draft request for proposal outlining a process for private firms
to accept and transport waste from reactors until a federal facility is
operational. 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 $83.3 million at December 31, 1997.  The Company
is allowed by the PSC to recover these costs in rates.  The estimated fees are
classified as a long-term liability and interest is accrued at the current
three-month Treasury bill rate, adjusted quarterly.  The Nuclear Waste Act also
requires the DOE to provide for the disposal of nuclear fuel irradiated after
April 6, 1983, for a charge of approximately one mill ($.001) per KWH of nuclear
energy generated and sold.  This charge (approximately $3.6 million per year) is
currently being collected from customers and paid to the DOE pursuant to PSC
authorization.  The Company expects to utilize on-site storage for all spent or
retired nuclear fuel assemblies until an interim or permanent nuclear disposal
facility is operational.

     There are presently no facilities in operation in the United States
available for the reprocessing of spent nuclear fuel from utility companies.  In
the Company's determination of nuclear fuel costs it has taken into account that
nuclear fuel would not be reprocessed and has provided for disposal costs in
accordance with the Nuclear Waste Act.  The Company has completed a conceptual
study of alternatives to increase the capacity for the interim storage of spent
nuclear fuel at the Ginna Plant.  The preferred alternative, based on cost and
safety criteria, is to install high-capacity spent fuel racks in the existing
area of the spent fuel pool.  The additional storage capacity, scheduled to be
implemented prior to September 2000, would allow interim storage of all spent
fuel discharged from the Ginna Plant through the end of its Operating License in
the year 2009.


ENVIRONMENTAL MATTERS


     The following tables list various sites where past waste handling and
disposal has or may have occurred that are discussed below:
 
 
TABLE I - COMPANY-OWNED SITES

<TABLE>
<CAPTION>
 
                                            Estimated
      Site Name         Location            Company Cost
      -------------     ---------------     ---------------------
      <S>               <C>                 <C>
      West Station*     Rochester, NY       Ultimate costs have
      East Station      Rochester, NY       not been determined.
      Front Street*     Rochester, NY       The Company has
      Brewer Street     Rochester, NY       incurred aggregate
      Brooks Avenue     Rochester, NY       costs for these sites
      Canandaigua       Canandaigua, NY     through December 31,
                                            1997 of $4.3 million.
</TABLE>

* Voluntary agreement signed.
<PAGE>
 
                                       61


TABLE II - SUPERFUND AND NON-OWNED OTHER SITES

<TABLE>
<CAPTION>
 
                                                   Estimated
      Site Name                Location            Company Cost
      -------------            ---------------     ---------------------
      <S>                      <C>                 <C>
      Quanta Resources*        Syracuse, NY        Ultimate costs have
      Frontier Chemical-                           not been determined.
        Pendleton*             Pendleton, NY       The Company has
      Maxey Flats*             Morehead, KY        incurred aggregate
      Mexico Milk              Mexico, NY          costs for these sites
      Byron Barrel and Drum    Bergen, NY          through December 31,
      Fulton Terminals*        Oswego, NY          1997 of less than $1.0
      PAS of Oswego*           Oswego, NY          million.
</TABLE>

* Orders on consent signed.


          COMPANY-OWNED WASTE SITE ACTIVITIES.  As part of its  commitment to
environmental excellence, the Company is conducting proactive Site Investigation
and/or Remediation (SIR) efforts at six Company-owned sites where past waste
handling and disposal may have occurred.  Remediation activities at four 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
total liability of approximately $13.6 million, $12.8 million of  which it
anticipates spending on SIR efforts at the six Company-owned sites listed in
Table I above.  Concurrently, the Company recorded a similar amount in its
Regulatory Assets.

          In mid-1995, the New York State Department of Environmental
Conservation (NYSDEC) developed a listing of sites called "The Hazardous
Substance Site Inventory".  Under current New York State law, unless a site,
which is determined to pose a public health or environmental risk, contains
hazardous wastes, State "Superfund" monies cannot be used to assist in the
cleanup.  The State wanted to have some sense of the scale of this problem
before the legislature considered other avenues of legal and financial redress
than those currently available.  The NYSDEC's "Hazardous Substance Waste
Disposal Site Study"  was developed to assess the number of and cost to
remediate sites where hazardous chemicals, but not hazardous wastes are present.
Of the six Company-owned sites listed in Table I above, three are listed in this
inventory.  These are East Station, Front Street and Brooks Avenue.  In addition
to these three sites, the inventory includes Ambrose Yard and Lindberg Heat
Treating.  The Company does not believe that additional SIR work for which the
Company is responsible is required at either site, however the Company is unable
to predict what action will be necessitated as a result of the listing.

          The Company and its predecessors formerly owned and operated three
manufactured gas facilities in the Rochester area.  They are included in Table
I. Cleanup activities which were previously suspended, resumed on a portion of
the West Station site and were concluded in July 1996 under a voluntary
agreement with the NYSDEC.  The Company received  release from future liability
and a covenant not to sue from the NYSDEC for this work.  There remain other
portions of the property where additional remedial work is expected, however,
only a preliminary scope and schedule have been determined.  At the second of
the three manufactured gas plant sites known as East Station, an interim
remedial action was undertaken in late 1993.  Ground water monitoring wells were
also installed to assess the quality of the ground water at this location.  The
Company has informed the NYSDEC of the results of the samples taken.  Subsequent
data evaluation indicate a wider array of potential sources of coal gasification
related materials than previously thought suggesting significant remedial work
may be required.

          At the third Rochester area property owned by the Company (Front
Street) where gas manufacturing took place, a boring placed in the Fall of 1988
for a
<PAGE>
 
                                       62

sewer system project showed a layer containing a black viscous material.  The
study of the layer found that some of the soil and ground water on-site had been
adversely impacted.  The matter was reported to the NYSDEC and, in September
1990, the Company also provided the agency with a risk assessment.  The report
of the results of this study and the NYSDEC's response to the recommendations
made therein will influence the future remediation costs.  The Company has
signed a voluntary agreement to perform limited additional investigation at the
site to determine whether certain remedial actions are necessary prior to
development.

          Another property owned by the Company where gas manufacturing took
place is located in Canandaigua, New York. Limited investigative work performed
there during the summer of 1995 has shown evidence of both the former gas
manufacturing operations and leakage from fuel tanks.  The NYSDEC was informed;
the fuel tanks removed; and additional investigative work continues.  The SIR
costs associated with these actions are included in Table I.  The NYSDEC has not
taken any action against the Company as a result of these findings.

          On another portion of the Company's property (Brewer Street), the
County of Monroe has installed and operates sewer lines.  During sewer
installation, the County constructed over Company property certain retention
ponds which reportedly received from the sewer construction area certain fossil-
fuel-based materials (the materials) found there.  In July 1989, the Company
received a letter from the County asserting that activities of the Company left
the County unable to effect a regulatorily-approved closure of the retention
pond area.  The County's letter takes the position that it intends to seek
reimbursement for its additional costs incurred with respect to the materials
once the NYSDEC identifies the generator thereof and that any further cleanup
action which the NYSDEC may require at the retention pond site is the Company's
responsibility. In a November 1997 letter, the County has claimed that the
Company was the original generator of the materials.  It asserts that it will
hold the Company liable for 50% of all County costs -- presently estimated at a
total of approximately $5 million -- associated both with the materials'
excavation, treatment and disposal and with effecting a regulatorily-approved
closure of the retention pond area.  The Company could incur costs as yet
undetermined if it were to be found liable for such closure and materials
handling, although provisions of an existing easement afford the Company rights
which may serve to offset all or a portion of any such County claim.  To date,
the Company has agreed to pay a 20% share of the County's 1995 investigation of
this area, which is estimated to cost no more than $150,000, but no commitment
has been made toward any subsequent investigations or remedial measures which
may be recommended by the investigations.

          Monitoring wells installed at another Company facility (Brooks Avenue)
in 1989 revealed that an undetermined amount of leaded gasoline had reached the
ground water.  The Company has continued to monitor free product levels in the
wells, and has begun a modest free product recovery project.  It is estimated
that further investigative work into this problem may cost up to $100,000.
While the cost of corrective actions cannot be determined until investigations
are completed, preliminary estimates are not expected to exceed $500,000.


          SUPERFUND AND NON-OWNED OTHER SITES.  The Company has been or may be
associated as a potentially responsible party (PRP) at seven sites not owned by
it.  The Company has signed orders on consent for five of these sites and
recorded estimated liabilities totaling approximately $.8 million.

          In one site, known as the Quanta Resources Site, the Company signed a
consent order with the Environmental Protection Agency (EPA) and paid its
$27,500 share of remedial cost.  The Company was again contacted by EPA in late
August, 1996.  The EPA informed the Company that it believed certain additional
work was required, including a study to determine the extent to which additional
removal of waste materials was required.  The EPA's list of PRPs had grown to
about 80. The Company, along with most of those PRPs, has agreed (through an
Administrative Order on Consent) to conduct the required study.  The Company
anticipates its obligation through this phase will be less than $10,000.  On May
12, 1997, the Company signed an Administrative Order on Consent with the NYSDEC.
This agreement served to obligate the respective parties to pay NYSDEC's past
costs at the Site, the Company's share of which was determined to be $1,500.
There is as yet, no information on which to determine the cost to design and
conduct at the
<PAGE>
 
                                       63

site any remedial measures which federal or State authorities may require, the
Company does not expect its additional costs to exceed $150,000.

          On May 21, 1993, the Company was notified by NYSDEC that it was
considered a PRP for the Frontier Chemical Pendleton Superfund Site located in
Pendleton, NY.  The Company has signed, along with other participating parties,
an Administrative Order on Consent with NYSDEC.  The Order on Consent obligates
the parties to implement a work plan and remediate the site.  The PRPs have
negotiated a work plan for site remediation and have retained a consulting firm
to implement the work plan.  Preliminary estimates indicate the Company's share
of additional site remediation costs are not expected to exceed $350,000.  The
Company is participating with the group to allocate costs among the PRPs.
Subsequent work has indicated that the final cost is likely to be lower.

          The Company is involved in the investigation and cleanup of the Maxey
Flats Nuclear Disposal Site in Morehead, Kentucky and has signed various consent
orders to that effect.  The Company has contributed to a study of the site and
estimates that its share of the additional costs of investigation and
remediation is not expected to exceed $250,000.

          The Company has been named as a PRP at three other sites and has been
associated with another site for which the Company's share of total additional
projected costs is not expected to exceed $71,000.  Actual Company expenditures
for these sites are dependent upon the total cost of investigation and
remediation and the ultimate determination of the Company's share of
responsibility for such costs as well as the financial viability of other
identified responsible parties.


          FEDERAL CLEAN AIR ACT AMENDMENTS. The Company is developing strategies
responsive to the federal clean air act amendments of 1990 (Amendments) which
will primarily affect air emissions from the Company's fossil-fueled generating
facilities.  The strategy being developed is a combination of hardware solutions
which have a capital and operation and maintenance (O&M) component and allowance
trading solutions which have strictly an O&M impact.  The most recent strategic
developments still envision this combination of efforts as the most cost
effective means of proceeding although State legislative activity could impact
the Company's ability to rely upon the emission allowance market to meet some of
its environmental commitments. The Company cannot predict the outcome of these
proceedings in the Legislature and, as a result, the Company's projections are
based solely on the combination strategy.  A range of capital costs between $2.9
and $3.5 million has been estimated for the implementation of several potential
alterations for meeting the foreseeable nitrogen oxide, opacity and sulfur
dioxide requirements of the Amendments, as well as $1.0 to $1.5 million per year
in operating expenses.  These capital costs would be incurred between 1998 and
2000.  The O&M expenses would be for the year 1999.  For the year 2000 and
beyond, the Company estimates that the annual operating expenses would rise to
between $2.4 million and $3.7 million.  Any additional post-2000 capital costs
and operating expense cannot be predicted until resolution of State and federal
legislative activity enables the Company to finalize its compliance strategy.


          OPACITY ISSUE.  In May 1997, the Company commenced negotiations with
the NYSDEC to resolve allegations of past opacity violations at the Company's
Beebee and Russell Stations.  The opacity standard is a regulation which limits
the density of the smoke emitted from the Stations' smokestacks.  The Company
believes that it will reach an agreement with NYSDEC on this issue and that the
amount of any civil penalty will likely include both cash and environmental
benefit project components which, in the aggregate, will not be material. In
addition, the Stations have been temporarily derated since February 1997 to
maintain acceptable opacity levels while the Company investigates additional
engineering solutions to address opacity emissions.  The financial impact of the
deratings includes the lost opportunity associated with energy sales and, at
times, the need to make additional purchases to meet system requirements.  While
the deratings have decreased earnings, and will continue to do so, the Company
does not expect the amount to be material.  Finally, the New York Power Pool
(NYPP) is in the process of evaluating new rules for its system load regulation.
The current Station deratings for opacity reasons would reduce the ability of
the Company to react to changes in load and provide regulation services when
called
<PAGE>
 
                                       64

upon by the NYPP, resulting in additional costs.  Depending on the new NYPP
requirements, and whether the deratings remain in effect, the revised rules
could result in the Company having to purchase additional regulation services
which may cost between $500,000 and $2,500,000 annually.


GAS COST RECOVERY


          GAS RESTRUCTURING PROCEEDING. In the PSC's Proceeding on Restructuring
the Emerging Competitive Natural Gas Market, the PSC established a three-year
period (ending March 28, 1999) during which the State's local distribution
companies (LDCs) would be permitted to require customers converting from sales
service to take associated pipeline capacity for which the LDCs had originally
contracted. Prior to the beginning of the third year, the LDCs would be required
to demonstrate their efforts to dispose of "excess" capacity.  On September 4,
1997, the PSC issued an Order clarifying the March 28, 1996 Order.  The
September 4 Order requires, among other things, that the LDCs (a) assess
strandable costs; (b) evaluate and pursue options to address strandable costs,
including exploration of alternative uses and quantification of market values
for the capacity that could be stranded by converting customers; (c) actively
encourage competition including collaboration with marketers to expand the
number of customers taking transportation service from the LDC and to provide
customer education; and (d) to the extent LDCs cannot shed all their capacity as
contracts expire, to continue to seek lower cost options and more flexibility
and shorter contract terms, where cost-effective.  LDCs are required to file
plans addressing the foregoing issues by April 1, 1998.  Pursuant to the PSC's
orders, the cost of capacity defined as "excess" may not be fully recoverable in
rates.  Accordingly, the Company's ability to avoid absorbing this cost will
depend on the success of remarketing and portfolio structuring efforts and, if
such efforts do not result in eliminating all "excess" capacity, on a
satisfactory explanation as to why all such capacity could not be eliminated.
The Company is engaged in negotiations with the Staff of the PSC and other
parties to address these and other issues related to the future provision of gas
service. At this time, no assessment of the potential impact of these
requirements on the Company can be made.

          On September 4, 1997, the PSC also issued for comment a Staff position
paper which proposes that LDCs exit their merchant function, i.e., cease to
supply the natural gas commodity to their existing customers, within five years
and that they eliminate or restructure transportation and storage capacity
contracts extending beyond five years so as to eliminate obligations beyond that
point, except where capacity is required to fulfill operational requirements or
the LDC's obligations as the "supplier of last resort" to customers having no
competitive alternative.  If adopted by the PSC, the Staff proposal could
require the Company to remarket more capacity and to do so more rapidly than
currently contemplated.  The comment period concluded on December 20, 1997, and
no prediction can be made as to whether the Staff proposal will be adopted or,
if so, the extent of its potential impact on the Company.


          1995 GAS SETTLEMENT. The Company has 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, 1997,
thereby avoiding negative financial impacts for that period.  The Company
believes that it will also be successful in meeting the Settlement targets in
the remaining year of the Settlement period, although no assurance may be given.

          The FERC approved a change in rate design for the Great Lakes Gas
Transmission Limited Partnership (Great Lakes) on which the Company holds
transportation capacity.  This change resulted in a retroactive surcharge by
Great Lakes to the Company in the amount of approximately $8 million, including
interest.  Under the terms of the 1995 Gas Settlement, the Company may recover
approximately one-half of the surcharge in rates charged to customers; but the
remainder may not be passed through and has been previously reserved.  The
Company, which paid the Great Lakes assessment under protest,  vigorously
contested it before the FERC, but on April 25, 1996, the FERC upheld this
determination that the charge to the Company is proper.  The Company's petition
to the U.S. Court of Appeals was denied on January 16, 1998.  The Company is
evaluating its next steps.
<PAGE>
 
                                       65

LEASE AGREEMENTS


          The Company leases five properties for administrative offices and
operating activities.  The total lease expense charged to operations was $4.2
million, $3.9 million and $2.4 million in 1997, 1996 and 1995, respectively.
For the years 1998, 1999, 2000, 2001 and 2002 the estimated lease expense
charged to operations will be $4.1 million, $2.4 million, $2.4 million, $2.4
million and $2.4 million, respectively.  Commitments under capital leases were
not significant to the accompanying financial statements.


LITIGATION


          SPENT NUCLEAR FUEL LITIGATION.  The Nuclear Waste Act (Act) obligates
the DOE to accept for disposal spent nuclear fuel (SNF) starting in 1998.  Since
the mid-1980s the Company and other nuclear plant owners and operators have paid
substantial fees to the DOE to fund its obligations under the Nuclear Waste Act.
DOE has indicated that it will not be in a position to accept SNF in 1998.  In
1994, Northern States Power Company and other owners and operators of nuclear
power plants filed suit against DOE and the U.S. in the U.S. Court of Appeals
for the District of Columbia Circuit seeking a declaration that DOE's course of
action was in violation of its obligations under the Act, and requesting other
relief.  In a July 1996 decision, the court upheld the utilities' position that
DOE is obligated to accept and dispose of the utilities' SNF beginning not later
than January 31, 1998.  DOE had contended in effect that it could defer the
disposal until the availability of a suitable SNF repository.  The court
rejected this DOE reading of the Nuclear Waste Act, but stopped short of
providing the utilities a remedy since DOE has not yet defaulted on its
obligations. By letter dated December 17, 1996, DOE invited the parties to the
proceeding to provide written comments on how DOE's anticipated inability to
meet its January 31, 1998 obligation to begin accepting SNF could "best be
accommodated".  The Company and a number of other parties responded to that
invitation.  By Joint Petition for Review, dated January 31, 1997, the Company
and a number of other nuclear utilities petitioned the United States Court of
Appeals for the District of Columbia Circuit for a declaration that the
Petitioners were relieved of the obligation to pay fees into the Nuclear Waste
Fund, and authorized to place those fees into escrow when and until DOE
commences disposing of SNF.  The Petition further requested that DOE be ordered
to develop a program that would enable it to begin acceptance of SNF by January
31, 1998.  By Order dated November 14, 1997, the D. C. Circuit held that DOE
could not exercise delay in accepting fuel 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 fuel, however, the Court referred
the utilities to the remedies set forth in their contracts with the DOE.  The
Company is pursuing such remedies.


          DEPARTMENT OF JUSTICE LAWSUIT.  On June 24, 1997, the Antitrust
Division of the United States Department of Justice filed a civil complaint
against the Company in the United States District Court for the Western District
of New York. The complaint follows a Civil Investigative Demand investigation.
That investigation included a broad look at the Company's activities in the
electric power industry including initially, the Company's power purchase
agreement with an independent power producer.  The investigation then focused
primarily upon the flexible rate long term contracts entered between the Company
and a number of its large customers under a tariff approved by the PSC.  The
tariff and the PSC policies it implemented recognized that if large customers
took their electrical load off the system, the rates for remaining customers
would have to increase to cover the fixed costs of operation.

   The Division in its complaint has challenged only certain provisions of one
flexible rate contract, the contract with the University of Rochester.  The
Complaint alleges that those provisions in that contract violate Section 1 of
the Sherman Act by restricting the customer's right to compete with the Company
in the sale of electricity and seeks an injunction prohibiting the Company from
enforcing that contract and from entering other agreements that limit
competition in the sale of electricity to other customers.
<PAGE>
 
                                       66


   The Company believes that the investigation and the Complaint reflect the
desire by the Antitrust Division to become involved in the deregulation of
electric utilities, but that the proper way to do that is in the proceedings
before the PSC in the Competitive Opportunities Case.

   On September 3, 1997, the Company filed its answer which denied the material
allegations of the Complaint.  At the same time, the Company filed a Motion for
Summary Judgment asking the Court to dismiss the action with prejudice on the
grounds that the Company's actions are immune from antitrust liability under the
State action exemption, that the Company's actions did not injure competition
and that the Department of Justice's claims are speculative.  On November 3,
1997, the Department of Justice filed its opposition to the Company's Motion for
Summary Judgment and filed its own Motion for Summary Judgement.  The Company's
response to the Justice Department motion was filed on December 5, 1997.

   These Motions for Summary Judgment were argued on December 19, 1997.  In
Court, the parties agreed to a resolution of the dispute, suggested by the Judge
which, in the Company's opinion, would not have any material effect on its
contract with the University.  The Antitrust Division, however, has expressed
its unwillingness to agree to a Consent Decree based on the agreement reached in
Court and the matter is still pending.


   LITIGATION WITH CO-GENERATOR.  Under federal and New York State laws and
regulations, the Company is required to purchase the electrical output of
unregulated cogeneration facilities which meet certain criteria (Qualifying
Facilities).  Under these statutes, a utility is required to pay for electricity
from Qualifying Facilities at a rate that equals the cost to the utility of
power it would otherwise produce itself or purchase from other sources (Avoided
Cost). With the exception of one contract which the Company was compelled by
regulators to enter into with Kamine/Besicorp Allegany L.P. (Kamine) for
approximately 55 megawatts of capacity, the Company has no long-term obligations
to purchase energy from Qualifying Facilities.

   Under State law and regulatory requirements in effect at the time the
contract with Kamine was negotiated, the Company was required to agree to pay
Kamine a price for power that is substantially greater than the Company's own
cost of production and other purchases.  Since that time the State "six-cent"
law mandating a minimum price higher than the Company's own costs has been
repealed and PSC estimates of future costs on which the contract was based have
declined dramatically.

   In September 1994, the Company commenced a lawsuit in New York State Supreme
Court, Monroe County, seeking to void or, alternatively, to reform a Power
Purchase Agreement with Kamine for the purchase of the electrical output of a
cogeneration facility in the Town of Hume, Allegany County, New York, for a term
of 25 years.  The contract was negotiated pursuant to the specific pricing
requirement of a State statute that was later repealed, as well as estimates of
Avoided Costs by the PSC that subsequently were drastically reduced.  As a
result, the contract requires the Company to pay prices for Kamine's electrical
output that dramatically exceed current Avoided Costs and current projections of
Avoided Costs.  The Company's lawsuit seeks to avoid payments to Kamine that
exceed actual and currently projected Avoided Costs.  Kamine answered the
Company's complaint, seeking to force the Company to take and pay for power at
the higher rates called for in the contract and claiming damages in an
unspecified amount alleged to have been caused by the Company's conduct.  The
Company received test generation from the Kamine facility during the last
quarter of 1994.  Kamine contends that the facility went into commercial
operation in December 1994 and that the Company is obligated to pay the full
contract rate for it.  The Company disputes this contention and refuses to pay
the full contract rate.  During 1995 Kamine filed a Motion for Summary Judgment
dismissing the Company's complaint and directing it to perform the Power
Purchase Agreement. The court denied that motion and Kamine appealed.  After
argument of that appeal Kamine filed for protection under the Bankruptcy laws
and sent to the Appellate Division a notice that all further proceedings were
stayed.

   In addition, Kamine has filed a related complaint in the United States
District Court for the Western District of New York alleging that the conduct
which is the subject of the State court action violates the federal antitrust
<PAGE>
 
                                       67

laws.  The complaint seeks damages in the amount of $420,000,000, when trebled,
as well as preliminary and permanent injunctions.  Subsequently, Kamine filed a
motion for a preliminary injunction in the federal action to enjoin the Company
from refusing to accept and purchase electric power from Kamine and enjoining
the Company from terminating during the pendency of this lawsuit its performance
under the contract.  In November 1995, the Court issued a decision denying
Kamine's motion for a preliminary injunction, finding, among other things, that
Kamine had not established the necessary likelihood of success on the merits of
its action.  Kamine filed a notice of appeal from that decision but has
subsequently announced that it is withdrawing that appeal.

   During 1995 the PSC invited the Company to file a petition requesting, among
other things, that the Commission commence an investigation to determine whether
at the time of claimed commercial operation the Hume plant was a cogeneration
facility under New York law as required by the Power Purchase Agreement.  The
Company filed such a petition and Kamine filed papers in opposition.

   During 1995 Kamine filed a petition before the FERC to waive certain
requirements for federal Qualified Facility status for 1994.  The Company and
the PSC filed in opposition to the request.  Subsequently FERC issued an order
granting the waiver request and the Company's motion for rehearing was denied.
The Company filed a petition for review with the U.S. Court of Appeals for the
District of Columbia Circuit but that court denied the request for review.

   In November 1995 Kamine filed in Newark, New Jersey for protection under the
Bankruptcy laws and filed a complaint in an adversary proceeding seeking, among
other things, specific performance of the Agreement.  Kamine filed a motion to
compel the Company to pay what would be due under Kamine's view of the terms of
the Agreement during the pendency of the Adversary Proceeding.  After hearing,
the Bankruptcy Court denied that motion.  The Court also denied various motions
made by the Company to change the venue of the proceedings to New York State and
to lift the automatic stay of the pending New York State action. On appeal the
Bankruptcy Court was reversed and the case sent back to the Bankruptcy Court to
decide where the contract issues in the Adversary Proceeding should be
adjudicated.  As of June 16, 1997, the Company filed a Second Amended Complaint
in the State Court action asserting additional claims based on subsequent
occurrences.

   On March 19, 1997, the Bankruptcy Court stayed the Adversary Proceeding
pending resolution of the contract issues in the New York State court trial.
Kamine has indicated it will not appeal this action.

   On June 26, 1997, the defendants filed a Joint Notice of Removal of Action,
removing the action to the United States District Court for the Western District
of New York.  There have been no further proceedings to date.

   Numerous other procedural motions have been presented in the Bankruptcy
Court, some of which may now be considered by the New York State court.  While
these proceedings are pending, the Company would pay approximately two cents per
kilowatt hour when the plant operates.  It is not operating at the present time.


   GENERAL ELECTRIC CAPITAL CORPORATION LAWSUIT.  On July 3, 1997, General
Electric Capital Corporation (GECC) filed a complaint against the Company in the
United States District Court for the Western District of New York in connection
with the Kamine project in Hume, New York, for which GECC provided financing.
The complaint asserts that the Company violated the antitrust laws in its
dealings with Kamine and seeks injunctive relief, treble damages and alleged
actual damages of not less than $100,000,000.  The claims made in the complaint
filed are substantially similar to the claims made by Kamine in the same court
under Kamine's version of the terms of the Power Purchase Agreement for the Hume
project.  The court denied Kamine's motion for a preliminary injunction on
grounds which included Kamine's failure to establish a likelihood of success on
the merits of its claims.  Kamine had filed a notice of appeal from a decision
denying Kamine's motion for a preliminary injunction.  Kamine subsequently
withdrew the appeal. The Company believes the complaint by GECC is also without
merit and intends to defend the action.
<PAGE>
 
                                       68

INTERIM FINANCIAL DATA


   In the opinion of the Company, the following quarterly information includes
all adjustments, consisting of normal recurring adjustments, necessary for a
fair statement of the results of operations for such periods.  The variations in
operations reported on a quarterly basis are a result of the seasonal nature of
the Company's business and the availability of surplus electricity.  The sum of
the quarterly earnings per share may not equal the fiscal year earnings per
share due to rounding.

<TABLE>
<CAPTION>
 
                                                (Thousands of Dollars)
 
                                                                                  Earnings per Common Share
                             Operating    Operating      Net       Earnings on           (in dollars)
Quarter Ended                Revenues       Income     Income      Common Stock     Basic        Diluted
<S>                          <C>         <C>           <C>         <C>              <C>          <C>
December 31, 1997            $271,039      $24,406     $14,031       $12,726        $ .32         $ .32
September 30, 1997            221,335       34,616      21,724        20,419          .52           .52
June 30, 1997                 229,419       31,125      18,172        16,681          .42           .42
March 31, 1997                314,845       55,194      41,433        39,729         1.02          1.02
 
December 31, 1996/1/         $274,431      $33,048     $22,228       $20,362        $0.52         $ .52
September 30, 1996            234,843       36,159      21,062        19,196         0.49           .49
June 30, 1996                 235,577       23,115      11,732         9,866         0.25           .25
March 31, 1996                309,195       56,866      42,489        40,623         1.05          1.05
 
December 31, 1995/1,2/       $270,518      $32,324     $  (387)      $(2,253)       $(.05)        $(.05)
September 30, 1995            245,145       41,738      26,934        25,068          .65           .65
June 30, 1995                 219,546       29,454      14,861        12,995          .34           .34
March 31, 1995                281,119       46,557      30,520        28,653          .75           .75
 
</TABLE>

/1/  Reclassified for comparative purposes.
/2/  Includes recognition of $28.7 million net-of-tax gas settlement adjustment.


Item 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE

     None
<PAGE>
 
                                       69

                                    PART III


Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT


     The information required by Item 10 of Form 10-K relating to directors who
are nominees for election as directors at the Company's Annual Meeting of
Shareholders to be held on April 15, 1998, will be set forth under the heading
"Election of Directors" in the Company's Definitive Proxy Statement for such
Annual Meeting of Shareholders.

     The information required by Item 10 of Form 10-K with respect to executive
officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of
Regulation S-K, set forth in Part I as Item 4-A of this Form 10-K under the
heading "Executive Officers of the Registrant".



Item 11.  EXECUTIVE COMPENSATION


     The information required by Item 11 of Form 10-K will be set forth under
the headings "Report of the Committee on Management on Executive Compensation",
"Executive Compensation" and "Pension Plan Table" in the Company's Definitive
Proxy Statement for the Annual Meeting of Shareholders.



Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT


     The information required by Item 12 of Form 10-K will be set forth under
the headings "General" and "Security Ownership of Management" in the Company's
Definitive Proxy Statement for the Annual Meeting of Shareholders.



Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS


     The information required by Item 13 of Form 10-K will be set forth under
the heading "Election of Directors" in the Company's Definitive Proxy Statement
for the Annual Meeting of Shareholders.

     Pursuant to General Instruction G(3) to Form 10-K, Items 10 through 13 have
not been answered because, within 120 days after the close of its fiscal year,
the Registrant will file with the Commission a definitive proxy statement
pursuant to Regulation 14A which involves the election of directors.  Regis
trant's definitive proxy statement dated March 3, 1998 will be filed with the
Securities and Exchange Commission prior to April 30, 1998. The information
required in Items 10 through 13 under the headings set forth above is incorpo
rated by reference herein by this reference thereto.  Except as specifically
referenced herein the proxy statement in connection with the annual meeting of
shareholders to be held April 15, 1998 is not deemed to be filed as part of this
Report.
<PAGE>
 
                                       70

                                    PART IV


Item 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K


(a)  1.   The financial statements listed below are shown under Item 8 of this
          Report.

          Report of Independent Accountants.

          Consolidated Statement of Income for each of the three years ended
          December 31, 1997.

          Consolidated Statement of Retained Earnings for each of the three
          years ended December 31, 1997.

          Consolidated Balance sheet at December 31, 1997 and 1996.

          Consolidated Statement of Cash Flows for each of the three years
          ended December 31, 1997.
 
          Notes to Consolidated Financial Statements.



(a)  2.   Financial Statement Schedules - Included in Item 14 herein:

          For each of the three years ended December 31, 1997.

          Schedule II - Valuation and Qualifying Accounts.



(a)  3.   Exhibits - See List of Exhibits.

(b)       Reports on Form 8-K



     The Company filed a Form 8-K dated December 5, 1997, reporting under Item
5, Other Events, approval by the PSC of the Company's Competitive Opportunities
Case Settlement with the PSC staff and other parties with respect to the
restructuring of the electric utility industry in New York State.
<PAGE>
 
                                       71

                     ROCHESTER GAS AND ELECTRIC CORPORATION

                SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

                             (Thousands of Dollars)



FOR THE YEAR ENDED DECEMBER 31, 1995

<TABLE>
<CAPTION>
                                                        Additions
                                                        ---------
                             Balance at    Charged to    Charged                  Balance
                             Beginning     Costs and    To Other                  at End 
Descriptions                 of Period     Expenses     Accounts   Deductions    of Period
------------                 ----------    --------     --------   ----------    ---------
<S>                          <C>           <C>          <C>        <C>           <C>
Reserves for:
 
Uncollectible accounts          $950       $14,893                   $3,893       $11,950
 
Materials and supplies
  obsolescence                     0           736                                    736
</TABLE>

FOR THE YEAR ENDED DECEMBER 31, 1996

<TABLE>
<CAPTION>
                                                        Additions
                                                        ---------
                             Balance at    Charged to    Charged                  Balance
                             Beginning     Costs and    To Other                  at End 
Descriptions                 of Period     Expenses     Accounts   Deductions    of Period
------------                 ----------    --------     --------   ----------    ---------
<S>                          <C>           <C>          <C>        <C>           <C>
Reserves for:
 
Uncollectible accounts        $11,950       $4,987       $ 565                    $17,502
 
Materials and supplies
  obsolescence                    736         (375)                                   361
</TABLE>

FOR THE YEAR ENDED DECEMBER 31, 1997

 
<TABLE>
<CAPTION>
                                                        Additions
                                                        ---------
                             Balance at    Charged to    Charged                  Balance
                             Beginning     Costs and    To Other                  at End 
Descriptions                 of Period     Expenses     Accounts   Deductions    of Period
------------                 ----------    --------     --------   ----------    ---------
<S>                          <C>           <C>          <C>        <C>           <C>
Reserves for:
 
Uncollectible accounts        $17,502       $5,078       $4,346                   $26,926
 
Materials and supplies
  obsolescence                    361        2,839                                  3,200
</TABLE>


          Beginning in 1992 the Company no longer charges uncollectible expenses
through the uncollectible reserve.  The total amount written off directly to
expense in 1995 was $8,170, in 1996 was $15,039 and in 1997 was $12,912.
<PAGE>
 
                                       72

LIST OF EXHIBITS

Exhibit 3-1*   Restated Certificate of Incorporation of Rochester Gas and
               Electric Corporation under Section 807 of the Business
               Corporation Law filed with the Secretary of State of the State of
               New York on June 23, 1992. (Filed in Registration No. 33-49805 as
               Exhibit 4-5 in July 1993)

Exhibit 3-2*   Certificate of Amendment of the Certificate of Incorporation of
               Rochester Gas and Electric Corporation Under Section 805 of the
               Business Corporation Law filed with the Secretary of State of the
               State of New York on March 18, 1994. (Filed as Exhibit 4 in May
               1994 on Form 10-Q for the quarter ended March 31, 1994, SEC File
               No. 1-672.)

Exhibit 3-3*   By-Laws of the Company, as amended to date. (Filed as Exhibit 3-1
               in May 1996 on Form 10-Q for the quarter ended March 31, 1996,
               SEC File No. 1-672)

Exhibit 4-1*   Restated Certificate of Incorporation of Rochester Gas and
               Electric Corporation under Section 807 of the Business
               Corporation Law filed with the Secretary of State of the State of
               New York on June 23, 1992. (Filed in Registration No. 33-49805 as
               Exhibit 4-5 in July 1993)

Exhibit 4-2*   Certificate of Amendment of the Certificate of Incorporation of
               Rochester Gas and Electric Corporation Under Section 805 of the
               Business Corporation Law filed with the Secretary of State of the
               State of New York on March 18, 1994. (Filed as Exhibit 4 in May
               1994 on Form 10-Q for the quarter ended March 31, 1994, SEC File
               No. 1-672.)

Exhibit 4-3*   By-Laws of the Company, as amended to date. (Filed as Exhibit 3-1
               in May 1996 on Form 10-Q for the quarter ended March 31, 1996,
               SEC File No. 1-672)

Exhibit 4-4*   General Mortgage to Bankers Trust Company, as Trustee, dated
               September 1, 1918, and supplements thereto, dated March 1, 1921,
               October 23, 1928, August 1, 1932 and May 1, 1940. (Filed as
               Exhibit 4-2 in February 1991 on Form 10-K for the year ended
               December 31, 1990, SEC File No. 1-672-2)

Exhibit 4-5*   Supplemental Indenture, dated as of March 1, 1983 between the
               Company and Bankers Trust Company, as Trustee (Filed as Exhibit
               4-1 on Form 8-K dated July 15, 1993, SEC File No. 1-672)

Exhibit 10-1*  Basic Agreement dated as of September 22, 1975 among the Company,
               Niagara Mohawk Power Corporation, Long Island Lighting Company,
               New York State Electric & Gas Corporation and Central Hudson Gas
               & Electric Corporation. (Filed in Registration No. 2-54547, as
               Exhibit 5-P in October 1975.)

Exhibit 10-2*  Letter amendment modifying Basic Agreement dated September 22,
               1975 among the Company, Central Hudson Gas & Electric
               Corporation, Orange and Rockland Utilities, Inc. and Niagara
               Mohawk Power Corporation. (Filed in Registration No. 2-56351, as
               Exhibit 5-R in June 1976.)
<PAGE>
 
                                       73

Exhibit 10-3*  Agreement dated September 25, 1984 between the Company and the
               United States Department of Energy, as amended. (Filed as Exhibit
               10-3 in February 1995 on Form 10-K for the year ended December
               31, 1994, SEC File No. 1-672-2)

Exhibit 10-4*  Agreement dated February 5, 1980 between the Company and the
               Power Authority of the State of New York. (Filed as Exhibit 10-10
               in February 1990 on Form 10-K for the year ended December 31,
               1989, SEC File No. 1-672-2)

Exhibit 10-5*  Agreement dated March 9, 1990 between the Company and Mellon
               Bank, N.A. (Filed as Exhibit 10-1 in May 1990 on Form 10-Q for
               the quarter ended March 31, 1990, SEC File No. 1-672)

Exhibit 10-6*  Basic Agreement dated September 22, 1975 as amended and
               supplemented between the Company and Niagara Mohawk Power
               Corporation. (Filed as Exhibit 10-11 in February 1993 on Form
               10-K for the year ended December 31, 1992, SEC File No. 1-672-2)

Exhibit 10-7*  Operating Agreement effective January 1, 1993 among the owners of
               the Nine Mile Point Nuclear Plant Unit No. 2. (Filed as Exhibit
               10-12 in February 1993 on Form 10-K for the year ended December
               31, 1992, SEC File No. 1-672-2)


Exhibit 10-8*  (A)  Rochester Gas and Electric Corporation Deferred Compensation
                    Plan. (Filed as Exhibit 10-14 in February 1994 on Form 10-K
                    for the year ended December 31, 1993, SEC File No. 1-672-2)

Exhibit 10-9*  (A)  Rochester Gas and Electric Corporation Long Term Incentive
                    Plan, Restatement of January 1, 1994. (Filed as Exhibit
                    10-10 in February 1995 on Form 10-K for the year ended
                    December 31, 1994, SEC File No. 1-672-2)

Exhibit 10-10*  (A) Rochester Gas and Electric Corporation Deferred Stock Unit
                    Plan for Non-Employee Directors, effective as of December
                    31, 1995. (Filed as Exhibit 10-1 in May 1996 on Form 10-Q
                    for the quarter ended March 31, 1996, SEC File No. 1-672)

Exhibit 10-11*  (A) 1996 Performance Stock Option Plan. (Filed as Exhibit 10-10
                    in February 1995 on Form 10-K for the year ended December
                    31, 1994, SEC File No. 1-672-2)

Exhibit 10-12*  (A) Rochester Gas and Electric Corporation Executive Incentive
                    Plan, Restatement of January 1, 1995. (Filed as Exhibit
                    10-11 in February 1996 on Form 10-K for the year ended
                    December 31, 1995, SEC File No. 1-672-2)


Exhibit 10-13*  (A) RG&E Unfunded Retirement Income Plan Restatement as of July
                    1, 1995. (Filed as Exhibit 10-12 in February 1996 on Form
                    10-K for the year ended December 31, 1995, SEC File No.
                    1-672-2)

Exhibit 10-14  (A)  Change of Control Agreement dated January 1, 1998 between
                    the Company and Thomas S. Richards, Chairman of the Board,
                    President and Chief Executive Officer.
<PAGE>
 
                                       74

Exhibit 10-15*  (A)  Change of Control Agreement dated August 17, 1995 between
                     the Company and Robert E. Smith, Senior Vice President,
                     Energy Operations. (Filed as Exhibit 10-15 in February 1996
                     on Form 10-K for the year ended December 31, 1995, SEC File
                     No. 1-672-2)

Exhibit 10-16*  (A)  Change of Control Agreement dated January 2, 1996 between
                     the Company and J. Burt Stokes, Senior Vice President,
                     Corporate Services and Chief Financial Officer. (Filed as
                     Exhibit 10-16 in February 1996 on Form 10-K for the year
                     ended December 31, 1995, SEC File No. 1-672-2)

Exhibit 10-17*  (A)  Change of Control Agreement dated January 2, 1997 between
                     the Company and Michael J. Bovalino, Senior Vice President,
                     Energy Services. (Filed as Exhibit 10-18 in February 1997
                     on Form 10-K for the year ended December 31, 1996, SEC File
                     No. 1-672-2)

Exhibit 10-18        Amended and Restated Settlement Agreement dated October 23,
                     1997 between the Company the Staff of the New York Public
                     Service Commission (PSC), and certain other parties (Filed
                     as Exhibit 10-4 on Form 10-Q for the quarter ended
                     September 30, 1997, SEC File No. 1-672) as amended pursuant
                     to an order of the PSC issued January 14, 1998 (excluding
                     Appendices) filed herewith.

Exhibit 10-19*  (A)  Form of Rochester Gas and Electric Corporation 1996
                     Performance Stock Option Plan Agreement. (Filed as Exhibit
                     10-1 in November 1997 on Form 10-Q for the quarter ended
                     September 30, 1997, SEC File No. 1-672)


Exhibit 10-20*  (A)  Agreement, dated October 1, 1997, between the Company and
                     Michael T. Tomaino, Senior Vice President and General
                     Counsel. (Filed as Exhibit 10-2 in November 1997 on Form
                     10-Q for the quarter ended September 30, 1997, SEC File
                     No. 1-672)

Exhibit 10-21*       Agreement dated as of September 23,1997 between the Company
                     and International Business Machines Corporation. (Filed as
                     Exhibit 10-3 in November 1997 on Form 10-Q for the quarter
                     ended September 30, 1997, SEC File No. 1-672)

Exhibit 23           Consent of Price Waterhouse LLP, independent accountants

Exhibit 27           Financial Data Schedule, pursuant to Item 601(c) of
                     Regulation S-K.

*   Incorporated by reference.
(A) Denotes executive compensation plans and arrangements.


   The Company agrees to furnish to the Commission, upon request, a copy of all
agreements or instruments defining the rights of holders of debt which do not
exceed 10% of the total assets with respect to each issue, including the
Supplemental Indentures under the General Mortgage and credit agreements in
connection with promissory notes as set forth in Note 6 of the Notes to
Financial Statements.
<PAGE>
 
                                       75

                                   SIGNATURES


   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.


                                        ROCHESTER GAS AND ELECTRIC CORPORATION


                                        By:  /S/ THOMAS S. RICHARDS
                                             ---------------------------------
                                             Thomas S. Richards
                                             Chairman of the Board,
                                             President and
                                             Chief Executive Officer



DATE:  February 11, 1998


   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.


<TABLE>
<CAPTION>

SIGNATURE                                     TITLE                        DATE
---------                                     -----                        ----
<S>                                    <C>                           <C>
Principal Executive Officer:

   /S/ THOMAS S. RICHARDS              Chairman of the Board,        February 11, 1998
-------------------------------        President and                                    
      (Thomas S. Richards)             Chief Executive Officer

Principal Financial Officer:

   /S/ J. B. STOKES                    Senior Vice President         February 11, 1998
-------------------------------        Corporate Services and                                  
      (J. Burt Stokes)                 Chief Financial Officer    


Principal Accounting Officer:

     /S/ WILLIAM J. REDDY               Controller                   February 11, 1998
-------------------------------                                                 
        (William J. Reddy)
</TABLE>
<PAGE>
 
                                       76

<TABLE>
<CAPTION>

SIGNATURE                                TITLE                        DATE
---------                                -----                        ----
<S>                                    <C>                      <C>
Directors:

  /S/ WILLIAM BALDERSTON III           Director                 February 11, 1998
-------------------------------                                             
    (William Balderston III)

  /S/ ANGELO J. CHIARELLA              Director                 February 11, 1998
-------------------------------                                                
     (Angelo J. Chiarella)

   /S/ ALLAN E. DUGAN                  Director                 February 11, 1998
-------------------------------                                             
      (Allan E. Dugan)
                                       Director                 February   , 1998
-------------------------------  
      (Mark B. Grier)

     /S/ SUSAN R. HOLLIDAY             Director                 February 11, 1998
-------------------------------                                             
       (Susan R. Holliday)

   /S/ JAY T. HOLMES                   Director                 February 11, 1998
-------------------------------                                             
      (Jay T. Holmes)

   /S/ SAMUEL T. HUBBARD,JR            Director                 February 11, 1998
-------------------------------                                             
    (Samuel T. Hubbard, Jr.)

   /S/ ROGER W. KOBER                  Director                 February 11, 1998
-------------------------------                                             
      (Roger W. Kober)

  /S/ CONSTANCE M. MITCHELL            Director                 February 11, 1998
-------------------------------                                             
    (Constance M. Mitchell)

   /S/ CORNELIUS J. MURPHY             Director                 February 11, 1998
-------------------------------                                             
     (Cornelius J. Murphy)

   /S/ CHARLES I. PLOSSER              Director                 February 11, 1998
--------------------------------                                             
      (Charles I. Plosser)

   /S/ THOMAS S. RICHARDS              Director                 February 11, 1998
-------------------------------                                             
     (Thomas S. Richards)
</TABLE>