<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, 1998
                                             -----------------


                                  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
                                                 -----


                    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, 1999 the aggregate market value of the voting stock held by
nonaffiliates of the Registrant was approximately $1,161,000,000.

     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, 1999, 37,378,813.

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

     Definitive proxy statement in connection           III
     with annual meeting of shareholders to be
     held April 29, 1999.
<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                                                     14
Item 3     Legal Proceedings                                              16
Item 4     Submission of Matters to a Vote of Security Holders            19
Item 4A    Executive Officers of the Registrant                           19
 

Part II
-------

Item 5     Market for the Registrant's Common Equity and
                  Related Stockholder Matters                             21
Item 6     Selected Financial Data                                        22
Item 7     Management's Discussion and Analysis of Financial 
                  Condition and Results of Operations                     25
Item 7A    Quantitative and Qualitative Disclosures about    
                  Market Risk                                             43
Item 8     Financial Statements and Supplementary Data                    44
Item 9     Changes in and Disagreements with Accountants on  
                  Accounting and Financial Disclosure                     74
 

Part III
--------
 
Item 10    Directors and Executive Officers of the Registrant             75
Item 11    Executive Compensation                                         75
Item 12    Security Ownership of Certain Beneficial Owners and
                  Management                                              75
Item 13    Certain Relationships and Related Transactions                 75
 

Part IV
-------

Item 14    Exhibits, Financial Statement Schedules and Reports
                  on Form 8-K                                             76

           Signatures                                                     81
<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                             3
     Electric Operations                            4
     Gas Operations                                 7
     Unregulated Operations                         7
     Fuel Supply                                    7
     Financing and Capital Requirements Program     8
     Environmental Quality Control                 10
     Research and Development                      11
     Operating Statistics                          12
 

GENERAL

     Incorporated in 1904 in the State of New York, the Company is engaged
principally in the business of generating, purchasing, transmitting and
distributing electricity, and purchasing, transporting and distributing natural
gas. The regulated business produces and distributes electricity and distributes
gas in parts of nine counties centering about the City of Rochester.  At
December 31, 1998 the Company and its subsidiaries had 2,333 employees.

     The Company's service area for its regulated business 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.

     Present Businesses.  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 natural gas,
kerosene, propane and heating oil, the greatest sales occur in the winter months
due to spaceheating usage. In addition, gasoline sales reflect seasonal
fluctuations due to increased consumer driving during the warmer months.  In
each of the communities in which it renders regulated utility 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.  In 1998, the
Company entered into unregulated businesses to bring energy products and
services to the marketplace both within and outside the Company's franchise area
as described below.

     Energetix, Inc.  It is part of the Company's financial strategy to seek
growth by entering into unregulated businesses.  The Competitive Opportunities
Settlement (discussed under Item 7, Management's Discussion and Analysis of
<PAGE>
 
                                       2

Financial Condition and Results of Operations) allows the Company to invest up
to $100 million in unregulated businesses.  The first step in this direction was
the formation and operation of Energetix, Inc. ("Energetix").  Energetix is an
unregulated subsidiary that brings energy products and services to the
marketplace including the marketing of electricity, natural gas, gasoline, oil
and propane fuel energy services in an area extending approximately in a 150-
mile radius around Rochester.

     In August 1998, Energetix announced the acquisition of Griffith Oil Co.,
Inc. ("Griffith"), the second largest oil and propane distribution company in
New York State.  Griffith gives Energetix access to 65,000 new customers, 60,000
of which are residing outside of the Company's regulated franchise territory.
In addition to its current products, Griffith sells electricity, natural gas and
other services offered by Energetix to its existing customers.  Griffith has
approximately 350 employees and operates 16 customer service centers.

     RGS Development Corporation.  During the second quarter of 1998, the
Company formed a new unregulated subsidiary, RGS Development Corporation ("RGS
Development").  RGS Development was formed to pursue unregulated business
opportunities in the energy marketplace.

     RGS Energy Group, Inc.  RGS Energy Group, Inc. ("RGS Energy") was organized
in 1998 for the purpose of carrying out the reorganization of the Company into a
holding company structure.  RGS Energy is currently a direct subsidiary of the
Company.  Subject to regulatory and shareholder approvals, all of the
outstanding shares of the Company's common stock will be exchanged on a share-
for-share basis for RGS Energy common stock. RGS Energy will become the parent
of the Company, Energetix, and RGS Development.  The Company expects to complete
the reorganization by mid-1999.

     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 regulated electric and gas revenues are
derived and other operating data are included herein under "Operating
Statistics".  A discussion of the causes of significant changes in revenues is
presented in Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations.  Percentages of the Company's operating
revenues derived from electric and gas service and unregulated businesses for
each of the last three years are as follows:

                                  1998     1997     1996
                                 ------   ------   ------

                   Electric       66.4%    67.6%    67.1%
                   Gas            26.6%    32.4%    32.9%
                   Unregulated     7.0%     -- %     -- %
                                  ----     ----     ----
                                 100.0%   100.0%   100.0%

     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 through July 1,
2002.  Regarding the Company's electric business, in early 1996 the Federal
Energy 
<PAGE>
 
                                       3

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". In 1998, FERC issued an order that conditionally authorizes
the establishment of an independent system operator (NYSIO) to administer a
state-wide open access tariff but deferred consideration of the tariff to a
future order for which no specific date has been set. 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 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. Through December 31, 1998, eight energy service
companies have been qualified by the Company to serve retail customers under the
Energy Choice Program. In 1998 the PSC also initiated a proceeding to examine a
number of issues relating to nuclear generation in a competitive market-based
electricity industry. This proceeding is intended to be completed in the fourth
quarter of 1999.

     With the unbundling of interstate gas pipeline 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 had 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
companies.  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.  In 1998 the PSC issued a gas
restructuring policy statement which concluded, among other things, that the
most effective way to establish a competitive gas supply market is for gas
distribution companies to cease selling gas.  The PSC has encouraged settlement
negotiations with each gas utility pertaining to the transition to a fully
competitive gas market.

     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, Energy Choice Program,
FERC Open Access, PSC Proceeding on Nuclear Generation, PSC Gas Restructuring
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
Nuclear Regulatory Commission (NRC).  The impact of regulation is discussed
throughout this report.

     On July 29, 1998, the FERC issued a Notice of Proposed Rulemaking (NOPR)
(RM98-10) on short-term natural gas transportation services, which proposed an
integrated package of revisions to its regulations governing interstate natural
gas pipelines.  "Short term" has been defined in the NOPR as all transactions of
less than one year.  The short-term market could be priced at market-based
rates.  Under the proposed approach, cost-based regulation would be eliminated
for short-term transportation and replaced by regulatory policies intended to
maximize
<PAGE>
 
                                       4

competition in the short-term transportation market, mitigate the ability of
companies to exercise residual pipeline market power, and provide opportunities
for greater flexibility providing pipeline services without disadvantaging
customers that have limited access to gas supplies. The proposed changes
include, among other things, initiatives to revise pipeline scheduling
procedures and the policies that govern the flow of gas through the pipelines;
require pipelines to auction short-term capacity; and permit pipelines to
negotiate rates and terms of services.

     In conjunction with the NOPR, the FERC also issued a Notice of Inquiry
(NOI) (RM98-12) on its pricing policies in the existing long-term market and
pricing policies for new capacity.  The FERC wants to ensure that its policies
are not biased toward either short-term or long-term service, provide accurate
price signals and the right incentives for pipelines to provide optimal
transportation services and construct facilities that meet future demand, but do
not result in over building and excess capacity.  Comments on the NOPR and NOI
are due April 22, 1999.  The Company is reviewing the NOPR and NOI but any
ultimate resolution at this stage is unknown.  The Company is presently unable
to estimate the effects of these matters on future operations.

     See Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading "Rates and Regulatory Matters" for
information regarding a gas settlement proposal and an interim gas settlement
and a 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 kilowatts (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 and
44,000 Kw of firm power from the Power Authority's 821,000 Kw FitzPatrick
Nuclear Power Plant near Oswego, New York. 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 1994-1998 are as follows:

                                1998     1997      1996     1995     1994
                                ----     ----      ----     ----     ----

Sources of Generated Energy:                                   
                                                               
Nuclear                         60.1%    61.6%     49.4%    52.8%    55.3%
                                                               
Fossil                          22.2     20.0      18.2     18.6     18.1
Hydro and Other                  2.1      2.7       3.0      2.0      2.7
                               -----    -----     -----    -----    -----
  Total Generated Net           84.4     84.3      70.6     73.4     76.1
                                                                  
Purchased                       15.6     15.7      29.4     26.6     23.9
                               -----    -----     -----    -----    -----
Total Electric Energy          100.0%   100.0%    100.0%   100.0%   100.0%
                               =====    =====     =====    =====    =====

     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 of potential changes to
the NYPP, see Item 7, Management's Discussion and Analysis of Financial
Condition and
<PAGE>
 
                                       5

Results of Operations - "FERC Open Access 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, 1998 the Company purchased a natural gas
combined cycle generating facility rated at approximately 65 megawatts (Mw)
which it intends to operate in 1999.

     For information relating to the retirement of Beebee Station and a sale
agreement for Oswego Unit Six see Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations - "Fossil Unit Status".

     Nine Mile Two, a nuclear generating unit in Oswego County, New York with a
designed capability of 1,143 Mw as estimated by Niagara Mohawk, was completed
and entered commercial service in Spring 1988.  Niagara Mohawk 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 Mohawk (41%) Long Island Power
Authority (formerly Long Island Lighting Company) (18%), New York State Electric
& Gas Corporation (18%) and Central Hudson Gas & Electric Corporation (9%).
Under the operating Agreement, Niagara Mohawk 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, 1998 are $877
million and $384 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, 1998 are
$595 million and $279 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 $12.9 million, $4.6 million and $6.9
million for the years 1999, 2000 and 2001, 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. The Company received renewed final
licenses for Stations 2,5 and 26. Overly stringent environmental conditions,
governmental requirements and high property taxes have nullified the economic
viability of the
<PAGE>
 
                                       6

fourth station, number 160 (less than one megawatt net capacity). It will not be
relicensed.
     Nuclear Operating Company.  In October 1996, the Company and Niagara Mohawk
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 with three members:  the
Company, Niagara Mohawk, and Consolidated Edison, Inc.  Although not a member,
the New York Power Authority has participated in the development of plans to
implement NYNOC.  The principal function of NYNOC, should it be implemented,
would be to operate and manage, but not to own, six operational nuclear plants
in New York, including the Company's totally owned Ginna Nuclear Plant and
jointly owned Nine Mile Point Unit 2.  The Company continues to believe that
NYNOC, or a similar arrangement, would contribute to maintaining a high level of
operational performance and satisfactory NRC compliance, and would provide
opportunities for further cost reduction. The initial work associated with plans
for implementation of NYNOC was completed in 1998.  Although the Company plans
to maintain NYNOC as an option in 1999, no substantial further work on its
implementation is anticipated until completion of the PSC proceeding regarding
the future of nuclear power plants in New York State.

     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 $88.1 million per licensed facility for each
nuclear incident, payable at a rate not to exceed $10 million per incident 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 expose it to a potential liability for each accident of
$100.4 million through retrospective assessments of $11.4 million per incident
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 $3.2 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 damage 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 $2.4
million and $10.4 million in the event of losses under the replacement power and
property damage coverages, respectively.
<PAGE>
 
                                       7

GAS OPERATIONS

     As of December 31, 1998 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.
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.

     Approximately 33% of the gas delivered to customers by the Company during
1998 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.


UNREGULATED OPERATIONS

  Energetix serves electric and gas customers, appliance service warranty
customers and, through its acquisition of Griffith, approximately 65,000
customers for its products including oil, diesel, kerosene, propane and
gasoline. See Note 4 of the Notes to Financial Statements for additional
operating information and Management's Discussion and Analysis of Financial
Condition and Results of Operations under Unregulated Operating Revenues and
Sales for information on products, revenues and sales.


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:

                             Ginna Plant  Nine Mile Two/(1)/
                             -----------  ----------------

          Uranium Concentrate    2001/(3)/    2002/(2)/
          Conversion             2000/(4)/    2002/(2)/
          Enrichment             2009/(5)/     /(6)/
          Fabrication            2009          2003

(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
<PAGE>
 
                                       8

     to supply about 30% of the annual requirements through 1999, and 100% of
     requirements in 2000.  A third contract is in place, which will supply
     500,000 pounds of uranium between 1999 and 2004 as scheduled by the
     Company.  This material may be scheduled for delivery against requirements
     in 2001, or may be scheduled for later delivery depending on the market
     price of uranium at the time.  The remaining requirements are uncommitted.

(4)  A contract is in place covering 70% of requirements in 1999 and 100% in
     2000.  Remaining requirements will be filled from market purchases or a new
     long term contract.

(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 through the end of the current operating license.

(6)  Nine Mile Two is covered for 75% of requirements through 2003 (with an
     option to increase to 100%).

     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.

     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 1999 coal requirements are expected to be approximately
650,000 tons.  In 1998 73% of its requirements were purchased under contract and
27% were purchased on the spot market.  Currently, the Company maintains a
current reserve supply of coal ranging from 30-60 days supply at maximum burn
rates.

     The sulfur content of the coal utilized in the Company's existing coal-
fired facilities ranges from 1.0 to 1.9 pounds per million BTU.  Under existing
New York State regulations, the Company's coal-fired facilities may not burn
coal which exceeds 2.5 pounds per million BTU, 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.


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
<PAGE>
 
                                       9

indentures.  Before additional First Mortgage Bonds are issued, the following
financial requirements must be satisfied:

(a)  The First Mortgage prohibits the issuance of additional First Mortgage
     Bonds unless earnings (as defined) for a period of twelve months ending not
     earlier than sixty days prior to the issue date of the additional bonds are
     at least 2.00 times the annual interest charges on First Mortgage Bonds,
     both those outstanding and those proposed to be outstanding.  The ratio
     under this test for the twelve months ended December 31, 1998 was 6.65.

(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, 1998 the amount of additional First Mortgage
     Bonds which could be issued on that basis was approximately $411,410,000.
     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, 1998, the Company
     could issue $327,169,000 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, 1998, the
coverage ratio under (b) above (the more restrictive provision) was 2.06.

     For other information with respect to long-term and short-term borrowing
arrangements and limitations see Item 8, Note 6 - Long-Term Debt and 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, 1998 were:

                                     First
                                    Mortgage  Preferred
                                     Bonds      Stock
                                    --------  ---------
 
     Standard & Poor's Corporation      A-       BBB+
     Moody's Investors Service          A3       baa1
     Duff & Phelps                      A-       BBB
 
     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.
<PAGE>
 
                                       10

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 $6.4 million on a
variety of projects and facility additions during 1998.

     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 storage capacity at the Ginna Plant
through the end of its license in 2009.  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 each of its
steam electric generating stations.  The Ginna Station permit is dated February
1998; the current Beebee station permit is dated February 1994 and has been
renewed with an effective date of February 1999; and the current Russell Station
permit is dated June 1994 and is presently in the renewal process with an
anticipated effective date of June 1999.  These permits are each valid for a
period of five years from their effective dates.  Consistent with the Ginna and
Beebee permits, no significant changes to the wastewater discharge treatment
systems are currently required, nor anticipated.  At Russell Station an
oil/water separator is being installed as a preventive measure against oil
contamination within the station wastewaters.  The cost of this separator is
approximately $.7 million.

  The Company is developing strategies responsive to the Federal Clean Air Act
amendments of 1990 (CAA) 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 only an
O&M impact.  The most recent strategic developments still envision this
combination of efforts as the most cost effective means of proceeding although
there is some New York State legislative activity that 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
matters in the Legislature and, as a result, the Company's projections are based
solely on the combination strategy. Capital expenditures due to CAA requirements
are expected to be limited to less than $250 thousand in 1999.  In 1999, it is
estimated that additional O&M costs for emissions control will range between
$0.9 million and $1.1 million.  Beginning in the year 2000, these additional O&M
costs could rise to approximately $3.0 million annually and remain there until
Phase III Federal NOx control limits become effective in 2003. O&M costs could
increase further after this point depending on Federal regulations.  Any further
capital expenditures for additional NOx control have been deferred until after
2000.  These additional capital costs and any increases in annual operating
costs that would be incurred as a result of these capital additions beyond the
year 2000 cannot be predicted accurately until a final strategy is chosen which
will await pending Federal and State regulatory decisions.

     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, subject to the terms
of the Company's Competitive Opportunities Settlement Agreement.  Capital
expenditures for meeting various federal, State and local environmental
standards
<PAGE>
 
                                       11

are estimated to be $2.7 million for the year 1999, $2.1 million for the year
2000 and $.5 million for the year 2001. 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 3 - Legal Proceedings and Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations, 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 1998, 1997 and 1996 were $3.4 million,
$4.5 million, and $4.9 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>
 
                                       12


Electric Department Statistics


<TABLE>
<CAPTION>
 
  Year Ended December 31                   1998        1997         1996         1995         1994        1993
                                       ----------   ----------   ----------   ----------   ----------   ----------
<S>                                    <C>          <C>          <C>          <C>          <C>          <C>
Electric Revenue (000's)
Residential                            $  250,073   $  252,464   $  254,885   $  256,294   $  243,961   $  234,866
Commercial                                203,338      210,643      215,763      215,696      206,545      196,100
Industrial                                130,778      144,305      153,337      157,464      150,372      148,084
Municipal and Other                        58,889       72,061       66,898       67,128       57,270       59,905
                                       ----------   ----------   ----------   ----------   ----------   ----------
Electric revenue from our customers       643,078      679,473      690,883      696,582      658,148      638,955
Wholesale electric sales *                 44,022       20,856       16,885       25,883       16,605       16,361
                                       ----------   ----------   ----------   ----------   ----------   ----------
  Total electric revenue                  687,100      700,329      707,768      722,465      674,753      655,316
 
Electric Expense (000's)
Fuel used in electric generation           53,954       47,665       40,938       44,190       44,961       45,871
Purchased electricity                      27,024       28,347       46,484       54,167       37,002       31,563
Other operation                           195,400      205,058      204,746      199,524      192,360      192,749
Maintenance                                38,022       41,217       41,429       44,032       47,295       52,464
Depreciation and amortization             102,123      103,395       92,615       78,812       75,211       72,326
Taxes - local, state and other             89,164       91,111       95,010      102,380       97,919       96,043
                                       ----------   ----------   ----------   ----------   ----------   ----------
  Total electric expense                  505,687      516,793      521,222      523,105      494,748      491,016
                                       ----------   ----------   ----------   ----------   ----------   ----------
Operating Income before
  Federal Income Tax                      181,413      183,536      186,546      199,360      180,005      164,300
Federal income tax                         61,477       61,837       61,901       59,500       52,842       43,845
                                       ----------   ----------   ----------   ----------   ----------   ----------
Operating Income from
  Electric Operations (000's)          $  119,936   $  121,699   $  124,645   $  139,860   $  127,163   $  120,455
                                       ----------   ----------   ----------   ----------   ----------   ----------
Electric Operating Ratio %                   45.8         46.0         47.1         47.3         47.7         49.2
Electric Sales - KWH (000's)
Residential                             2,111,739    2,139,064    2,132,902    2,144,718    2,117,168    2,123,277
Commercial                              2,007,282    2,118,991    2,061,625    2,064,813    2,028,611    1,986,100
Industrial                              1,929,268    2,010,613    2,010,963    1,964,975    1,860,833    1,892,700
Municipal and Other                       514,243      537,051      520,885      531,311      513,675      504,987
                                       ----------   ----------   ----------   ----------   ----------   ----------
  Total customer sales                  6,562,532    6,805,719    6,726,375    6,705,817    6,520,287    6,507,064
Wholesale electric sales*               1,671,959    1,218,794      994,842    1,484,196    1,021,733      743,588
                                       ----------   ----------   ----------   ----------   ----------   ----------
  Total electric sales                  8,234,491    8,024,513    7,721,217    8,190,013    7,542,020    7,250,652
                                       ----------   ----------   ----------   ----------   ----------   ----------
Electric Customers at December 31
Residential                               309,931      308,909      307,181      306,601      304,494      302,219
Commercial                                 30,248       30,940       30,620       30,426       29,984       29,635
Industrial                                  1,279        1,300        1,325        1,347        1,361        1,382
Municipal and Other                         2,594        2,824        2,688        2,711        2,670        2,638
                                       ----------   ----------   ----------   ----------   ----------   ----------
  Total electric customers                344,052      343,973      341,841      341,085      338,509      335,874
                                       ----------   ----------   ----------   ----------   ----------   ----------
Electricity Generated and
  Purchased - KWH (000's)
Fossil                                  1,962,889    1,664,914    1,512,513    1,631,933    1,478,120    1,520,936
Nuclear                                 5,323,639    5,119,544    4,094,272    4,645,646    4,527,178    4,495,457
Hydro                                     189,512      227,867      248,990      171,886      218,129      199,239
Pumped storage                            232,927      238,900      246,726      237,904      247,550      233,477
Less energy for pumping                  (348,438)    (358,350)    (370,097)    (361,144)    (371,383)    (355,725)
Other                                         195          890          936        1,565        1,245        2,559
                                       ----------   ----------   ----------   ----------   ----------   ----------
Total generated - net                   7,360,724    6,893,765    5,733,340    6,327,790    6,100,839    6,095,943
Purchased                               1,376,221    1,301,636    2,437,433    2,343,484    1,998,882    1,646,244
                                       ----------   ----------   ----------   ----------   ----------   ----------
  Total electric energy                 8,736,945    8,195,401    8,170,773    8,671,274    8,099,721    7,742,187
                                       ----------   ----------   ----------   ----------   ----------   ----------
System Net Capability -
  KW at December 31
Fossil                                    526,000      526,000      529,000      529,000      532,000      541,000
Nuclear                                   638,000      638,000      638,000      640,000      617,000      620,000
Hydro                                      47,000       47,000       47,000       47,000       47,000       47,000
Other                                      28,000       28,000       28,000       28,000       29,000       29,000
Purchased                                 349,000      375,000      375,000      375,000      375,000      347,000
                                       ----------   ----------   ----------   ----------   ----------   ----------
  Total system net capability           1,588,000    1,614,000    1,617,000    1,619,000    1,600,000    1,584,000
                                       ----------   ----------   ----------   ----------   ----------   ----------
Net Peak Load - KW                      1,388,000    1,421,000    1,305,000    1,425,000    1,374,000    1,333,000
Annual Load Factor - Net %                   59.5         56.1         61.9         57.6         58.8         59.1
 
</TABLE>

*     Includes sales to energy marketers and bulk sales.
<PAGE>
 
                                       13

Gas Department Statistics

<TABLE>
<CAPTION>
 
  Year Ended December 31                   1998        1997         1996         1995         1994        1993
                                        ----------   ----------  ----------   ---------     --------   ----------
<S>                                    <C>          <C>          <C>          <C>          <C>          <C>
Gas Revenue (000's)
Residential                             $    2,944   $    5,852  $    6,010  $    4,081   $    5,935   $    5,526
Residential spaceheating                   201,686      249,101     246,945     230,934      215,974      201,129
Commercial                                  40,196       51,893      52,073      51,117       49,115       46,321
Industrial                                   4,222        5,800       6,175       6,686        7,088        6,368
Municipal and other                         25,492       23,663      35,076       1,045       47,949       34,364
                                        ----------   ----------  ----------   ---------     --------   ----------
  Total gas revenue                        274,540      336,309     346,279     293,863      326,061      293,708
                                        ----------   ----------  ----------   ---------     --------   ----------
Gas Expense (000's)
Gas purchased for resale                   155,497      196,579     202,297     167,762      194,390      166,884
Other operation                             63,014       63,416      61,348      59,684       49,312       47,593
Maintenance                                  5,188        5,418       5,634       5,194        7,774        9,229
Depreciation                                12,867       13,127      12,999      12,781       12,250       11,851
Taxes - local, state and other              27,672       30,685      31,858      31,514       31,859       30,849
                                        ----------   ----------  ----------   ---------     --------   ----------
  Total gas expense                        264,238      309,225     314,136     276,935      295,585      266,406
                                        ----------   ----------  ----------   ---------     --------   ----------
Operating Income before
  Federal Income Tax                        10,302       27,084      32,143      16,928       30,476       27,302
Federal income tax                             (92)       3,442       7,600       6,715        8,403        5,485
                                        ----------   ----------  ----------   ---------     --------   ----------
Operating Income from
  Gas Operations (000's)                $   10,394   $   23,642  $   24,543  $   10,213   $   22,073   $   21,817
                                        ----------   ----------  ----------   ---------     --------   ----------
Gas Operating Ratio %                         81.5         78.9        77.8        79.2         77.1         76.2

Gas Sales - Therms (000's)
Residential                                  3,599        5,773       6,455       7,167        6,535        6,871
Residential spaceheating                   239,740      285,395     299,085     280,763      283,039      295,093
Commercial                                  53,552       65,675      70,543      68,380       72,410       78,887
Industrial                                   6,079        7,828       9,334       9,560       11,420       12,030
Municipal                                    6,388        7,331       8,086       8,219       10,230       12,188
                                        ----------   ----------  ----------   ---------     --------   ----------
  Total gas sales                          309,358      372,002     393,503     374,089      383,634      405,069
Transportation of customer-owned gas       163,575      166,060     167,779     146,149      136,372      124,436
                                        ----------   ----------  ----------   ---------     --------   ----------
  Total gas sold and transported           472,933      538,062     561,282     520,238      520,006      529,505
                                        ----------   ----------  ----------   ---------     --------   ----------
 
 
Gas Customers at December 31
 
Residential                                 16,944       16,265      16,718      17,443       17,836       18,389
Residential spaceheating                   249,684      243,264     240,685     238,267      235,313      231,937
Commercial                                  18,633       19,118      19,045      18,978       18,742       18,636
Industrial                                     778          829         857         879          905          924
Municipal                                      965        1,117         961         981          988        1,001
Transportation                               1,900          836         744         655          558          466
                                        ----------   ----------  ----------   ---------     --------   ----------
  Total gas customers                      288,904      281,429     279,010     277,203      274,342      271,353
                                        ----------   ----------  ----------   ---------     --------   ----------
Gas - Therms (000's)
Purchased for resale                       203,677      274,430     279,353     237,728      262,267      347,778
Gas from storage                           111,164      104,317     122,843     152,852      134,802       76,378
Other                                        1,496        1,410       1,082       1,800        2,959        1,039
                                        ----------   ----------  ----------   ---------     --------   ----------
  Total gas available                      316,337      380,157     403,278     392,380      400,028      425,195
                                        ----------   ----------  ----------   ---------     --------   ----------
Total Daily Capacity -
  Therms at December 31*                 4,380,000    4,380,000   4,480,000   5,230,000    5,625,000    5,625,000
                                        ----------   ----------  ----------   ---------     --------   ----------
 
Maximum daily throughput - Therms        3,583,500    4,114,290   4,022,600   3,980,000    4,735,690    3,864,850
Degree Days (Calendar Month)
For the period                               5,666        6,916       6,998       6,535        6,699        7,044
Percent colder (warmer) than normal          (15.9)         2.8         3.9        (3.0)        (0.6)         4.4
 
</TABLE>

* Method for determining daily capacity, based on current network analysis,
  reflects the maximum demand which the transmission systems can accept without
  a deficiency.
<PAGE>
 
                                       14

Item 2.  PROPERTIES



ELECTRIC PROPERTIES



     The net capability of the Company's electric generating plants in operation
as of December 31, 1998  and the net generation of each plant for the year ended
December 31, 1998, and the year each plant was placed in service are as set
forth below:



Electric Generating Plants

<TABLE>
<CAPTION>
 
                                                     Net         Net
                                  Year Unit      (Nameplate)  Generation
                                  Placed in      Capability   thousands
                 Type of Fuel      Service          (Mw)         (KWH)
                 ------------     ---------       ----------   ---------
<S>              <C>              <C>            <C>          <C> 

Beebee Station
  (Steam)           Coal             1959            80          508,476

Beebee Station
  (Gas Turbine)     Oil              1969            14               86

Russell Station
  (Steam)           Coal          1949-1957         257        1,393,216

Ginna Station
  (Steam)           Nuclear          1970           480        4,308,112

Oswego Unit 6/(1)/
  (Steam)           Oil              1980           189           61,197

Nine Mile Point
  Unit No. 2/(2)/
  (Steam)           Nuclear          1988           158        1,015,527

Station No. 9
  (Gas Turbine)     Gas              1969            14              109
 
Station 5
  (Hydro)           Water            1917            39          150,779

5 Other Stations
  (Hydro)           Water         1906-1960           8           38,733
                                                  -----        ---------
                                                               7,476,235
Pumped Storage /(3)/                                             232,927
Less: energy for pumping                                        (348,438)
                                                               ---------
                                                  1,239        7,360,724
                                                  =====        =========
</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>
 
                                       15

     The Company owns 147 distribution substations having an aggregate rated
transformer capacity of 2,172,154 Kva, of which 138, having an aggregate rated
capacity of 1,992,988 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 71,407 line
transformers with a capacity of 2,850,977 Kva. The Company also owns 24
transmission substations having an aggregate rated capacity of 3,065,617 Kva of
which 23, having an aggregate rated capacity of 2,990,950 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 405 circuit
miles of underground lines. The distribution system consists of approximately
16,264 circuit miles of overhead lines, approximately 3,917 circuit miles of
underground lines and 353,512 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 consist of 4,273 miles of gas mains and
294,844 installed meters. (See Item 1 - Business, "Gas Operations" and "Gas
Department Statistics".

UNREGULATED SUBSIDIARIES

  Griffith, acquired by Energetix in August 1998, owns or leases 47 properties
for use in its business operations. These properties consist of:

  -         (3) Pipeline Terminal facilities: these major bulk petroleum storage
       facilities are primarily supplied by pipeline and have an aggregate
       storage capacity of approximately 475,000 barrels.
  -         (10) Bulk Plant Facilities: these bulk petroleum facilities are
       primarily supplied by truck and have an aggregate storage capacity of
       105,000 barrels.
  -        (14) Service Stations: these retail sites are sublet to a dealer who
       provides various services at retail to the general public.
  -        (20) Other properties: there are a mixture of other properties
       including office buildings, warehouses and garage facilities used in the
       general operation of the business.


OTHER PROPERTIES

     The Company owns a ten-story office building centrally located in Rochester
and other structures and property. On December 1, 1998 the Company purchased a
natural gas combined cycle generating facility rated at approximately 65 mw,
which it intends to operate in 1999. The Company also leases approximately
502,000 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
<PAGE>
 
                                       16

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). Mortgages securing the Company's revolving credit agreement and a
long term note are also liens 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.

Item 3.  LEGAL PROCEEDINGS

     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 seven Company-owned sites where past waste
handling and disposal may have occurred. Remediation activities at five of these
sites are in various stages of planning or completion and the Company is
conducting a program to restore the other two sites. The Company has recorded a
total liability of approximately $21.6 million which it anticipates spending on
SIR efforts at the seven Company-owned sites. Through December 31, 1998 the
Company has incurred aggregate costs of $5.4 million for these sites.



     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 seven Company-owned sites three are listed
in this inventory. These are East Station, Front Street and Brooks Avenue, all
located in Rochester, NY. In addition to these three sites, the inventory
includes Ambrose Yard and Lindberg Heat Treating. These two sites are owned by
the Company (and are in addition to the seven mentioned above) however, the
Company does not believe that additional SIR work for which the Company is
responsible is required at either site. At this time, the Company is unable to
predict what action will be necessitated as a result of the listing.



     Manufactured Gas Sites. The Company and its predecessors formerly owned and
operated five manufactured gas facilities for which SIR costs are estimated to
be approximately $20 million. Three sites, located in the Rochester area are
known as West Station, East Station and Front Street. Cleanup activities on a
portion of the West Station site 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 site 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. A supplemental remedial
investigation and feasibility study is in progress and is expected to be
completed in early 1999.

     At the third site (Front Street) a boring placed in the fall of 1988 for a
sewer system project showed a layer containing a black viscous material. The
study of the layer found that some of the soil and ground water on-site had been
adversely impacted. The matter was reported to the NYSDEC and, in September
1990, the Company also provided the agency with a risk assessment. The Company
signed a consent order to perform limited remedial activities. That work was
completed in late 1998. Additional investigative work and remedial action is
expected to occur under separate agreement now under negotiation.
<PAGE>
 
                                       17

     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 NYSDEC
is awaiting the Company's proposal for supplemental remedial investigation.

  A preliminary phase 1 investigation was completed in 1998 on a 3/4 acre site
located in Brockport, New York. Evidence from residuals from gas manufacturing
operations suggest further investigation is necessary and may ultimately warrant
remedial action. No estimates can be made based on available information at this
time.

     Other Sites. On another portion of the Company's property in Rochester, NY
(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 waste materials (the materials) found there. In a November 1997 letter,
the County claimed that the Company was the original generator of the materials
and asserted that the Company was liable to the County for 50% of all County
costs incurred to date to excavate, treat and dispose of the materials placed in
the ponds and to implement whatever further cleanup activities may be required
by the NYSDEC. The Company and the County have reached a settlement in principle
and are working out the details of a written settlement agreement. Pursuant to
the settlement, the Company will bear 20% of the remediation costs and has
committed to be responsible for the construction management function. The
Company's overall costs are estimated to be approximately $1.3 million,
excluding a 20% share of ongoing long-term operation and maintenance work which
is judged to be insignificant at this time. There is a mutual waiver and release
as to all past claims regarding this property.



     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 at eight sites not owned by it and has
recorded estimated liabilities of approximately $.8 million in connection with
SIR efforts at these sites. The Company has signed orders on consent for five of
these sites.


     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 site any remedial measures which federal or State authorities may
require, but 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 $500,000. 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.
<PAGE>
 
                                       18



     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 $232,000.

     The Company has been named as a PRP at three other sites and has been
associated with two other sites for which the Company's share of total
additional projected costs is not expected to exceed $30,000. 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.

     The Company has begun negotiations with its past insurance carriers seeking
to obtain coverage for environmental remediation costs at some Company
locations.

     GRIFFITH OWNED SITES. In connection with its Big Flats, New York terminal,
Griffith has been complying with the Unilateral Administrative Order issued by
the EPA. Pursuant to a cost sharing agreement with Sun Pipe Line Company,
Griffith continues to undertake one-half of the costs necessary to comply with
the order. To date Griffith has spent $1.6 million on this compliance. Griffith
continues to disclaim that it is either the owner or operator of a failed spur
where petroleum was discharged, and compliance is proceeding on this basis
accordingly.

     Since February 1996, Griffith has been involved in a legal proceeding in
New York State Supreme Court for Steuben County, related to the environmental
matter in the above paragraph. In Steuben Contracting v. Sun Pipe Line Company,
Griffith Oil Co., Inc. and Chevron, USA, the plaintiff is seeking compensation
for property damage associated with petroleum discharge at Big Flats. The
parties have engaged in depositions and disclosure activities. Such disclosure
has not revealed any facts that have altered Griffith's position that the other
parties reimburse Griffith for costs, expenses and damages associated with site
remediation at Big Flats.

     In May 1998, the State of New York (State of New York v. Griffith Oil Co.,
Inc.) commenced an action against Griffith in New York State Supreme Court for
Albany County, for statutory penalties in connection with the discharge of
petroleum at Big Flats, New York. The complaint alleges Griffith failed to
report the discharge within two hours of discovery, and further alleges a
violation of Griffith's Major Oil Storage Facility License for failure to report
such discharge. Griffith has answered the complaint and denied the allegations.
Griffith's position is that it complied with practice established with DEC, and
promptly reported the discharge upon confirmation of the presence of subsurface
petroleum. Griffith has offered to settle this matter for $15,000 subject to a
mutually acceptable agreement of settlement. Griffith continues to deny
responsibility for this matter and unless otherwise settled will defend this
matter in the usual course.

     In April 1998, the State of New York commenced an action against Griffith
and other parties (State of New York v. Griffith Oil Co., Inc., Sugar Creek
Stores, Inc. and Mahl Bros. Oil Co., Inc. [Springville Bulk Plant]) in New York
State Supreme Court for Erie County, for reimbursement of the sum of $180,962.43
to the New York Environmental Protection and Spill Compensation Fund in
connection with subsurface petroleum contamination in the vicinity of
Springville, New York. Until December 1997, Griffith leased a petroleum bulk
storage facility at the location. Cross-claims also exist among the defendants
related to causes of action associated with the contamination and lease of the
property. While the presence of subsurface contamination is evident, an analysis
of the contamination is substantially associated with a parent product produced
no later than 1985. This date precedes the interest of Griffith. Griffith will
continue to vigorously defend this matter.

     In connection with the acquisition of Griffith by Energetix, a stock
purchase agreement obligates the Seller to pay for environmental claims or
remedial action on Griffith property once the amount of environmental losses
incurred by Energetix exceeds
<PAGE>
 
                                       19

$3.5 million less any reserve reflected on the balance sheet at the time of
acquisition. The amount of that reserve at the time of acquisition was $1.9
million.

     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, 1998.

Item 4-A.  EXECUTIVE OFFICERS OF THE REGISTRANT

                       Age    Positions, Offices and Business Experience
Name                 1/1/99                 1994 to date
----                 -------  ------------------------------------------
Thomas S. Richards      55    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
                              - 1994 to August, 1994.

Michael J. Bovalino     43    President and Chief Executive Officer, 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.

J. Burt Stokes          55    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.
<PAGE>
 
                                       20

                     Age at   Positions, Offices and Business Experience
Name                 1/1/99                   1994 to date
----                 ------   ------------------------------------------
Michael T. Tomaino      61    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.

Paul C. Wilkens         51    Senior Vice President, Generation - March 1998 to
                              Date.

                              Director, Gas Services - January 1996 -
                              March 1998.
 
                              Principal Consultant - May 1995 - January 1996.

                              Department Manager - Nuclear Engineering
                              Services - 1994 - May 1995.

William J. Reddy        51    Controller - April 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
                              1994 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>
 
                                       21

                                    PART II
                                        


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




COMMON STOCK AND DIVIDENDS

<TABLE>
<CAPTION>
 
 
Earnings/Dividends           1998   1997    1996         Shares/Shareholders            1998    1997    1996
--------------------------  ------ ------  -------       -----------------------       ------  ------  ------
<S>                         <C>    <C>    <C>             <C>                          <C>     <C>     <C>
Earnings per share                                        Number of shares (000's)
  - basic                   $2.32  $2.30   $2.32          Weighted average - basic     38,462  38,853  38,762
 - diluted                  $2.31  $2.30   $2.32                           - diluted   38,600  38,909  38,762
  
Dividends paid                                            Actual number at
  per share                 $1.80  $1.80   $1.80               December 31             37,379  38,862  38,851
                                                          Number of shareholders
                                                               at December 31          28,995  31,337  33,675
 </TABLE>

TAX STATUS OF CASH DIVIDENDS

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

DIVIDEND POLICY

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



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

COMMON STOCK TRADING

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

<TABLE>
<CAPTION>
 
Common Stock - Price Range      1998      1997      1996
----------------------------  --------  --------  --------
<S>                           <C>       <C>       <C>    
  High
     1st quarter              33  1/4   20   3/8  23 3/4
     2nd quarter              32  3/4   21  7/16  21 7/8
     3rd quarter              32 7/16   24 15/16  21 3/8
     4th quarter              33  1/4   34   1/2  19 5/8
 
  Low
     1st quarter              29   1/2  18   7/8  21 1/4
     2nd quarter              29  5/16  18        19 7/8
     3rd quarter              28   3/8  20   5/8  18
     4th quarter              28  9/16  23   3/4  17 7/8
  At December 31              31   1/4  34        19 1/8
</TABLE>
<PAGE>
 
                                      22

 
ITEM 6 - SELECTED FINANCIAL DATA

CONSOLIDATED SUMMARY OF OPERATIONS

<TABLE>
<CAPTION>

(Thousands of Dollars)   Year Ended December 31            1998       1997*      1996*          1995*      1994*     1993*
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>        <C>         <C>           <C>        <C>        <C>   
Operating Revenues
  Electric                                                $687,970   $700,329    $707,768      $722,465   $674,753  $655,316
  Gas                                                      275,177    336,309     346,279       293,863    326,061   293,708
  Other                                                     71,215          -           -             -          -         - 
                                                         ---------   --------    --------     ---------   --------  -------- 
                                                                                                                    
      Total Operating Revenues                           1,034,362  1,036,638   1,054,047     1,016,328  1,000,814   949,024
                                                                                                                    
Operating Expenses                                                                                                  
  Fuel Expenses                                                                                                     
    Fuel for electric generation                            53,954     47,665      40,938        44,190     44,961    45,871
    Purchased electricity                                   27,024     28,347      46,484        54,167     37,002    31,563
    Gas purchased for resale                               155,497    196,579     202,297       167,762    194,390   166,884
    Unregulated fuel expenses                               60,001          -           -             -          -         - 
                                                         ---------   --------    --------     ---------   --------  -------- 
      Total Fuel Expenses                                  296,476    272,591     289,719       266,119    276,353   244,318
                                                         ---------   --------    --------     ---------   --------  -------- 
                                                                                                                    
Operating Revenues Less Fuel Expenses                      737,886    764,047     764,328       750,209    724,461   704,706
                                                                                                                    
  Other Operating Expenses                                                                                          
    Operations and maintenance excluding fuel expenses     301,625    315,109     313,157       308,433    296,741   302,035
    Unregulated operating and maintenance expenses                                                                  
     excluding fuel                                         13,257          -           -             -          -         -
    Depreciation and amortization                          116,122    116,522     105,614        91,593     87,461    84,177
    Taxes - local, state and other                         118,337    121,796     126,868       133,895    129,778   126,892
    Federal income tax - current                            70,541     69,812      65,757        65,368     35,658    33,453
                       - deferred                           (9,156)    (4,533)      3,744           847     25,587    15,877
                                                         ---------   --------    --------     ---------   --------  -------- 
      Total Other Operating Expenses                       610,726    618,706     615,140       600,136    575,225   562,434
                                                         ---------   --------    --------     ---------   --------  -------- 
                                                                                                                    
Operating Income                                           127,160    145,341     149,188       150,073    149,236   142,272
                                                                                                                    
Other (Income) and Deductions                                                                                       
  Allowance for other funds used during                                                                             
    construction                                              (408)      (351)       (684)         (585)      (396)     (153)
  Federal income tax                                           516     (3,704)     (3,450)      (16,948)   (16,259)   (9,827)
  Regulatory disallowances                                       -          -           -        26,866        600     1,953
  Pension Plan Curtailment                                       -          -           -             -     33,679     8,179
  Other, net                                               (13,181)     3,308        (712)        9,631       (923)    2,113
                                                         ---------   --------    --------     ---------   --------  -------- 
      Total Other (Income) and Deductions                  (13,073)      (747)     (4,846)       18,964     16,701     2,265
                                                                                                                    
Interest Charges                                                                                                    
  Long term debt                                            42,590     44,615      48,618        53,026     53,606    56,451
  Short term debt                                              431         47          21           398      1,808     1,487
  Other, net                                                 3,727      6,629       9,307         8,658      4,758     5,220
  Allowance for borrowed funds used during                                                                          
    construction                                              (653)      (563)     (1,423)       (2,901)    (2,012)   (1,714)
                                                         ---------   --------    --------     ---------   --------  -------- 
      Total Interest Charges                                46,095     50,728      56,523        59,181     58,160    61,444
                                                                                                                    
Net Income                                                  94,138     95,360      97,511        71,928     74,375    78,563
                                                                                                                    
Dividends on Preferred Stock                                                                                        
   at required rates                                         4,842      5,805       7,465         7,465      7,369     7,300
                                                         ---------   --------    --------     ---------   --------  -------- 
Earnings Applicable to Common Stock                        $89,296    $89,555     $90,046       $64,463    $67,006   $71,263
                                                         ==========  =========   =========    ==========  ========= =========
                                                                                                                    
Earnings per Common Share - Basic                            $2.32      $2.30       $2.32         $1.69      $1.79     $2.00
                                                                                                                    
Earnings per Common Share - Diluted                          $2.31      $2.30       $2.32         $1.69      $1.79     $2.00
                                                                                                                    
Cash Dividends Declared per Common Share                     $1.80      $1.80       $1.80         $1.80      $1.77     $1.73

</TABLE>
* Reclassified for comparative purposes.

<PAGE>
 
                                      23

 
CONDENSED CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>

(Thousands of Dollars)       At December 31           1998          1997*         1996*         1995*         1994*         1993*
------------------------------------------------------------------------------------------------------------------------------------
<S>                                               <C>           <C>           <C>           <C>           <C>           <C>
Assets
Utility Plant                                      $3,326,995    $3,234,077    $3,159,759    $3,068,103    $2,981,151    $2,890,799
Less: Accumulated depreciation and                                                                                                 
    amortization                                    1,863,475     1,714,368     1,569,078     1,518,878     1,423,098     1,335,083
                                                  ------------  ------------  ------------  ------------  ------------  ------------
                                                    1,463,520     1,519,709     1,590,681     1,549,225     1,558,053     1,555,716
Construction work in progress                          98,554        74,018        69,711       121,725       128,860       112,750
                                                  ------------  ------------  ------------  ------------  ------------  ------------
Net utility plant                                   1,562,074     1,593,727     1,660,392     1,670,950     1,686,913     1,668,466
Current Assets                                        202,963       242,371       250,461       292,596       236,519       248,589
Investment in Empire                                        -             -             -        38,879        38,560        38,560
Intangible Assets                                      21,062             -             -             -             -             -
Deferred Debits and Other Assets                      666,836       432,191       450,623       453,726       484,962       488,527
                                                  ------------  ------------  ------------  ------------  ------------  ------------
      Total Assets                                 $2,452,935    $2,268,289    $2,361,476    $2,456,151    $2,446,954    $2,444,142
                                                  ------------  ------------  ------------  ------------  ------------  ------------
                                                                                                                                   
CAPITALIZATION AND LIABILITIES                                                                                                     
Capitalization                                                                                                                     
Long term debt                                       $758,226      $587,334      $646,954      $716,232      $735,178      $747,631
Preferred stock redeemable at option                                                                                               
  of Company                                           47,000        47,000        67,000        67,000        67,000        67,000
Preferred stock subject to mandatory                                                                                               
  redemption                                           25,000        35,000        45,000        55,000        55,000        42,000
Common shareholders' equity:                                                                                                       
  Common stock                                        699,730       699,031       696,019       687,518       670,569       652,172
  Retained earnings                                   129,484       109,313        90,540        70,330        74,566        75,126
  Less: Treasury stock at cost (1,507,000 shares)      46,433             -             -             -             -             -
                                                  ------------  ------------  ------------  ------------  ------------  ------------
Total common shareholders' equity                     782,781       808,344       786,559       757,848       745,135       727,298
                                                  ------------  ------------  ------------  ------------  ------------  ------------
      Total Capitalization                          1,613,007     1,477,678     1,545,513     1,596,080     1,602,313     1,583,929
                                                  ------------  ------------  ------------  ------------  ------------  ------------
                                                                                                                                   
Long Term Liabilities (Department                                                                                                  
  of Energy and Site Remediation)                     123,920       110,352       106,578       101,561        88,500        89,804
Current Liabilities                                   183,369       175,691       145,391       171,664       180,653       234,530
Deferred Credits and Other Liabilities                532,639       504,568       563,994       586,846       575,488       535,879
                                                  ------------  ------------  ------------  ------------  ------------  ------------
      Total Capitalization and Liabilities         $2,452,935    $2,268,289    $2,361,476    $2,456,151    $2,446,954    $2,444,142
                                                  ------------  ------------  ------------  ------------  ------------  ------------
</TABLE>
* Reclassified for comparative purposes.

<PAGE>
 
                                       24


Financial Data


<TABLE>
<CAPTION>
     At December 31                             1998    1997    1996     1995    1994   1993
                                                ----    ----    ----     ----    ----   ----
<S>                                            <C>     <C>     <C>     <C>     <C>     <C>
Capitalization Ratios (a) (percent)
Long-term debt                                   49.8    43.0    44.7    47.4    48.2    49.4
Preferred Stock                                   4.2     5.2     6.9     7.3     7.3     6.6
Common shareholders' equity                      46.0    51.8    48.4    45.3    44.5    44.0
                                               ------  ------  ------  ------  ------  ------
   Total                                        100.0   100.0   100.0   100.0   100.0   100.0
 
 
Book Value per Common Share - Year End         $20.94  $20.80  $20.24  $19.71  $19.78  $19.70
Rate of Return on Average Common Equity (b)
  (percent)                                     11.22   11.00   11.41    8.37    8.92   10.25
 
Embedded Cost of Senior Capital (percent)
Long-term debt                                   7.20    7.32    7.33    7.38    7.40    7.36
Preferred stock                                  5.56    5.80    6.26    6.26    6.26    6.69
Effective Federal Income Tax Rate (percent)      39.7    39.2    40.4    40.7    37.7    33.5
Depreciation Rate (percent) - Electric           3.09    3.12    2.99    2.76    2.69    2.62
                            - Gas                2.64    2.60    2.60    2.59    2.62    2.60
Interest Coverages
Before federal income taxes (incld. AFUDC)       4.41    4.06    3.82    2.95    2.98    2.87
                            (excld. AFUDC)       4.38    4.04    3.79    2.90    2.94    2.84
After federal income taxes (incld. AFUDC)        3.06    2.86    2.68    2.16    2.24    2.24
                           (excld. AFUDC)        3.03    2.84    2.65    2.10    2.20    2.21
Interest Coverages Excluding Non-Recurring
   Items (c)
Before federal income taxes (incld. AFUDC)       4.41    4.06    3.82    3.66    3.55    3.03
                       (excld. AFUDC)            4.38    4.04    3.79    3.61    3.51    3.00
 
After federal income taxes (incld. AFUDC)        3.06    2.86    2.68    2.62    2.61    2.35
                           (excld. AFUDC)        3.03    2.84    2.65    2.57    2.57    2.32
 
</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)  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>
 
                                       25


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


INTRODUCTION

     The following is Management's assessment of certain significant factors
affecting the financial condition and operating results of Rochester Gas and
Electric Corporation ("RG&E") and its subsidiaries (RG&E, together with its
subsidiaries, is referred to as "the Company") over the past three years. The
Consolidated Financial Statements and the Notes thereto contain additional data.
For the twelve months ended December 31, 1998, 66 percent of the Company's
operating revenues were derived from electric service, 27 percent from natural
gas service, and 7 percent from unregulated businesses.

     The discussion presented below contains statements which are not historic
fact and which can be classified as forward looking.  These statements can be
identified by the use of certain words which suggest forward looking
information, such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words which relate to
future goals or strategies.  In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant difference in whether the forward
looking statements ultimately prove to be accurate include:

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

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

(3) any changes in the regulatory status of nuclear generating facilities and
their related costs, including recovery of costs related to spent fuel and
decommissioning;

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

(5) the development of any new technologies which allow customers to
generate their own energy or produce lower cost energy;

(6) any unusual or extreme weather or other natural phenomena;

(7) the ability of the Company to manage profitably new unregulated operations;

(8) certain unknowable risks involved in operating unregulated businesses in new
territories and new industries;

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

(10) any unanticipated developments associated with identifying, assessing,
fixing and testing the modifications necessary to mitigate Year 2000 compliance
problems, including the possible indirect impact of customers, suppliers and
other business partners who do not sufficiently mitigate their Year 2000
compliance problems; and

(11) any other considerations that may be disclosed from time to time in the
Company's publicly disseminated documents and filings.
<PAGE>
 
                                       26

Shown below is a listing of the principal items discussed.

     Earnings Summary                                           Page 26

     Competition                                                Page 27
          PSC Competitive Opportunities Case Settlement
          Business and Financial Strategy
          PSC Proceeding on Nuclear Generation
          FERC Open Access Transmission Orders and
           Company Filings
          PSC Gas Restructuring Policy Statement
          Prospective Financial Position


     Rates and Regulatory Matters                               Page 33
          Gas Proposal and Interim Settlement
          Flexible Pricing Tariff

     Liquidity and Capital Resources                            Page 34
          Capital and Other Requirements
          Environmental Issues
          Redemption of Securities
          Financing

     Results of Operations                                      Page 38
          Operating Revenues and Sales
          Fossil Unit Status
          Operating Expenses

     Dividend Policy                                            Page 43



EARNINGS SUMMARY

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

     Basic earnings per share were $2.32 in 1998, compared with $2.30 in 1997,
and $2.32 a year earlier. Earnings per Common Share - Diluted were $2.31 in
1998, $2.30 in 1997, and $2.32 in 1996.  Earnings per share in 1998 were
improved by approximately $.02 per share resulting from the buyback of Common
Stock under the Company's Stock Repurchase Program.

     For the twelve month period ending December 31, 1998, the Company's
unregulated subsidiary, Energetix, Inc., had a pretax operating loss of $4.1
million, which reduced consolidated earnings by approximately $0.06 per basic
share.  This loss is primarily due to initial start-up and marketing costs.
Moreover, while Energetix  was formed January 1, 1998, the first revenues were
not received until April of 1998.  In addition, revenues from Griffith Oil Co.,
Inc., a company acquired by Energetix, only reflect sales since acquisition in
August 1998. Energetix revenues for 1999 from electric and gas operations are
expected to increase over 1998 levels as Energetix expands its customer base,
although no assurance may be given that Energetix will achieve a net operating
gain in 1999 or that new business opportunities will not impact its operating
results.
<PAGE>
 
                                       27

     The impact of developing competition in the energy marketplace may 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
several factors, including the availability of qualified energy suppliers in the
Company's service territory, 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 the development of its unregulated business opportunities as
permitted under the Settlement.

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


COMPETITION

     PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. During 1996 and 1997, RG&E,
the staff of the PSC and several other parties negotiated an agreement which was
approved by the PSC in November 1997 (the "Settlement").  The Settlement sets
the framework for the introduction and development of open competition in the
electric energy marketplace and lasts through June 30, 2002.  Over this time,
the way electricity is provided to customers will fundamentally change.  In
phases, RG&E will allow customers to purchase electricity, and later capacity
commitments, from sources other than RG&E through its retail access program,
Energy Choice.  These energy service companies will compete to package and sell
energy and related services to customers. The competing energy service companies
will purchase distribution services from RG&E who will remain the sole provider
of distribution services, and will be responsible for maintaining the
distribution system and for responding to emergencies.

     The Settlement sets RG&E's electric rates for each year during its five-
year term. Over the five-year term of the Settlement, the cumulative rate
reductions for the bundled service will be as follows: Rate Year 1 (July 1, 1997
to June 30, 1998) $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 Settlement permits RG&E to fund its unregulated operations with up to
$100 million.

     In the event that RG&E earns a return on common equity in excess of an
effective rate of 11.50 percent over the entire five-year term of the
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
<PAGE>
 
                                       28

permitted by SFAS-71, Accounting for the Effects of Certain Types of
Regulation). If certain extraordinary events occur, including a rate of return
on common equity 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.

     The Settlement requires RG&E to functionally separate its three regulated
operations: distribution, generation and retailing.  Additionally, unregulated
energy retailing operations must be structurally separate from the regulated
utility functions.  Although the Settlement provides incentives for the sale of
generating assets, it does not require RG&E to divest generating or other assets
or write-off stranded costs.  Additionally, RG&E will be given a reasonable
opportunity to recover substantially all of its prudently incurred costs,
including those pertaining to generation and purchased power.

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

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

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

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

     ENERGY CHOICE. On July 1, 1998, the Company launched its full-scale retail
Energy Choice Program. There are three basic components of the sale of energy:
the sale of electricity which is the amount of energy actually used by the
consumer, the sale of capacity which is the ability through generating
facilities or otherwise, to provide electricity when it is needed, and the sale
of distribution, which is the physical delivery of electricity to the consumer.
Historically, the Company has sold all three components bundled together for a
fixed rate approved by the PSC.  Up to ten percent of RG&E's retail electric
customers can now seek out or be approached by alternative energy service
companies for electricity to be delivered over RG&E's distribution system.
Participation in Energy Choice is limited to no more than 10 percent of RG&E's
total annual retail electric kilowatt-hour sales during the first year of the
program.  This limit increases to 20 percent the second year and 30 percent
<PAGE>
 
                                       29

in the third year.  In July, 2001, all retail customers will be eligible to
purchase energy from alternative energy service companies.

     The phase-in of the Energy Choice Program over the next few years
eventually will give retail electric customers the opportunity to purchase
energy, capacity and retailing services from competitive energy service
companies. They may also continue to purchase fully bundled electric service
from RG&E under existing retail tariffs.

     Energy Choice adopts the single-retailer model for the relationship between
the Company as the distribution provider, qualified energy service companies,
and retail (end-use) customers.  In this model, retail customers have the
opportunity for choice in their energy service company and receive only one
electric bill from the company that serves them.  With the exception of
emergency services, which remain the Company's responsibility, the retail
customers' primary point of contact is with their chosen energy service company.

  Under the single-retailer model, energy service companies are responsible for
buying or otherwise providing the electricity their retail customers will use,
paying regulated rates for transmission and distribution, and selling
electricity to their retail customers (the price of which would include the cost
of the electricity itself and the cost to transport electricity through RG&E's
distribution system).

     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 energy service company, 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), energy service companies
will be able to choose their own sources of energy supply, while RG&E will
continue to provide to them, through its bundled distribution rates, the
generating capacity (installed reserve) needed to serve their retail customers
reliably.

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

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

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

     During the initial "Energy Only" stage of the Retail Access Program, RG&E's
distribution rate will be set by deducting 2.3 cents per kilowatt-hour from its
full service ("bundled") rates.  The 2.3 cents per kilowatt-hour is comprised of
1.9 cents per kilowatt-hour (an estimate of the wholesale market price of
<PAGE>
 
                                       30

electricity) plus 0.4 cents per kilowatt-hour for its avoided cost of retailing
services.  During the "Energy and Capacity" stage, RG&E's distribution rates
will equal the bundled rate less RG&E's cost of the electric commodity and
RG&E's non-nuclear generating capacity.  During this stage of the program,
RG&E's distribution rates will be set by deducting 3.2 cents per kilowatt-hour,
inclusive of applicable gross receipts taxes, from its full service ("bundled")
rates.  The 3.2 cents per kilowatt-hour is comprised of 2.8 cents per kilowatt-
hour (an estimate of the wholesale market price of electric energy and capacity,
inclusive of gross receipts taxes) plus 0.4 cents per kilowatt-hour for its
avoided cost of retailing services.

     Through January 31, 1999, eight energy service companies, including
Energetix, the Company's unregulated subsidiary, have been qualified by RG&E to
serve retail customers under the Energy Choice Program.  In addition to
Energetix, these companies are Columbia Energy Power Marketing Corporation,
Enserch Energy Services (New York), Inc., Florida Power & Light (FPL Energy
Services), Inc., NEV East, L.L.C.(New Energy Ventures), Northeast Energy
Services, Inc.(NORESCO), North American Energy, and Select Energy Inc.
(Northeast Utilities Wholesale Power).  As of January 31, 1999, all energy
service companies have opted to purchase "full-requirements" from RG&E to serve
their retail customers.  As "full-requirements" customers, energy service
companies are able to purchase electricity from RG&E at 1.9 cents per kilowatt-
hour.  RG&E has distributed approximately 670,000 (annualized) megawatt-hours to
retail customers of energy service companies, thereby reaching 100 percent of
the first-year cap of 10% for the full-scale program.  This impact was not
significant because the loss of RG&E retail sales is roughly offset by the sale
of distribution service and electricity to energy service companies.  Although
it is too early to quantify at this time, a substantial part of this revenue
loss is expected to be offset by cost reductions resulting from the shift in
retailing responsibilities from RG&E to energy service companies.

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

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

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

     Subject to regulatory and shareholder approvals, the Company anticipates
forming the holding company structure by mid-1999.  FERC approved the Company's
<PAGE>
 
                                       31

application in late November 1998 and the NRC gave approval in December 1998.
The remaining regulatory approvals are expected to be received before mid-1999.

     At the Company's 1999 Annual Meeting of  Shareholders, shareholders will
vote on a Plan of Exchange which provides that all of the outstanding shares of
RG&E common stock will be exchanged on a share-for-share basis for RGS Energy
common stock.  Upon consummation of the exchange, RGS Energy will become the
parent company of RG&E.  Moreover, RG&E intends to transfer its unregulated
subsidiaries, Energetix and RGS Development Corporation, to RGS Energy
immediately prior to the exchange so that RGS Energy will become the parent
company of RG&E and such subsidiaries.

     The holding company structure is consistent with provisions of the
Competitive Opportunities Settlement.

     Unregulated Subsidiaries. It is part of RG&E's financial strategy to seek
growth by entering into unregulated businesses.  The Settlement allows RG&E to
invest up to $100 million in unregulated businesses.  The first step in this
direction was the formation and operation of Energetix effective January 1,
1998. Energetix is an unregulated subsidiary that brings energy products and
services to the marketplace both within and outside of RG&E's regulated
franchise territory. Energetix markets electricity, natural gas, oil, gasoline,
and propane fuel energy services in an area extending in approximately a 150-
mile radius around Rochester.

     In August 1998, Energetix announced the acquisition of Griffith Oil Co.,
Inc. ("Griffith"), the second largest oil and propane distribution company in
New York State.  Energetix accounted for its acquisition of Griffith as a
purchase in the amount of $31,500,000, and purchase accounting adjustments,
including goodwill, are reflected in the consolidated financial statements of
the Company at December 31, 1998.

     Griffith gives Energetix access to 65,000 new customers, 60,000 of which
are outside of RG&E's regulated franchise territory.  In addition to its current
products, Griffith sells electricity, natural gas and other services offered by
Energetix to its existing customers.  Griffith has approximately 350 employees
and operates 16 customer service centers.

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

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

     Stock Repurchase Plan. By order issued April 24, 1998, the PSC approved a
Stock Repurchase Plan providing for the repurchase of Common Stock having an
aggregate market value not to exceed $145 million. The Company began the
repurchase program in May 1998 and has repurchased 1,507,000 shares of Common
Stock for approximately $46.4 million through December 31, 1998.  The Company
expects to repurchase up to an additional three million shares over the next two
years.

     PSC PROCEEDING ON NUCLEAR GENERATION. On March 20, 1998, the PSC initiated
a proceeding to examine a number of issues raised by a Staff position paper on
nuclear generation and the comments received in response to it.  In reviewing
the Staff paper and parties' comments, the PSC:
<PAGE>
 
                                       32

(1)  adopted as a rebuttable presumption the premise that nuclear power should
     be priced on a market basis to the same degree as power from other sources,
     with parties challenging that premise having to bear a substantial burden
     of persuasion;

(2)  characterized the proposals in the Staff paper as by and large consistent
     in concept with the PSC's goal of a competitive, market-based electricity
     industry;

(3)  questioned Staff's position that would leave funding and other
     decommissioning responsibilities with the sellers of nuclear power
     interests and;

(4)  indicated interest in the potential for a New York Nuclear Operating
     Company (NYNOC) proposal to benefit customers through efficiency gains and
     directed pursuit of that matter in this nuclear generating proceeding or
     separately upon the filing of a formal NYNOC proposal.

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

     FERC OPEN ACCESS TRANSMISSION ORDERS AND COMPANY FILINGS. On January 31,
1997, the New York electric 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 (NYISO) will administer a Statewide 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 NYISO, the proposal calls for
creation of a New York Power Exchange and a New York State Reliability Council.

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

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

     PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC issued
a gas restructuring policy statement ("Gas Policy Statement") announcing its
conclusion that, among other things, the most effective way to establish a
competitive gas supply market is for gas distribution utilities to cease selling
gas.  The PSC established a transition process in which it plans to address
three groups of issues: (1) individual gas utility plans to implement the PSC's
vision of the market; (2) key generic issues to be dealt with through
collaboration among gas utilities, marketers, pipelines and other stakeholders,
and (3) coordination of issues that are common to both the gas and the electric
<PAGE>
 
                                       33

industries.  The Company is in the process of evaluating this Gas Policy
Statement and will respond to the specific requirements of the Order.  The PSC
has encouraged settlement negotiations with each gas utility pertaining to the
transition to a fully competitive gas market.

     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 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 made in facilities, or costs incurred to service customers, are not
fully recoverable in market-based rates.  Estimates of such strandable assets
are highly sensitive to assumptions of competitive wholesale market prices.  In
a competitive natural gas market, strandable assets could 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, 1998, the Company believes that its regulatory assets 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  issued an Opinion and
Order Instituting Further Inquiry on March 20, 1998 to address issues
surrounding nuclear generation.  The ultimate determination in this proceeding
could have an impact on strandable assets and the recovery of nuclear costs.
The initial meeting in this Inquiry was held in January 1999 and such a
determination is unlikely before year-end.


RATES AND REGULATORY MATTERS

     GAS PROPOSAL AND INTERIM SETTLEMENT. In August 1998, prior to issuance of
the PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Statement
above), RG&E had commenced negotiations with the PSC staff and other parties to
develop a comprehensive multi-year settlement of various issues, including rates
and the structure of RG&E's gas business.  Because the negotiation of a
comprehensive settlement is not anticipated to conclude until mid-1999, the
parties to the negotiations agreed to an Interim Settlement, effective November
1998 through June 1999, that deals with such issues as rates, transportation and
storage capacity costs, assignment of capacity, and retail access.  Under the
Interim Settlement, which was approved by the PSC on November 9, 1998, base
rates for gas service remain frozen at their current levels (which were fixed
pursuant to a 1995 Settlement that expired at the end of October 1998).
Additionally, RG&E must provide a guaranteed level of benefits to customers from
the re-marketing of unneeded transportation and storage capacity, and RG&E must
permit marketers serving up to ten percent of retail and aggregated customer
annual throughput to do so without mandatory assignment of the corresponding
capacity.  RG&E is permitted to recover the costs associated with non-assigned
capacity from all customers, with certain exceptions.

     An Interim Gas Settlement having been reached and the PSC having issued its
Gas Policy Statement, RG&E and other parties anticipate proceeding with
discussions with PSC Staff based on the Company's August 1998 comprehensive
proposal and the PSC's Gas Policy Statement.  RG&E's objective is to have a
<PAGE>
 
                                       34

comprehensive final settlement in place prior to July 1, 1999, although no
assurance can be given.

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

     FLEXIBLE PRICING TARIFF. Under its flexible pricing tariff for major
industrial and commercial electric customers, RG&E 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, RG&E 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 29 percent of all electric sales to customers
are made under long-term contracts, primarily to large industrial customers.
These contracts represent approximately 45 percent of RG&E's revenues from its
commercial and industrial customers.



LIQUIDITY AND CAPITAL RESOURCES

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

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

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

  The Company estimates that initially as many as 100,000 customers lost power
due to the storm. On Saturday afternoon, September 12, the Company announced
that all power had been restored, in all but a few isolated cases.

     In 1998, the Company incurred $7.2 million of costs associated with this
storm.  Under the Competitive Opportunities Settlement with the PSC, if
incremental costs resulting from a "catastrophic event" exceed $2.5 million,
such costs could be deferred.  The Company has submitted a petition to the PSC
for deferral of costs associated with this storm.
<PAGE>
 
                                       35

     Settlement with Co-generator.   In May 1998 the Company entered into a
Global Settlement Agreement regarding the termination of a power purchase
contract with Kamine/Besicorp Allegany L.P. (Kamine).  In August 1998 the PSC
approved the Global Settlement Agreement, and on December 1, 1998, the Agreement
became effective. The Global Settlement Agreement is discussed under Note 10 of
the Notes to Financial Statements.  Under the terms of the Global Settlement
Agreement the Power Purchase Agreement was terminated in consideration of
payment by the Company of $168 million over the next 16 years, without interest,
with an initial payment of $10 million. Also, under the terms of the Global
Settlement Agreement, the Company paid an additional $15 million for the
purchase of the Kamine generation facility. The plant may be operated if market
conditions warrant and the Company will assess the possible disposition of the
plant.  The Company does not expect the terms of the Global Settlement
Agreement to have any material effect on its earnings.  Pursuant to a PSC order
approving the terms of the Global Settlement Agreement, regulatory assets have
been established by the Company to account for the initial payment, the facility
purchase, and future payments. The Company has no other long-term obligations to
purchase energy from other cogeneration facilities.

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

  The Company identified the need to address Y2K issues early and in June 1996
established the Y2K Project (Y2K Project).  Resources from across the enterprise
have been committed to the Y2K Project. The Company has assigned approximately
40 full-time equivalent people to work on the Y2K Project as well as retaining
certain outside consultants to assist in the inventory, assessment, and
certification of date-aware devices.  The Company expects to fund its Y2K
Project internally and estimates it will incur between $10 to $12 million of
incremental costs through January 1, 2000, associated with making the necessary
modifications identified to date to applications ($11 million) and devices ($1
million). This projection includes contingencies and replacement systems that
may be required and represents 25% of the Corporate Information Technology (IT)
budget.  The Company has not deferred any other major IT project due to this
effort.  The Company has incurred approximately $5.3 million of its $12 million
total costs through December 31, 1998.  The Company is also participating in the
Y2K activities of several organizations such as the New York Power Pool, North
American Electric Reliability Council, Electric Power Research Institute and
others for the development of a network to verify the risks and costs
nationally, in the Northeast, in New York State, and in the Company.

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

  To date, the Y2K Project has completed the inventory phase, which was the
identification of internally developed applications, devices, vendor
applications and critical external parties including customers, suppliers,
business partners,
<PAGE>
 
                                       36

government agencies, and financial institutions. The Company will prioritize
these critical parties and independently evaluate the most critical of these by
various methods, such as mandatory written verification to the Company of their
status or testing transfer of information.

     The Y2K Project, in the assessment phase, has completed assessment of
internally developed applications and critical devices.  The Company expects to
complete the assessment of critical external parties and vendor applications by
the end of the first quarter of 1999.  Results of these assessments will be
given to the Business Areas for further action.

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

     Testing of internal applications for Y2K readiness has begun and is 28%
complete. Testing of critical applications, devices, and systems will take place
primarily in the first half of 1999 and is currently in the initial stages.

      The Company has in place a Business Recovery Plan describing alternative
processes and procedures to ensure the integrity of its energy and financial
systems.  The Business Recovery Plan will serve as the basis for Y2K contingency
plans.  Contingency planning commenced in October 1998 and is expected to be
completed by June 1999.  The Company will be able to identify its most
reasonably likely worst case Y2K contingency scenario by the end of the first
quarter of 1999 when it completes the Scenario Risk Analysis phase of
contingency planning. Failure to address Y2K issues properly could cause the
Company to, among other things, issue inaccurate bills, report inaccurate data,
or incur plant outages and/or energy delivery problems.

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

     Energetix, the Company's wholly owned subsidiary, including its recently
acquired Griffith, estimates the cost of making the necessary modifications
identified to date to be less than $100,000, 50% of which relate to devices and
50% to applications.  The cost represents approximately 50% of their IT budget,
but no major IT projects have been deferred due to Y2K.  Most of its systems,
personal computers and operating equipment are less than seven years old.
Energetix has identified items that are the most vulnerable to the Y2K problem
and is in various stages of assessing, fixing and testing those items. These
items are expected to be Y2K-ready by the third quarter of 1999, at which time a
Scenario Risk Analysis will be completed.  Energetix has a Business Recovery
Plan, which will serve as the basis for Y2K contingency planning by the third
quarter of 1999 also.   Energetix has begun to survey critical third parties
including customers, suppliers, business partners and financial institutions to
assess their degree of Y2K readiness and develop contingency plans to ensure the
integrity of its operational and financial systems.  Energetix will prioritize
these critical parties and independently evaluate the most critical of these by
various methods, such as mandatory verification of their status or testing
transfer of information.
<PAGE>
 
                                       37

     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.

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

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

     REDEMPTION OF SECURITIES.  In addition to first mortgage bond maturities
and mandatory sinking fund obligations over the past three years, discretionary
redemption of securities totaled $49 million in 1996, $152 million in 1997, and
$25.5 million in 1998.  Included in discretionary redemptions for 1997 and 1998
were over $127 million of tax-exempt securities.

     CAPITAL REQUIREMENTS - SUMMARY. Excluding the Kamine Global Settlement
obligations discussed above, capital requirements for the Company over the
three-year period 1996 to 1998 and the current estimate of capital requirements
through 2001 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.

Capital Requirements
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                            Actual            Projected
                                      1996  1997  1998     1999  2000  2001
<S>                                   <C>   <C>   <C>      <C>   <C>   <C>
Type of Facilities                          (Millions of Dollars)
-------------------------------------------------------------------------------
                                                      
Electric Property                                     
  Production                          $ 57  $  9  $ 16     $ 20  $ 11   $11
  Energy Delivery                       23    28    41       35    34    19
                                      ----  ----  ----     ----  ----   ---
     Subtotal                           80    37    57       55    45    30
  Nuclear Fuel                          16    19    14       16    27     9
                                      ----  ----  ----     ----  ----   ---
     Total Electric                     96    56    71       71    72    39
Gas Property                            17    22    21       18    21    19
Common Property                          6     9    21       24    14    11
                                      ----  ----  ----     ----  ----   ---
     Total                             119    87   113      113   107    69
Carrying Costs                                        
  Allowance for Funds Used During                     
     Construction                        2     1     1        1     1     1
                                      ----  ----  ----     ----  ----   ---
  Total Construction Requirements      121    88   114      114   108    70
Securities Redemptions, Maturities                    
  and Sinking Fund Obligations*         67   182    66       10    30    --
                                      ----  ----  ----     ----  ----   ---
     Total Capital Requirements       $188  $270  $180     $124  $138   $70
                                      ----  ----  ----     ----  ----   ---
</TABLE>
* Excludes prospective refinancings.
<PAGE>
 
                                       38

     FINANCING. On December 22, 1998 the Company issued $50 million of 5.84%
First Mortgage Bonds, Designated Secured Medium-Term Notes, Series B.  The net
proceeds from this financing were used to repay short-term debt.

     In September 1998 the Company completed the delivery of $25.5 million of
5.95% New York State Energy Research and Development Authority (NYSERDA) tax-
exempt bonds due September 1, 2033.  Proceeds were used to redeem $25.5 million
of outstanding tax-exempt First Mortgage 8 3/8% Bonds, Series OO, on December 1,
1998.

     Included on the Company's consolidated Balance Sheet as of December 31,
1998 is a $24.6 million Promissory Note issued by Energetix in connection with
the acquisition of Griffith in August 1998, as discussed under Competition -
Unregulated Subsidiaries.  This Note is payable in seven annual installments of
principal and interest.  Also included at year-end 1998 is a $94.8 million
liability associated with the $168 million Promissory Note issued in connection
with the Kamine Global Settlement Agreement (see Liquidity and Capital Resources
- Settlement with Co-Generator).  This amount represents the present value at
December 31, 1998 of future obligations under the Note assuming a discount rate
of 7.5 percent.  This Note is secured by a subordinate mortgage on the Company's
property.  Additional information about these Promissory Notes is discussed in
Note 6 of the Notes to Financial Statements.

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

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

     Capital requirements during 1999 are anticipated to be satisfied primarily
from the combination of internally generated funds and the use of short-term
credit arrangements with some external long-term financing possible during the
year. The Company may refinance long-term securities obligations during 1999
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 1998 to 1997 and 1997 to
1996. The Notes to Financial Statements contain additional information.

     INCOME STATEMENT CHANGES. Operating revenues have been reclassified into
three components.  Two of them, electric operating revenues and gas operating
revenues, include all regulated and unregulated sales of electricity and gas,
respectively. The third, other operating revenues, includes mainly sales from
<PAGE>
 
                                       39

Griffith, as well as other energy products.  Unregulated fuel expenses and
unregulated operating and maintenance expenses excluding fuel reflect certain
operating expenses of Energetix.

     OPERATING REVENUES AND SALES - SUMMARY. Total Company operating revenues in
1998 were $1,034 million, or 0.2% below 1997.  Revenues in 1998 reflect
unregulated operations as discussed below. For 1998, a decrease in electric base
rates and lower therm sales of gas due to milder weather during the heating
season were partially offset by higher wholesale electric sales.  In 1997,
operating revenues were lower than 1996 with the effect of RG&E's electric base
rate decreases in July 1996 and 1997 and lower therm sales of gas due to milder
weather partially offset by higher electric kilowatt-hour sales.

     Unregulated Operating Revenues and Sales. Included in total operating
revenues for 1998 are $10.6 million of electric and gas operating revenues
received by Energetix and $71.2 million of Griffith operating revenues.

     During 1998, Energetix derived 99% of its revenues (excluding Griffith
revenues) from electric and gas sales. The balance of revenues was derived from
ServiceCare, the appliance warranty service.  Electric sales do not reflect
significant seasonal variances. Gas revenues, however, are subject to seasonal
fluctuations due to the dependence on spaceheating sales during the heating
season.  While Energetix was formed January 1, 1998, its first revenues were not
received until April of 1998.  As a result, 1998 gas revenues reflect only a
small amount of spaceheating sales.

     During 1998 and since its acquisition by Energetix in August, Griffith
derived 97% of its total revenues from distillates (heating oil, kerosene, and
diesel), and gasoline sales.  The balance of revenues was mainly derived from
propane, servicing and motor lubricant sales.  Griffith separates the business
into three general segments: retail or residential, wholesale which consists of
large commercial and reseller accounts, and dealers or service stations.  For
distillates and propane sales, Griffith experiences seasonal fluctuations due to
the dependence on spaceheating sales during the heating season.  In addition,
gasoline sales reflect seasonal fluctuations due to increased consumer driving
during the warmer months.

     Regulated Operating Revenues and Sales.  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 13.6 percent warmer during the first three months of 1998 and
18.1 percent warmer for the entire year on a calendar month heating degree day
basis. Likewise, weather during 1997 was 1.2 percent warmer than 1996 on a
calendar month heating degree day basis.  The Company has no weather
normalization clause in its gas tariff; therefore, abnormal weather variations
will have a more pronounced effect on gas revenues.  Warmer summer weather
during 1998 boosted electric energy sales to meet the demand for air
conditioning usage, compared to the cool 1997 summer weather conditions.  On a
cooling degree day basis, weather in 1998 was 62 percent warmer than 1997, while
in contrast, the 1997 weather was approximately 27 percent cooler than 1996.

     Compared with a year earlier, kilowatt-hour sales of energy to retail
customers were down 3.6 percent in 1998, following a 1.2 percent increase in
1997. Commercial and industrial sales were down in 1998 due, in part, to the
opening of the electric market under terms of the Competitive Opportunities
Settlement.  Reported retail sales are depressed as former RG&E customers choose
an alternative energy supplier as permitted under the terms of the Competitive
Opportunities Settlement.  RG&E, however, also sells electric energy, as well as
distribution services, to qualified energy marketers in its franchise territory,
which has the effect of increasing electric wholesale sales and revenues as
<PAGE>
 
                                       40

discussed in the following paragraph. Partially offsetting the decline in
electric sales in 1998 to retail customers was the increased demand for air
conditioning usage caused by the warmer summer weather.  In contrast, cooler
summer weather had a negative impact on kilowatt-hour sales in 1997.

     Under its Energy Choice Program, RG&E on July 1, 1998 began selling
electricity and distribution services to qualified energy marketers to serve
their retail customers as permitted by the terms of the Competitive
Opportunities Settlement.  Electric sales to energy marketers, including the
Company's unregulated subsidiary Energetix, totaled 174,676 megawatt-hours in
1998.  Revenue from these energy marketers for electricity and distribution
services totaled $15.0 million and is included in electric operating revenues.

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

     The transportation of gas for large-volume customers who are able to
purchase natural gas from sources other than the Company is an important
component of the Company's marketing mix.  Company facilities are used to
distribute this gas, which amounted to 16.4 million dekatherms in 1998 and 16.6
million dekatherms in 1997.  These purchases by eligible customers have caused
decreases in the Company's retail gas customer revenues, with offsetting
decreases in purchased gas 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, are the same
as the rates charged the Company's retail gas service customers.  Moreover,
under the current regulatory environment, the Company does not earn a return on
the gas commodity it acquires for distribution.  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 12.1 percent in 1998, after
declining four percent in 1997.  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 1998 over 1997, while non-residential sales, including gas
transported, would have increased approximately two percent in 1998.  The
average use per residential gas customer, when adjusted for normal weather
conditions, showed a modest decrease in 1998 and 1997.

     FOSSIL UNIT STATUS. On January 21, 1998, the Company announced the
retirement of Beebee Station by mid-1999.  Factors such as the plant's age, lack
of a rail/coal delivery system and more stringent clean air regulations made the
plant uneconomical in the developing competitive generation business.  The
retirement of Beebee Station is not expected to have a material effect on the
Company's financial position or results of operations.  The plant will be fully
depreciated at the time of retirement.  The Competitive Opportunities Settlement
provides that all prudently incurred incremental costs associated with the
retirement and decommissioning of the plant are recoverable through the
Company's distribution access rates.  The electric capacity and energy currently
provided by the plant are expected to be replaced in the energy markets as
needed.
<PAGE>
 
                                       41


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

     The Sale Agreement provides for the allocation of proceeds and liabilities
pertaining to the Oswego 6 facility in accordance with the ownership interests
of the Company and Niagara Mohawk.  For purposes of the Sale Agreement, the
Company's 24% interest in the Oswego 6 facility has been deemed equivalent to a
12% interest in the entire Oswego Generation Facility, which consists of Oswego
6, another operational unit, Oswego 5, that is virtually identical to Oswego 6,
and four older, non-operational units, Oswego 1-4.  The Sale Agreement has been
approved by the PSC.  The bidding process continued into January 1999. The
Company cannot predict whether Oswego 6 will be sold or at what price. Under the
terms of the Competitive Opportunities Settlement, a gain for RG&E on such sale
would be shared between RG&E and its customers.  With regard to a loss on such
sale, the Settlement acknowledges an intent that RG&E 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
RG&E is to have a reasonable opportunity to recover such costs.  The electric
capacity and energy currently provided by the plant are expected to be replaced
in the energy markets as needed. The book value of the Company's interest in
Oswego 6 at December 31, 1998 was $53.8 million.


  OPERATING EXPENSES - SUMMARY.  Changes in fuel expenses for both comparison
periods reflect primarily the availability of Company generating facilities,
variations in sales of energy, and weather effects on gas purchased for resale
during the heating season.  For the 1998 comparison period, fuel expenses also
reflect unregulated operations.  Non-fuel operating expense was down in 1998
reflecting lower federal income taxes and a drop in other operating expenses
(see Operations, excluding Fuel Expenses), partially offset by recognition of
unregulated non-fuel operating expense.  For 1997, compared to a year earlier,
non-fuel operating expense was up due to higher depreciation expense, partially
offset by lower local and State taxes.

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

Regulated Operating Expenses

     Energy Costs - Electric.  Higher fuel expense for electric generation in
both comparison periods reflects increased generation to support higher electric
sales. For the 1998 comparison period, increased fuel expense also reflects
relatively more generation from the Company's costlier fossil-fueled units.  A
fuel cost adjustment clause was eliminated effective July 1, 1996. Company
shareholders are assuming the full benefits and detriments realized from actual
electric fuel costs and generation mix compared with PSC-approved forecast
amounts.



     RG&E 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
<PAGE>
 
                                       42

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.  In 1998, purchased electric expense also decreased reflecting greater
availability of the Company's generating facilities.


     Energy Management and Costs - Gas.  RG&E acquires gas supply and
transportation capacity based on its requirements to meet peak loads which occur
in the winter months.  RG&E 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 RG&E's current requirements.

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


     Operations Excluding Fuel Expenses.  For the 1998 comparison period,
operations less fuel expenses declined, reflecting decreased expense of $5.3
million associated with uncollectible accounts and a $7.9 million drop in
welfare expenses due to the performance of pension assets (see Note 3 to the
Notes to Financial Statements).  Partially offsetting these lower costs were
increased payroll costs of $2.2 million.  For the 1997 comparison period, the
increase in operations excluding fuel expenses reflects mainly higher outside
services expenses ($6.1 million), recognition of obsolete and unproductive
materials inventory ($3.0 million), and storm costs ($1.7 million) partially
offset by $3.9 million of lower payroll costs and decreased expense of $2.0
million associated with uncollectible accounts.  The recognition of obsolete
materials was driven by the planned relocation of the Company's warehouse.  The
decrease in the uncollectible accounts expense is driven by the increased level
of collection activity in the last two years.


     For the 1997 comparison period, the increase in depreciation and
amortization expense reflects primarily results from depreciation of the Ginna
nuclear plant steam generators, which were replaced in 1996 and recovery of
increased nuclear decommissioning expense of approximately $3.2 million per
quarter beginning July 1, 1996.  The higher decommissioning expense reflects an
increase in the estimated cost of decommissioning as recognized in rates for
Ginna Station and Nine Mile Two.  Depreciation and amortization expense in 1998
includes $1.1 million for unregulated operations, but remained relatively flat
compared to 1997 due to the completion of depreciation expense on certain fully
depreciated computer equipment.


     Taxes Charged To Operating Expenses. Local, State and other taxes declined
in 1998 reflecting mainly lower State revenue taxes due to decreased revenues.
This decline was partially offset by an additional $1.5 million of local and
State taxes associated with unregulated operations. The decrease in local and
State taxes for 1997 reflects mainly lower property taxes due to decreases in
assessments and/or rates and lower state revenue taxes due to decreases in
revenues and the New York State revenue tax surcharge rate.


     The decrease in federal income tax in 1998 reflects decreased earnings and
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.


     Other Statement of Income Items.  For the 1998 comparison period, the
variation in non-operating federal income tax reflects variances in non-
operating earnings before federal income taxes, as well as a $1.7 million
reserve for deferred taxes subsequent to a review of the historic balances.
<PAGE>
 
                                       43

     The change in Other Income and Deductions, Other-net in 1998 reflects the
recognition of income due to the reversal of certain deferred credits in
accordance with the Competitive Opportunities Settlement.  In prior years, the
PSC had required the Company to establish deferred credits to account for
certain pension and other post-employment benefit charges and Nine Mile Two
operating and maintenance expenses.  In 1998, these deferred credits totaling
$17.4 million were eliminated consistent with the terms of the Settlement and
discussions with the PSC.  An amount of $8.8 million associated with certain
pension charges was reflected on the Company's books in the first quarter of
1998, after the Company received the written order associated with the
Competitive Opportunities Settlement.  An amount of $6.0 million associated with
certain Nine Mile Two operating and maintenance expenses was reflected ratably
over each of the four quarters of 1998, consistent with Nine Mile Two accounting
practices.  The remainder associated with certain other post-employment benefits
was reflected in the second quarter of 1998, after the Company had concluded
discussions with the PSC.  The Company does not have any deferred credits which
are subject to PSC Orders which would permit the recognition of any significant
credits to income in the future.  This income was partially offset by expenses
associated with the gas interim settlement agreement. Other (Income) and
Deductions, Other--net changed in 1997 due mainly to recognition of expense
associated with management performance awards and the Company's Performance
Stock Option Plan.


     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 1996-1998. Other interest decreased in 1998 due to lower
miscellaneous interest charges on pension and other post-employment benefits.
This decline was partially offset by an additional $1.0 million of interest
expense associated with unregulated operations.   Compared to the prior year,
the average RG&E short-term debt outstanding was up in 1998 and nearly unchanged
in 1997.


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


Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
          MARKET RISK


  The Company is exposed to interest rate and commodity price risks.

  The interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to variable rate debt.
The Company manages its interest rate risk through the issuance of fixed -rate
debt with varying maturities and through economic refundings of debt through
optional redemptions.  A portion of the Company's long-term debt consists of
long-term Promissory Notes, the interest component of which resets on a periodic
basis reflecting current market conditions.  The Company was not participating
in any derivative financial instruments for managing interest rate risks as of
December 31, 1998 or December 31, 1997.
<PAGE>
 
                                       44

  The commodity price risk relates to natural gas in storage and other
petroleum-related products used for resale to customers.  The Company primarily
enters into forward contracts for natural gas through its gas broker.  In
addition, Griffith enters into various exchange-traded futures and option
contracts and over-the-counter contracts with third parties.  The commodity
instruments are designated at the inception as a hedge where there is a direct
relationship to the price risk associated with the Company's inventory or future
purchases and sales of commodities used in the Company's operations.  At
December 31, 1998 and 1997 neither the fair value of the contracts outstanding
nor potential, near-term contract losses from reasonably possible near-term
changes in market prices were material to the financial position, results of
operations or liquidity of the Company.

  For information about the Company's primary market risks associated with
activities in derivative financial instruments, other financial instruments and
derivative commodity instruments, see "Financial/Commodity Instruments" in Note
1 of the Notes to Financial Statements.


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, 1998.

     Consolidated Statement of Retained Earnings for each of the three years
     ended December 31, 1998.

     Consolidated Balance sheet at December 31, 1998 and 1997.

     Consolidated Statement of Cash Flows for each of the three years ended
     December 31, 1998.

     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>
 
                                       45



                       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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally 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/ PricewaterhouseCoopers LLP
    PricewaterhouseCoopers LLP


Rochester, New York
January 20, 1999
<PAGE>
 
                                      46


CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>

(Thousands of Dollars)   Year Ended December 31                            1998             1997*           1996*
--------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>              <C>              <C>  
Operating Revenues                                                  
  Electric                                                                $687,970        $700,329         $707,768
  Gas                                                                      275,177         336,309          346,279
  Other                                                                     71,215               -                -
                                                                      -------------    ------------     ------------
      Total Operating Revenues                                           1,034,362       1,036,638        1,054,047
                                                                      -------------    ------------     ------------
Operating Expenses                                                                                      
  Fuel Expenses                                                                                         
    Fuel for electric generation                                            53,954          47,665           40,938
    Purchased electricity                                                   27,024          28,347           46,484
    Gas purchased for resale                                               155,497         196,579          202,297
    Unregulated fuel expenses                                               60,001               -                -
                                                                      -------------    ------------     ------------
      Total Fuel Expenses                                                  296,476         272,591          289,719
                                                                      -------------    ------------     ------------
Operating Revenues Less Fuel Expenses                                      737,886         764,047          764,328
                                                                                                        
  Other Operating Expenses                                                                              
    Operations and maintenance excluding fuel expenses                     301,625         315,109          313,157
    Unregulated operating and maintenance expenses excluding fuel           13,257               -                -
    Depreciation and amortization                                          116,122         116,522          105,614
    Taxes - local, state and other                                         118,337         121,796          126,868
    Federal income tax                                                      61,385          65,279           69,501
                                                                      -------------    ------------     ------------
      Total Other Operating Expenses                                       610,726         618,706          615,140
                                                                      -------------    ------------     ------------
Operating Income                                                           127,160         145,341          149,188
                                                                                                        
Other (Income) and Deductions                                                                           
  Allowance for other funds used during construction                          (408)           (351)            (684)
  Federal income tax                                                           516          (3,704)          (3,450)
  Other, net                                                               (13,181)          3,308             (712)
                                                                      -------------    ------------     ------------
      Total Other (Income) and Deductions                                  (13,073)           (747)          (4,846)
                                                                                                        
Interest Charges                                                                                        
  Long term debt                                                            42,590          44,615           48,618
  Other, net                                                                 4,158           6,676            9,328
  Allowance for borrowed funds used during construction                       (653)           (563)          (1,423)
                                                                      -------------    ------------     ------------
      Total Interest Charges                                                46,095          50,728           56,523
                                                                      -------------    ------------     ------------
Net Income                                                                  94,138          95,360           97,511
                                                                      -------------    ------------     ------------
Dividends on Preferred Stock                                                 4,842           5,805            7,465
                                                                      -------------    ------------     ------------
Earnings Applicable to Common Stock                                        $89,296         $89,555          $90,046
                                                                      -------------    ------------     ------------

Earnings per Common Share - Basic                                            $2.32           $2.30            $2.32
                                                                                                        
Earnings per Common Share - Diluted                                          $2.31           $2.30            $2.32
                                                                      =============    ============     ============
</TABLE>

CONSOLIDATED STATEMENT OF RETAINED EARNINGS

<TABLE>
<CAPTION> 

(Thousands of Dollars)   Year Ended December 31                            1998             1997            1996
--------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>              <C>              <C>  
Balance at Beginning of Period                                            $109,313         $90,540          $70,330
Add                                                                                         
   Net Income                                                               94,138          95,360           97,511
   Adjustment Associated with Stock Options Exercised                          (72)              -                -
   Adjustment Associated with Stock Redemptions                               (126)           (846)               -
                                                                      -------------    ------------     ------------
       Total                                                               203,253         185,054          167,841
                                                                      -------------    ------------     ------------
Deduct                                                                                      
   Dividends declared on capital stock                                                      
     Cumulative preferred stock - at required rates                          4,842           5,805            7,465
     Common Stock                                                           68,927          69,936           69,836
                                                                      -------------    ------------     ------------
       Total                                                                73,769          75,741           77,301
                                                                      -------------    ------------     ------------

Balance at End of Period                                                  $129,484        $109,313          $90,540
                                                                      =============    ============     ============

Cash Dividends Declared per Common Share                                     $1.80           $1.80            $1.80
                                                                      =============    ============     ============
</TABLE>
The accompanying notes are an integral part of the financial statements.
* Reclassified for comparative purposes.

<PAGE>
 
                                      47


CONSOLIDATED BALANCE SHEET

<TABLE> 
<CAPTION>

(Thousands of Dollars)    At December 31                                1998           1997*
<S>                                                                 <C>            <C>
Assets                                                                             
Utility Plant                                                                      
Electric                                                             $2,477,077     $2,439,108
Gas                                                                     435,318        416,989
Common                                                                  158,038        134,938
Nuclear fuel                                                            256,562        243,042
                                                                    ------------   ------------
                                                                      3,326,995      3,234,077
Less: Accumulated depreciation                                        1,640,645      1,510,074
      Nuclear fuel amortization                                         222,830        204,294
                                                                    ------------   ------------
                                                                      1,463,520      1,519,709
Construction work in progress                                            98,554         74,018
                                                                    ------------   ------------
      Net Utility Plant                                               1,562,074      1,593,727
                                                                    ------------   ------------
                                                                                   
Current Assets                                                                     
Cash and cash equivalents                                                 6,523         25,405
Accounts receivable, net of allowance for doubtful accounts:                       
  1998 - $ 26,554; 1997 - $ 26,926                                       89,291        104,781
Unbilled revenue receivable                                              37,922         48,438
Materials, supplies and fuels                                            43,024         39,929
Prepayments                                                              25,950         23,818
Other current assets                                                        253              -
                                                                    ------------   ------------
      Total Current Assets                                              202,963        242,371
                                                                    ------------   ------------
                                                                                   
Intangible Assets                                                                  
Goodwill                                                                 14,681              -
Other Intangible assets                                                   6,381              -
                                                                    ------------   ------------
      Total Intangible Assets                                            21,062              -
                                                                    ------------   ------------
                                                                                   
Deferred Debits and Other Assets                                                   
Nuclear generating plant decommissioning fund                           183,502        132,540
Nine Mile Two deferred costs                                             29,258         30,309
Unamortized debt expense                                                 17,241         16,943
Other deferred debits                                                    18,531         20,411
Regulatory assets                                                       416,320        231,988
Other assets                                                              1,984              -
                                                                    ------------   ------------
      Total Deferred Debits and Other Assets                            666,836        432,191
                                                                    ------------   ------------
      Total Assets                                                   $2,452,935     $2,268,289
                                                                    ============   ============
                                                                                   
Capitalization and Liabilities                                                     
Capitalization                                                                     
Long term debt - mortgage bonds                                        $510,002       $485,434
               - promissory notes                                       248,224        101,900
Preferred stock redeemable at option of Company                          47,000         47,000
Preferred stock subject to mandatory redemption                          25,000         35,000
Common shareholders' equity:                                                       
  Common stock ($5 par, 38,885,813 shares at
    December 31, 1998 and 38,862,347 shares
    at December 31, 1997)                                               699,730        699,031
  Retained earnings                                                     129,484        109,313
                                                                    ------------   ------------
                                                                        829,214        808,344
  Less:  Treasury stock at cost (1,507,000 shares)                       46,433              -
                                                                    ------------   ------------
      Total Common Shareholders' Equity                                 782,781        808,344
                                                                    ------------   ------------
      Total Capitalization                                            1,613,007      1,477,678
                                                                    ------------   ------------
                                                                                   
Long Term Liabilities                                                              
  Nuclear waste disposal                                                 87,566         83,261
  Uranium enrichment decommissioning                                     12,197         13,465
  Site remediation                                                       24,157         13,626
                                                                    ------------   ------------
      Total Long Term Liabilities                                       123,920        110,352
                                                                    ------------   ------------
                                                                                   
Current Liabilities                                                                
Long term debt due within one year                                          427         30,000
Preferred stock redeemable within one year                               10,000         10,000
Short term debt                                                          57,000         20,000
Accounts payable                                                         52,454         53,195
Dividends payable                                                        17,937         18,791
Equal payment plan                                                       11,025          8,935
Other                                                                    34,526         34,770
                                                                    ------------   ------------
      Total Current Liabilities                                         183,369        175,691
                                                                    ------------   ------------
                                                                                   
Deferred Credits and Other Liabilities                                             
Accumulated deferred income taxes                                       326,972        344,969
Pension costs accrued                                                    58,677         67,361
Kamine deferred costs                                                    65,799              -
Post employment benefits internal reserve                                42,909         32,190
Other                                                                    38,282         60,048
                                                                    ------------   ------------
      Total Deferred Credits and Other Liabilities                      532,639        504,568
                                                                    ------------   ------------
                                                                                   
Commitments and Other Matters                                                      
                                                                    ------------   ------------
      Total Capitalization and Liabilities                           $2,452,935     $2,268,289
                                                                    ============   ============
</TABLE>
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.

<PAGE>
 
                                      48


CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>

(Thousands of Dollars)        Year Ended December 31                  1998            1997*           1996*
<S>                                                               <C>             <C>             <C>
CASH FLOW FROM OPERATIONS                                                                        
Net income                                                        $    94,138     $    95,360     $    97,511
Adjustments to reconcile net income to net cash provided                                         
  from operating activities:                                                                     
Depreciation and amortization                                         134,259         133,942         121,824
Deferred fuel                                                          (3,565)            489          (6,501)
Deferred income taxes                                                  (9,141)        (10,064)          6,391
Allowance for funds used during construction                           (1,061)           (914)         (2,107)
Unbilled revenue, net                                                  10,516           4,823          10,908
Stock option plan, net                                                     99           2,399               -
Nuclear generating plant decommissioning fund                         (20,827)        (20,331)        (11,732)
Payment to Kamine                                                     (17,790)              -               -
Pension costs accrued                                                 (15,818)         (3,398)         (2,494)
Post employment benefit internal reserve                               10,719           6,189           6,626
Provision for doubtful accounts                                          (372)          5,078           4,987
Changes in certain current assets and liabilities:                                               
  Accounts receivable                                                  27,549           3,049           3,228
  Materials, supplies and fuels                                           141             (41)         (1,238)
  Taxes accrued                                                        (1,448)            347         (13,944)
  Payroll  accrued                                                         54             433              17
  Accounts payable                                                     (7,031)          3,733          (3,116)
  Other current assets and liabilities, net                              (817)          6,911          (5,203)
Other, net                                                             (4,699)          6,847          (3,931)
                                                                 -------------   -------------   -------------
       Total Operating                                                194,906         234,852         201,226
                                                                 =============   =============   =============
                                                                                                 
CASH FLOW FROM INVESTING ACTIVITIES                                                              
Net additions to utility plant                                       (129,286)        (84,068)       (114,274)
Acquisition, net of cash                                              (30,977)              -               -
Other, net                                                                484              (1)          9,204
                                                                 -------------   -------------   -------------
       Total Investing                                               (159,779)        (84,069)       (105,070)
                                                                 =============   =============   =============
                                                                                                 
CASH FLOW FROM FINANCING ACTIVITIES                                                              
Proceeds from:                                                                                   
  Sale/Issuance of common stock                                           586             272           8,612
  Issuance of long term debt                                           99,422         101,900               -
  Short term borrowings, net                                           30,500           6,000          14,000
Retirement of long term debt                                          (55,500)       (151,568)        (67,332)
Retirement of preferred stock                                         (10,000)        (30,000)              -
Dividends paid on preferred stock                                      (5,031)         (6,366)         (7,465)
Dividends paid on common stock                                        (69,592)        (69,933)        (69,657)
Payment for treasury stock                                            (46,433)              -               -
Equal payment plan                                                      2,090           3,385           4,273
Other, net                                                                (51)           (369)         (1,407)
                                                                 -------------   -------------   -------------
       Total Financing                                                (54,009)       (146,679)       (118,976)
                                                                 -------------   -------------   -------------
       Increase (Decrease) in cash and cash equivalents           $   (18,882)    $     4,104     $   (22,820)
       Cash and cash equivalents at beginning of year             $    25,405     $    21,301     $    44,121
                                                                 -------------   -------------   -------------
       Cash and cash equivalents at end of year                   $     6,523     $    25,405     $    21,301
                                                                 =============   =============   =============
</TABLE>


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

<TABLE>
<CAPTION>

(Thousands of Dollars)        Year Ended December 31                  1998            1997            1996
<S>                                                               <C>             <C>             <C>
Cash Paid During the Year
Interest paid (net of capitalized amount)                         $    43,793     $    50,681     $    55,545
Income taxes paid                                                 $    75,600     $    70,500     $    76,890
                                                                 =============   =============   =============
</TABLE>
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.

<PAGE>
 
                                       49


NOTES TO FINANCIAL STATEMENTS

Note 1.  SUMMARY OF ACCOUNTING PRINCIPLES


     GENERAL.  The Company supplies regulated electric and gas services wholly
within the State of New York.  The unregulated portion of the Company provides
products and services as discussed in Note 4.  The Company is subject to
regulation by the Public Service Commission of the State of New York (PSC) under
New York statutes and by 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 Energetix and
Energyline.  All intercompany balances and transactions have been eliminated.
Energetix financial statements are consolidated with its wholly-owned subsidiary
Griffith.

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

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

     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.

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

     ACQUISITIONS.  In August 1998, Energetix announced the acquisition of
Griffith Oil, Co., Inc. ("Griffith"), for $31.5 million.  Griffith sells oil,
propane, electricity, gasoline, natural gas and other services offered by
Energetix to its existing customers.  The acquisition was accounted for as a
purchase resulting in goodwill as reflected on the consolidated financial
statements.  The principal assets acquired were vehicles, tanks, pumps,
buildings and commodity inventory.

     RATES AND REVENUE.  Revenue is recorded on the basis of meters read.  In
addition, the Company records an estimate of unbilled revenue for service
<PAGE>
 
                                       50

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.

     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 Allowance for Other Funds Used During Construction, a part of Other
Income.  The rate approved by the PSC for purposes of computing AFUDC was 5.0%
during the three-year period ended December 31, 1998.  Replacement of minor
items of property is included in maintenance expenses.  Costs of depreciable
units of plant retired are eliminated from utility plant accounts, and such
costs, plus removal expenses, less salvage, are charged to the accumulated
depreciation reserve.

     Depreciation in the financial statements is provided on a straight-line
basis at rates based on the estimated useful lives of property, which have
resulted in an annual regulated depreciation provision of 3.2% in the three-year
period ended December 31, 1998.  The annual depreciation provision of Energetix
is 8.0% for 1998.

     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.  The Company has no other debt or equity securities.

     FINANCIAL/COMMODITY INSTRUMENTS.  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.  The Company primarily enters
into forward contracts for natural gas through its gas broker.

     Griffith is in the business of purchasing various petroleum-related
commodities for resale to its customers. In order to manage the risk associated
with market price fluctuations Griffith enters into various exchange-traded
futures and option contracts and over-the-counter contracts with third parties.
The commodity instruments are designated at the inception as a hedge where there
is a direct relationship to the price risk associated with the company's
inventory or future purchases and sales of commodities used in the company's
<PAGE>
 
                                       51

operation.  These contracts are closely monitored on a daily basis to manage the
price risk associated with the company's inventory and future product
commitments.  All hedge contracts are accounted for under the deferral method
with gains and losses from the hedging activity included in the cost of sales as
inventories are sold or as the hedge transaction occurs.  Commodity instruments
not designated as effective hedges are marked to market at the end of the
reporting period, with the resulting gains or losses recognized in cost of
sales.  As of December 31, 1998 the Company had net deferred gains on open hedge
contracts of $0.7 million.

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

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

     STOCK-BASED COMPENSATION.  Financial Accounting Standards Board Statement
No. 123 (SFAS-123), Accounting for Stock-Based Compensation, was adopted by the
Company in the first quarter of 1996.  It recommends the use of a fair value
based method of accounting for compensation costs associated with stock-based
compensation.  The Company currently has Stock Appreciation Rights plans
covering certain employees and directors.  For these plans, the Company's
accounting policy has been to use a fair value method of computing periodic
compensation expense.  SFAS-123 was applied to the valuation of the 1996
Performance Stock Option Plan (PSOP), which became effective on January 22,
1997.  The aggregate amount charged to expense as a result of these plans for
the years 1998, 1997 and 1996 approximates $5.9 million, $8.2 million and $1.0
million respectively.  Additional information on the PSOP is included in Note 8.

     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 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.
<PAGE>
 
                                       52


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


                              1998            1997
                              ----            ----

(thousands of dollars except per share amounts)

Basic EPS:
----------


Net Income                    $94,138         $95,360

Less:
Preferred Stock Dividends      (4,842)         (5,805)
                               -------         -------
 
 
Income available to
     Common Shareholders       89,296          89,555
 
Shares                         38,462          38,853
 
Per-Share Amount              $  2.32         $  2.30
                              =======         =======
 

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

Effect of Dilutive Securities
  Stock Option Plan               138              56
                               ------           -----

Income available to
  Common Shareholders plus
  assumed conversions         $89,296         $89,555

Shares                         38,600          38,909
                              -------         -------


Per-Share Amount                $2.31           $2.30
                                =====           =====

There were no dilutive shares in 1996.


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

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

     RECLASSIFICATIONS.  Certain amounts in the prior years' financial
statements were reclassified to conform with current year presentation.
<PAGE>
 
                                       53

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.


                                                     (Thousands of Dollars)
  
                                              1998       1997       1996
 
Charged (Credited) to operating expense:
 
  Current                                    $70,541    $69,812    $65,757
  Deferred                                    (9,156)    (4,533)     3,744
                                             -------    -------    -------
     Total                                    61,385     65,279     69,501
 
Charged (Credited) to other income:
  Current                                     (1,614)     1,828     (6,097)
  Deferred                                     4,562     (3,100)     5,079
  Deferred investment tax credit              (2,432)    (2,432)    (2,432)
                                             -------    -------    -------
      Total                                      516     (3,704)    (3,450)
 
Total federal income tax expense             $61,901    $61,575    $66,051



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%.



                                                        (Thousands of Dollars)

                                                   1998       1997       1996

Net Income                                      $ 94,138   $ 95,360   $ 97,511
Add:  federal income tax expense                  61,901     61,575     66,051
                                                --------   --------   --------
 
Income before federal income tax                $156,039   $156,935   $163,562
 
Computed tax expense at statutory tax rate      $ 54,614   $ 54,927   $ 57,247
Increases (decreases) in tax resulting from:
  Difference between tax depreciation
  and amount deferred                              9,366     10,772     10,796
  Deferred investment tax credit                  (2,432)    (2,432)    (2,432)
  Miscellaneous items, net                           353     (1,692)       440
 
Total federal income tax expense                $ 61,901   $ 61,575   $ 66,051



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



                                                       (Thousands of Dollars)

                                             1998       1997      1996

Nuclear decommissioning                   $(24,849)  $(20,807)  $(17,880)
Accelerated depreciation                   214,521    216,704    213,907
Deferred investment tax credit              25,768     27,981     29,562
Depreciation previously flowed through     146,953    157,538    169,562
Pension                                    (20,161)   (23,166)   (24,570)
Other                                      (15,260)   (13,281)      (553)
                                          --------   --------   --------
Total                                     $326,972   $344,969   $370,028
<PAGE>
 
                                       54


     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, 1998 and
1997 was $148 million and $160 million, respectively.  In conjunction with the
recognition of this liability, a corresponding regulatory asset was also
recognized.



Note 3: Pension and Other Postretirement Benefit Plans


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

<TABLE>
<CAPTION>
                                                               (Millions)
                                                   Pension Benefits    Other Benefits
                                                    1998      1997     1998     1997
                                                  --------  --------  -------  -------
<S>                                               <C>       <C>       <C>      <C>
Change in benefit obligation
Benefit obligation at beginning of year           $ 499.3   $ 480.2   $ 89.0   $ 79.1
Service cost                                          7.0       6.2      1.1      0.9
Interest cost                                        32.9      33.1      6.0      5.8
Plan Amendments                                       0.0       0.0      4.3      0.0
Actuarial loss                                       10.6      13.1      2.7      7.2
Benefits paid                                       (33.0)    (33.3)    (4.1)    (4.0)
                                                  -------   -------   ------   ------
Benefit obligation at end of year                 $ 516.8   $ 499.3   $ 99.0   $ 89.0
 
Change in plan assets
---------------------
Fair value of plan assets at beginning of year    $ 638.4   $ 567.1   $  0.0   $  0.0
Actual return on plan assets                        100.0     104.0      0.0      0.0
Company contribution                                  0.9       0.5      4.1      4.0
Benefits paid                                       (32.9)    (33.2)    (4.1)    (4.0)
                                                  -------   -------   ------   ------
Fair value of plan assets at end of year          $ 706.4   $ 638.4   $  0.0   $  0.0
                                                  =======   =======   ======   ======
 
Funded status                                     $ 189.5   $ 139.1   $(99.0)  $(89.0)
Unrecognized actuarial loss                        (259.4)   (219.0)    11.2      8.4
Unrecognized prior service cost                       9.9      10.7     12.6      8.9
Unrecognized net transition obligation (asset)        1.3       1.8     32.3     39.5
                                                  -------   -------   ------   ------
Accrued benefit cost                              $ (58.7)  $ (67.4)  $(42.9)  $(32.2)
                                                  =======   =======   ======   ======

Weighted-average assumptions as of
December 31
-----------

Discount rate                                        6.50%     6.75%    6.50%    6.75%
Expected return on plan assets                       8.50%     8.50%
Rate of compensation increase                        5.00%     5.00%
</TABLE>

<TABLE> 
<CAPTION>
                                                                                               (Millions)
                                                                               Pension Benefits          Other Benefits
                                                                            1998     1997     1996     1998   1997   1996
                                                                            ----     ----     ----     ----   ----   ----
<S>                                                                         <C>      <C>      <C>      <C>    <C>    <C>
Components of net periodic benefit cost
---------------------------------------
Service cost                                                                $  7.0   $  6.2   $  7.4   $ 1.1  $ 0.9  $ 1.0
Interest cost                                                                 32.9     33.1     33.4     6.0    5.8    5.4
Expected return on plan assets                                               (44.8)   (39.6)   (37.2)    0.0    0.0    0.0
Unrecognized transition obligation                                             0.5      0.5      0.5     2.8    2.9    2.8
Amortization of prior service                                                  0.9      0.9      0.9     0.6    0.6    0.5
Recognized actuarial loss                                                     (4.3)    (3.1)    (6.0)    0.0    0.0    0.9
                                                                            ------   ------   ------   -----  -----  -----
Net periodic (benefit) cost                                                 $ (7.8)  $ (2.0)  $ (1.0)  $10.5  $10.2  $10.6
                                                                            ======   ======   ======   =====  =====  =====
</TABLE>
<PAGE>
 
                                       55

  In addition to providing pension benefits, the Company provides certain health
care and life insurance benefits on a defined dollar basis.  In 1998, the health
care benefit consists of a contribution of up to $210 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.  Effective January 1999, the Company amended the health care plan
increasing the contribution to up $220 per retiree per month.


In addition to the above plans, employees are eligible to contribute to a 401(k)
plan.  The Company matches a portion of these contributions.  Contributions
charged to income for this plan for 1998, 1997, and 1996 were $2.5 million, $2.3
million, and $2.3 million, respectively.


Note 4.  OPERATING SEGMENT FINANCIAL INFORMATION


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

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

     The Regulated Electric segment supplies electric distribution services
wholly within New York State.  It produces electricity, and distributes and
sells electricity to retail customers within a franchise area centering about
the City of Rochester.  It also sells electricity on a wholesale basis to other
electric utilities throughout the Northeast and to energy marketers who resell
that electricity to retail customers.

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

     The Unregulated segment includes Energetix and RGS Development Corporation,
both unregulated subsidiaries of the Company formed in 1998.  In August, 1998,
Energetix acquired Griffith Oil Inc., the second largest propane and oil
distribution company in New York State.  Energetix brings energy products and
services to the marketplace both within and outside of the Company's regulated
franchise area.  These energy products and services include appliance warranty
and repair, electricity, gasoline, natural gas, oil, and propane.  RGS
Development Corporation was formed to pursue unregulated business opportunities
in the energy marketplace.
<PAGE>
 
                                       56

<TABLE>
<CAPTION>
                                              (thousands of dollars)
 
Regulated Electric                             1998         1997         1996
                                               ----         ----         ---- 
<S>                                        <C>          <C>          <C>
 
Profit                                      $   93,762   $   82,765   $   83,528
Revenues from External Customers            $  687,100   $  700,329   $  707,768
Revenues from Intersegment Transactions     $    8,984   $        -   $        -
Interest Revenue                            $    1,694   $    3,379   $    1,455
Depreciation and Amortization               $  102,123   $  103,395   $   92,615
Regulatory Amortization                     $   15,080   $   23,409   $   23,743
Nuclear Fuel Amortization                   $   18,138   $   17,419   $   16,209
Interest Expense                            $   36,122   $   40,583   $   45,218
Income Tax Expense                          $   62,900   $   58,682   $   58,950
 
Capital Expenditures, net                   $   96,206   $   58,522   $   95,334
 
Total Identifiable Assets                   $1,941,622   $1,783,825   $1,877,224
 
<CAPTION> 
Regulated Gas                                  1998         1997         1996   
                                               ----         ----         ----  
<S>                                        <C>          <C>          <C>

Profit                                      $    3,610   $   12,595   $   13,983
Revenues from External Customers            $  274,540   $  336,309   $  346,279
Revenues from Intersegment Transactions     $       72   $        -   $        -
Interest Revenue                            $      424   $      845   $      364
Depreciation and Amortization               $   12,867   $   13,127   $   12,999
Regulatory Amortization                     $    1,461   $    1,337   $    1,677
Interest Expense                            $    9,030   $   10,145   $   11,305
Income Tax Expense                          $      504   $    2,893   $    7,101
 
Capital Expenditures, net                   $   28,075   $   25,546   $   18,940
 
Total Identifiable Assets                   $  433,029   $  441,849   $  447,865
 
<CAPTION> 
Unregulated                                    1998         1997         1996  
                                               ----         ----         ----  
<S>                                        <C>          <C>          <C>

(Loss)                                      $   (3,234)  $        -   $        -
Revenues from External Customers            $   81,778   $        -   $        -
Interest Revenue                            $      158   $        -   $        -
Depreciation and Amortization               $      854   $        -   $        -
Goodwill Amortization                       $      278   $        -   $        -
Interest Expense                            $      943   $        -   $        -
Income Tax Benefit                          $   (1,503)  $        -   $        -
                                                                                
Capital Expenditures, net                   $    5,005   $        -   $        -
                                                                                
Total Assets                                $   59,946   $        -   $        -
 
</TABLE>


          There are intersegment transactions which occur between the Regulated
segments and the Unregulated segment.  These transactions are governed by
guidelines established in the Competitive Opportunities Settlement and other PSC
proceedings.  The Unregulated segment is charged for the provision of services
and for an allocation of other corporate costs by the Regulated Segments on a
fully loaded cost basis.  The Unregulated segment buys electricity from the
Regulated Electric segment at rates established through PSC proceedings.  The
Unregulated segment also pays the Regulated segments for electric and gas
distribution services at rates established through PSC proceedings.  The total
amount of the revenues identified by operating segment do not equal the total
<PAGE>
 
                                       57

Company consolidated amounts as shown in the Consolidated Statement of Income.
This is due to the elimination of certain intersegment revenues during
consolidation.  The total assets identified by operating segment do not equal
the total Company consolidated amounts as shown in the Consolidated Balance
Sheet.  This is due to the elimination of certain intersegment transactions
during consolidation, and certain common assets unidentifiable by segment.  A
reconciliation follows:

<TABLE>
<CAPTION>
Revenues                                        1998         1997         1996
                                                ----         ----         ----    
<S>                                          <C>          <C>          <C>
 
Regulated Electric                            $  687,100   $  700,329   $  707,768
Regulated Gas                                    274,540      336,309      346,279
Unregulated                                       81,778            -            -
                                              ----------   ----------   ----------
 
   Total                                      $1,043,418   $1,036,638   $1,054,047
 
Reported on Consolidated Income Statement      1,034,362    1,036,638    1,054,047
                                              ----------   ----------   ----------
 
Difference to reconcile                       $    9,056   $        -   $        -
 
Intersegment Revenues
 Regulated Electric from Unregulated          $    8,984   $        -   $        -
 Regulated Gas from Unregulated                       72            -            -
                                              ----------   ----------   ----------
 
 Total Intersegment                           $    9,056   $        -   $        -

Assets

Regulated Electric                            $1,941,622   $1,783,825   $1,877,224
Regulated Gas                                    433,029      441,849      447,865
Unregulated                                       59,946            -            -
                                                         
Cash and Cash Equivalents,                               
                                                         
   Regulated Operations                            5,375       25,405       21,301
Unamortized Debt Expense                          17,241       16,944       14,820
Investment in Subsidiaries                        11,202            -            -
Other                                                266          266          266
Intersegment eliminations                        (15,746)           -            -
                                              ----------   ----------   ----------
                                            
Total Assets                                  $2,452,935   $2,268,289   $2,361,476
</TABLE>

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.
<PAGE>
 
                                       58

<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

<CAPTION> 
                                            (Millions of Dollars)

                                            at December 31, 1998
                                          --------------------------
<S>                                       <C>             <C>
Plant In Service Balance                  $ 99.6              $881.8
Accumulated Provision For Depreciation    $ 43.6              $490.9
Plant Under Construction                  $  0.0              $  0.7
</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.


Note 6.   LONG-TERM DEBT

FIRST MORTGAGE BONDS

<TABLE>
<CAPTION>
                                                  (Thousands of  Dollars)
                                                      Principal Amount
                                                         December 31
 
  %                  Series        Due                1998           1997
-----                ------        ---            --------       --------
<S>                  <C>           <C>            <C>            <C>
                                                           
6.7                  X             July  1, 1998  $      -       $ 30,000
8 3/8                OO/(a)/       Dec.  1, 2028         -         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
5.84                 /(b)/(d)/     Dec. 22, 2008    50,000              -
                                                  --------       --------
                                                  $510,500       $516,000
                                                           
Net bond discount                                     (498)          (566)
Less:  Due within one year                               -         30,000
                                                  --------       --------
Total                                             $510,002       $485,434
                                                  ========       ========
</TABLE>
<PAGE>
 
                                       59

(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%, 6.375% and
    5.84% medium-term notes described below are generally not redeemable prior
    to maturity.

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

(d) In 1998 the Company issued $50 million under a medium-term note program
    entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series
    B" with maturities that range from 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 December 1, 1998 the Company redeemed all its outstanding First Mortgage
8 3/8% Bonds, due December 1, 2028, Series OO.

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


<TABLE>
<CAPTION>
                                              (Thousands of Dollars)

                            1999     2000     2001     2002     2003
                          -------  -------  -------  -------  -------
<S>                       <C>      <C>      <C>      <C>      <C> 
     7% Series                     $30,000
     Series QQ                                       $100,000
     7.15% Series                                             $ 39,000
     7.13% Series                                             $  1,000
     6.375% Series                                            $ 40,000
                          ----     -------  ----     -------- --------
                          $  -     $30,000  $  -     $100,000 $ 80,000
</TABLE>
<PAGE>
 
                                       60

PROMISSORY NOTES AND OTHER



<TABLE>
<CAPTION>
                                                            (Thousands of Dollars)
                                                                  December 31
 
Issued                                     Due                1998      1997
------                                     ---                ----      ----
<S>                                        <C>                <C>       <C>
September 2, 1998(/e/)                     September 1, 2033  $ 25,500  $      -
August 19, 1997(/f/)                       August 1, 2032      101,900   101,900
August  3, 1998(/g/)                       August 3, 2005       24,563         -
December 1, 1998(/h/)                      March 31, 2014       94,761         -
Other Long Term Debt of Subsidiaries(/i/)                        1,500         -
                                                              --------  --------
Total                                                         $248,224  $101,900
                                                              ========  ========
</TABLE>

(e)  The $25.5 million Promissory Note was issued in connection with NYSERDA's
     5.95% Pollution Control Revenue Bonds (Rochester Gas and Electric
     Corporation Project), 1998 Series A. Payment of the principal of, and
     interest on the Series A Bonds is guaranteed under a Bond Insurance Policy
     by MBIA Insurance Corporation.

(f)  Multi-mode pollution control notes totaling the principal amount of $101.9
     million were issued in connection with NYSERDA's Pollution Control Revenue
     Bonds (Rochester Gas and Electric Corporation Project), $34,000,000 1997
     Series A, $34,000,000 1997 Series B and $33,900,000 1997 Series C.  The
     Multi-mode Revenue Bonds have a structure that enables the Company to
     optimize the use of short-term 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, 1998 and December
     31, 1997, the Multi-mode Revenue Bonds bore interest at the weekly rate and
     the average annual interest rate for all three series was 3.21% and 3.65%,
     respectively.


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


(g)  The $24.6 million Promissory Note was issued in connection with the
     acquisition of Griffith Oil, Inc. by Energetix and is secured by a pledge
     of the stock of Griffith Oil, Inc.   The Company has made a financial
     guarantee on behalf of Energetix which obligates the Company in the event
     of a default by Energetix in payments under the Note.  Payments of
     principal are made in seven annual installments and interest for the first
     three years accrues at the rate of 7% per year and thereafter at rates
     varying between 7%-8 1/2% per year.



(h)  The Promissory Note was issued in connection with the Kamine Global
     Settlement Agreement (See Note 10.)  The Promissory Note is secured by a
     mortgage, the lien for which is subordinate to the lien of the First
     Mortgage.  The $94.8 million liability represents the present value at
     December 31, 1998 of future obligations under the Note assuming a discount
     rate of 7.5 percent.  This balance will decrease as payments are made over
     the term of the Note.  During 1998 the Company made payments totaling $7.8
     million.  In 1999 the Company expects to make payments totaling $9.6
     million and thereafter, payments totaling $10.6 million per year.
<PAGE>
 
                                       61

(i)  Represents mainly promissory notes under various distribution seller
     agreements of Energetix aggregating $1,927 less $427 due within one year.

     Based on an estimated borrowing rate at year-end 1998 of 5.84% for long-
term debt with similar terms and average maturities (12 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $844 million at December 31, 1998.

     Based on an estimated borrowing rate at year-end 1997 of 6.62% for long-
term debt with similar terms and average 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.



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      820,000*
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, 1998        1998    1997       (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
                           -------      -------  -------
 
Total                      470,000      $47,000  $47,000
                           =======      =======  =======
</TABLE>

# May be redeemed at any time at the option of the Company on 30 days minimum
  notice, plus accrued dividends in all cases.
<PAGE>
 
                                       62

B.   PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:

<TABLE>
<CAPTION>
 
                      Shares              (Thousands)          Optional
                    Outstanding           December 31,        Redemption
 %       Series  December 31, 1998        1998    1997        (per share) 
-----    ------  -----------------      -------  -------     -------------
<S>      <C>     <C>                    <C>      <C>         <C>
 
7.55          T                  -      $     -  $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                      350,000      $35,000  $45,000      
                                                          
Less: Due within one year  100,000       10,000   10,000      
                           -------      -------  -------      
                                                          
Total                      250,000      $25,000  $35,000      
                           =======      =======  =======      
</TABLE>

+ Thereafter at $100.00


MANDATORY REDEMPTION PROVISIONS

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

     Series U.  All of the shares are subject to redemption pursuant to
mandatory sinking funds on September 1, 1999 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 1998 of 4.75% for Preferred
Stock, subject to mandatory redemption, with similar terms and average
maturities (6.61 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $39 million at December 31,
1998.

     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.
<PAGE>
 
                                       63

Note 8.  COMMON STOCK AND STOCK OPTIONS


REPURCHASE PLAN


     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. A total of 1,507,000 of the shares were purchased in 1998.

<TABLE> 
<CAPTION> 
                                                      Shares      Amount
                                                   Outstanding  (Thousands)
                                                   -----------  -----------
<S>                                                <C>          <C> 
Balance, December 31, 1997                                   0           $0
  Reacquired through Repurchase Plan                (1,507,000)     (46,433)
                                                   -----------     --------
 
Balance, December 31, 1998                          (1,507,000)    $(46,433)
</TABLE> 


COMMON STOCK

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

<TABLE> 
<CAPTION> 
                                                        Shares       Amount
                                                   Outstanding  (Thousands)
                                                   -----------  -----------
<S>                                                <C>          <C> 

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
  Shares Issued through Stock Plans                     23,466          586
  Additional Paid in Capital                                             99
  Repurchase Plan                                   (1,507,000)     (46,433)
  Decrease (Increase) in Capital
     Stock Expense                                                       14
                                                    ----------     --------
 
Balance, December 31, 1998                          37,378,813     $653,297
</TABLE> 
<PAGE>
 
                                       64

PERFORMANCE STOCK OPTION PLAN

     The Company has a Performance Stock Option Plan which provides for the
granting of options to purchase up to 2,000,000 authorized but unissued shares
or treasury shares of $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 of the
Board of Directors (the Committee).  The Committee grants 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 1998, the Board of Directors granted 27,984 options at an exercise price
of $33.9065 per share and 15,157 options at an exercise price of $31.0005 per
share.  These options are vested at 25% when the stock closes at $35 per share,
50% at $40 per share, 75% at $45 per share and 100% at $50 per share.  These
options are exercisable for a period of 10 years.  The weighted average grant
date option fair value is $5.56.  The weighted average contractual remaining
life at December 31, 1998 is 9.10 years.

     In 1997, the Board of Directors granted 504,700 options at an exercise
price of $19.0625 per share.  These options are vested at 50% when the stock
closes at $25 per share, 75% at $30 per share and 100% at $35 per share.  Also
in 1997, the Board of Directors granted 50,159 options at an exercise price of
$24.75 per share.  These options are vested at 25% when the stock closes at $25
per share, 50% at $30 per share, 75% at $35 per share and 100% at $40 per share.
These options are exercisable for a period of 10 years.  The weighted average
grant date option fair value is $4.60.  The weighted average contractual
remaining life at December 31, 1998 is 8.13 years.

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

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

  A summary of the Company's stock option activity is presented below:
<PAGE>
 
                                       65

<TABLE>
<CAPTION>
                                                         Weighted
                                                         Average
                                           Options    Exercise 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
 
Options granted 1998                         43,141          $32.886
Options exercised                           (23,466)         $19.063
                                          ---------
Outstanding at 12/31/98                     563,651          $20.627
Vested at 12/31/98                          369,255          $19.449
Available for future grant at 12/31/98    1,402,000
</TABLE>


Note 9.  SHORT-TERM DEBT

     On December 31, 1998, the Company and its subsidiary, Energetix had short-
term debt outstanding of $50.5 million and $6.5 million, respectively.  At
December 31, 1997 the Company had short-term debt outstanding of $20.0 million.
At no time during 1997 did Energetix have any short-term debt outstanding. The
weighted average interest rates on short-term debt outstanding at year-end 1998
for the Company and Energetix were 5.81% and 6.66%, respectively.  The weighted
average interest rates for borrowings during the year were 5.51% and 6.31%,
respectively.  The weighted average interest rate on short-term debt borrowed
during 1997 for the Company was 6.07%.

     The Company's $90 million revolving credit agreement currently terminates
on December 31, 2001.  Commitment fees related to this facility amounted to
$97,705 in 1998 and $113,000 in 1997 and 1996.  At the time of acquisition of
Griffith Oil Co., Inc. by Energetix, Griffith secured a $15 million revolving
credit agreement.  Borrowings under this agreement are secured by personal
property of Griffith.  Energetix has made a financial guarantee on behalf of
Griffith which obligates Energetix in the event of a Griffith default.

     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, 1998, the Company would be
able to incur approximately $93.8 million of additional unsecured debt under
this provision.  The Company has unsecured lines of credit totaling $47 million
available from several banks, at their discretion.

     In order to be able to use its $90 million revolving credit agreement, the
Company has created a subordinate mortgage which secures borrowings under its
revolving credit agreement that might 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 $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.
<PAGE>
 
                                       66



Note 10.  COMMITMENTS AND OTHER MATTERS



REGULATORY 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
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, 1998
and 1997:




                                                      Millions of Dollars

                                                        1998         1997
                                                        ----         ----
       Income Taxes                                   $147.6       $159.6 
       Kamine                                          192.8            -
       Uranium Enrichment Decommissioning Deferral      15.1         16.4
       Deferred Ice Storm Charges                        8.9         11.5
       Deferred Environmental SIR costs                 20.9         12.4
       Labor Day 1998 Storm Costs                        7.2            -
       Gas Deferred Fuel                                10.7          7.1
       Other, net                                       13.1         25.0
                                                      ------       ------ 
 
       Total - Regulatory Assets                      $416.3       $232.0
                                                      ======       ======



-    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,
     which varies from one to thirty years, when the effect of the past
     deductions reverses in future years.

-    Kamine:  This amount results from a settlement resolving all litigation,
     releasing all claims and terminating all electricity purchase obligations
     under a power purchase agreement.

-    Uranium Enrichment Decommissioning Deferral:  The Energy Policy Act of 1992
     requires utilities to contribute such amounts based on the amount of
     uranium enriched by the United States Department of Energy (DOE) for each
<PAGE>
 
                                       67

     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.

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

-    Labor Day 1998 Storm Costs: These costs result from a 1998 Labor Day storm.
     Under the Competitive Opportunities Settlement, the Company is entitled to
     defer, for later recovery in rates, certain costs, including those caused
     by "catastrophic events", when any single event results in costs exceeding
     $2.5 million. The Company has filed a petition with the PSC notifying them
     of the deferral of these storm costs.

-    Gas Deferred Fuel:  These costs result from a PSC-approved annual
     reconciliation of recoverable gas costs with gas revenues in which the
     excess or deficiency is refunded to or recovered from 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 or high cost generating assets.  Estimates of
strandable assets are highly sensitive to the competitive wholesale market price
assumed in the estimation.  The amount of potentially strandable assets at
December 31, 1998 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 Cost Recovery"
below, may affect this exposure; but whether and to what extent there may be an
impact on the level and recoverability of strandable assets cannot be determined
at this time.

     At December 31, 1998 the Company believes that its regulatory and
strandable assets, if any, are not impaired and are probable of recovery.  The
settlement approved in the Competitive Opportunities proceeding (Competitive
Opportunities Settlement) does not impair the opportunity of the Company to
recover its investment in these assets.  However, the PSC issued an Opinion and
Order Instituting Further Inquiry on March 20, 1998 to address issues
surrounding nuclear generation. The ultimate  determination in this proceeding
could have an impact on strandable assets and the recovery of nuclear costs.
The initial meeting in this Inquiry was held in January 1999 and such a
determination is unlikely before year-end.
<PAGE>
 
                                       68

CAPITAL EXPENDITURES


     The Company's 1999 construction expenditures program is currently estimated
at $114 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 $138.3 million through December 31, 1998
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 $107.3 million to this fund and, including realized and unrealized
investment returns, the fund has a balance of $183.5 million as of December 31,
1998.  The amount attributed to the allowance for removal of non-contaminated
structures is being held in an internal reserve.  The internal reserve balance
as of December 31, 1998 is $31.0 million.

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

     The PSC in August 1997 issued for comment a report by its staff proposing
norms by which nuclear plants in the state would relate to the competitive
electricity market following the period covered by electric utility
restructuring agreements then pending before the PSC.  Among other things, the
report envisioned the sale of these plants at auction, but with the selling
utilities remaining responsible for ultimate decommissioning as well as for
disposal of certain spent fuel.  Recognizing that bidders may not be attracted
to certain units -- which could include both the Company's Ginna plant and the
Nine Mile Two plant in which it has a 14% interest, the report contemplated
their early shutdown unless they could compete with other forms of generation.
In Fall 1997, the Company and others commented on these and other facets of the
report.  On March 20, 1998 the PSC issued an Opinion and Order Instituting
Further Inquiry.  In December 1998 the PSC issued a Notice of Collaborative
Conference to further
<PAGE>
 
                                       69

examine the future treatment of nuclear generation.  The
initial collaborative conference in this proceeding will be held in January,
1999.

     The Staff of the Financial Accounting Standards Board is studying the
recognition, measurement and classification of certain liabilities related to
the closure or removal of long lived assets.  This could affect the accounting
for the decommissioning costs of the Company's nuclear generating stations.  If
current accounting practices for such costs were changed, the annual provisions
for decommissioning costs could increase, the estimated cost for decommissioning
could be reclassified as a liability rather than as accumulated depreciation,
the liability accounts and corresponding plant asset 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.  On June 12,
1998, 16 electric utilities from across the country, including the Company,
filed a multi-count complaint against the United States government in the United
States District Court for the Southern District of New York. The suit challenges
the constitutionality of a $2.25 billion retroactive assessment imposed by the
federal government on domestic nuclear power companies to pay for the clean up
of the federal government's three uranium enrichment plants.  Those plants are
located at Oak Ridge, Tennessee, Paducah, Kentucky, and Portsmouth, Ohio.  The
Oak Ridge plant went into operation in 1945, and the other two plants began
operation during the 1950s.

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

  The assessments for Ginna and the Company's share of Nine Mile Two are
estimated to total $22.1 million, excluding inflation and interest. Installments
aggregating approximately $11.2 million have been paid through 1998.  A
liability has been recognized on the financial statements along with a
corresponding regulatory asset.  For the two facilities the Company's liability
at December 31, 1998 is $13.9 million ($12.2 million as a long-term liability
and $1.7 million as a current liability). The Company is recovering costs
through base rates of fuel.

     NUCLEAR FUEL DISPOSAL COSTS.  The Nuclear Waste Policy Act (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.  In
December 1996 the DOE notified the Company that the DOE will not start
acceptance of Ginna spent fuel in 1998.  The Nuclear Waste Act provides for a
determination of the fees collectible by the DOE for the disposal of nuclear
fuel irradiated prior to April 7, 1983 and for three payment options.  The
option of a single payment to be made at any time prior to the first delivery of
fuel to the DOE was selected by the Company in June 1985.  The Company estimates
the fees, including accrued interest, owed to the DOE to be $87.6 million at
December 31, 1998.  The
<PAGE>
 
                                       70

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 $4.7 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.  In November 1998 the Company completed
installation of seven high-capacity spent fuel racks in the spent fuel pool.
This will allow interim storage capacity of all spent fuel discharged from the
Ginna Plant through the end of its Operating License in the year 2009.



ENVIRONMENTAL MATTERS

     The Company is subject to federal, state and local laws and regulations
dealing with air and water quality and other environmental matters.
Environmental matters may expose the Company to potential liabilities which, in
certain instances, may be imposed without regard to fault or historical
activities which were lawful at the time they occurred.  The Company continually
monitors its activities in order to determine the impact of its activities on
the environment and to ensure compliance with various environmental laws.  The
Company has recorded a total liability of approximately $24.2 million in
connection with Site Investigation and/or Remediation (SIR) efforts where
disposal of certain waste products may have occurred. Estimates of the SIR costs
for each of these sites range from preliminary to highly refined. The Company
expects to pay these SIR costs over the next ten years.  These estimates could
change materially, based on facts and circumstances derived from site
investigations, changes in required remedial action, changes in technology
relating to remedial alternatives and changes to current laws and regulations.
Liability may be joint and several for certain of these sites.  There may be
additional costs with respect to these and possibly other sites, the materiality
of which is not presently determinable.

     COMPANY-OWNED ELECTRIC AND GAS WASTE SITE ACTIVITIES.  The Company is
conducting proactive SIR efforts at seven Company-owned sites where past waste
handling and disposal may have occurred.  Remediation activities at five of
these sites are in various stages of planning or completion and the Company is
conducting a program to restore the other two sites. The Company has recorded a
liability of approximately $21.6 million for SIR efforts at the seven Company-
owned sites in the Rochester, NY area.

     SUPERFUND AND NON-OWNED OTHER SITES.  The Company has been or may be
associated as a potentially responsible party at eight sites not owned by it and
has recorded estimated liabilities of approximately $.8 million in connection
with SIR efforts at these sites.   The Company has signed orders on consent for
five of these sites.

     GRIFFITH FACILITIES.  The Company's subsidiary, Energetix, recently
acquired Griffith Oil, Inc.  A review and audit was conducted of all Griffith
facilities by a nationally recognized engineering firm as part of the due
diligence acquisition process by Energetix.   As a result of the review of 43
sites and subsequent subsurface investigations of 26 sites, thirteen new New
York
<PAGE>
 
                                       71

State Department of Environmental Conservation (NYSDEC) spill numbers were
assigned. These sites are currently undergoing evaluation and remediation
planning for corrective action. Using historical NYSDEC remedial actions as a
guide, Energetix estimates the accrual of aggregate cleanup costs over a five-
year period for all 43 sites approximates $1.8 million.


GAS COST RECOVERY

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

  On October 16, 1998, the Company, the staff of the PSC and certain other
parties entered into an interim settlement agreement, designed to address the
period between expiration of the 1995 Settlement and the implementation of a new
multi-year settlement to be negotiated.  The interim settlement was approved by
the PSC on November 4, 1998.  In its ruling the PSC indicated that the
allocation of transition costs that result from the migration of customers to
other gas suppliers under the Interim Settlement Agreement may be subject to
revision after it considers similar issues in another case.  Major elements of
the interim settlement include: (1) the term is from December 1, 1998 through
the earlier of June 30, 1999 or the effective date of a new multi-year
agreement; (2) base rates, which cover the cost of the local distribution
system, will remain frozen for all customers at their current level (which were
fixed at the July 1994 level pursuant to the 1995 Settlement that expired on
October 31, 1998), while the Gas Cost Adjustment will continue to vary from
month to month; (3) a level of revenues ($11.9 million on an annual basis) which
corresponds to the Company's anticipated revenues from capacity remarketing
transactions currently in place is imputed to the Company; (4) the Company will
share 15% of the savings realized from the reduction of capacity commitments;
(5) the Company will simplify the transportation gas program and cap the
migration of customers at 10% of annual retail sales and not assign capacity
costs to certain migrating customers; (6) the Company will be allowed to recover
the upstream costs that may be stranded by migration; and, (7) certain issues
relating to past gas costs have been resolved whereby the Company shall set
aside, in a manner to be determined by the PSC for the benefit of customers,
$2.2 million of the total amount recovered through the Gas Cost Adjustment.


LITIGATION

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

  In 1994, Northern States Power Company and other owners of nuclear plants
filed suit against DOE and the federal government in the U.S. Court of Appeals
for the District of Columbia Circuit (Court) seeking a declaration that DOE's
course of action was in violation of its statutory obligation and requesting
<PAGE>
 
                                       72

other relief.  In 1996, the Court upheld the utilities' position that DOE is
obligated to accept and dispose of the utilities' SNF by the statutory deadline.
The Court rejected the DOE contention that it could defer the disposal until the
availability of a suitable SNF repository, but stopped short of providing the
utilities a remedy since DOE had not yet defaulted.

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

  By a Joint Petition for Review, the Company and other nuclear utilities
petitioned the Court in January 1997 for a declaration that the Petitioners were
relieved of the obligation to pay fees into the Nuclear Waste Fund, and were
authorized to place those fees into escrow 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 the statutory deadline.  In
November 1997, the Court held that DOE could not delay acceptance on grounds
that it lacked an SNF repository, and that the utilities had a "clear right to
relief".  Rather than grant funding relief and order the DOE to move SNF,
however, the Court referred the utilities to their contractual remedies against
DOE.  State agencies, municipal governments and DOE sought review of this
decision, but the U.S. Supreme Court declined in November 1998 to hear the case.
The Company, joined by several other nuclear utilities, in July 1998 initiated a
further effort to have the Court provide a suitable remedy under its "original
and exclusive" jurisdiction over matters arising under the Nuclear Waste Act.
The Court has yet to rule on that request.

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

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

   LITIGATION WITH CO-GENERATOR.  On December 1, 1998 the Company completed the
closing under its Global Settlement Agreement with General Electric Capital
Corporation (GECC), Kamine/Besicorp Allegany L.P. (Kamine) and other Kamine
affiliates.  In connection with the closing the Company paid $10 million and
gave a promissory note in the aggregate amount of $168 million payable to GECC.
The promissory note is secured by a general mortgage on the Company's property
which mortgage is subject and subordinate to the Company's First Mortgage.  The
mortgage is not recorded but may be recorded in the event of default.  In
addition the Company purchased the gas-fired generation facility rated at 65Mw
for $15 million.  The Global Settlement was approved by the PSC which authorized
the Company to recover the payments in rates.
<PAGE>
 
                                       73

OTHER MATTERS


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

     EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY.  In July
1997, the Financial Accounting Standards Board's Emerging Issues Task Force
(EITF) reached a consensus on accounting rules for 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". 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, 1998 in nuclear generating assets is $666.9
million and in non-nuclear generating assets is $117.9 million.
<PAGE>
 
                                       74

     LEASE AGREEMENTS.  The Company, including Energetix, leases 15 properties
for administrative offices, operating activities and vehicles.  The total lease
expense charged to operations was $4.8 million, $4.2 million and $3.9 million in
1998, 1997 and 1996, respectively.  For the years 1999, 2000, 2001, 2002 and
2003 the estimated lease expense charged to operations will be $5.2 million,
$3.4 million, $3.3 million, $2.9 million and $2.8 million, respectively.
Commitments under capital leases were not significant to the accompanying
financial statements.

  GAS PURCHASE COMMITMENTS.  Energetix has entered into natural gas purchase
commitments with numerous gas suppliers.  These commitments support a fixed
price offering to retail gas customers.

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, 1998     $287,106   $22,345   $15,015      $14,088     $ .37  $ .37
September 30, 1998     253,606    34,444    25,213       23,908       .62    .62
June 30, 1998/1/       211,134    22,203    15,655       14,350       .37    .37
March 31, 1998/1/      282,516    48,168    38,255       36,950       .95    .95
 
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     $ .52  $ .52
September 30, 1996     234,843    36,159    21,062       19,196       .49    .49
June 30, 1996          235,577    23,115    11,732        9,866       .25    .25
March 31, 1996         309,195    56,866    42,489       40,623      1.05   1.05
 
</TABLE>

/1/ Reclassified for comparative purposes.


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

     None
<PAGE>
 
                                       75

                                    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 29, 1999, 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.
Registrant's definitive proxy statement dated March 8, 1999 will be filed with
the Securities and Exchange Commission prior to April 30, 1999. The information
required in Items 10 through 13 under the headings set forth above is
incorporated by reference herein by this reference thereto.  Except as
specifically referenced herein the proxy statement in connection with the annual
meeting of shareholders to be held April 29, 1999 is not deemed to be filed as
part of this Report.
<PAGE>
 
                                       76


                                    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, 1998.

         Consolidated Statement of Retained Earnings for each of the three
         years ended December 31, 1998.

         Consolidated Balance sheet at December 31, 1998 and 1997.

         Consolidated Statement of Cash Flows for each of the three years
         ended December 31, 1998.

         Notes to Consolidated Financial Statements.


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

         For each of the three years ended December 31, 1998.

         Schedule II - Valuation and Qualifying Accounts.



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

(b)      Reports on Form 8-K

         None
<PAGE>
 
                                       77

                    ROCHESTER GAS AND ELECTRIC CORPORATION

                SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

                            (Thousands of Dollars)

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> 

FOR THE YEAR ENDED DECEMBER 31, 1998


<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       $26,926      $861      $507      $1,740      $26,554
 
Materials and supplies
  obsolescence                 3,200                           1,010        2,190

</TABLE> 

     Beginning in 1992 the Company no longer charges uncollectible expenses
through the uncollectible reserve.  The 1998 reserves for uncollectibles
includes Energetix.  The total amount written off directly to expense in 1996
was $15,039, in 1997 was $12,912 and in 1998 was $11,838.  In 1997, the amounts
charged to other accounts represent a true-up of writeoff amounts during the
implementation of a new customer information system ($3.0 million) and the
forgiveness of late payment amounts which had previously been reflected as
revenue ($1.3 million).  In 1996, the entire amount charged to other accounts is
attributable to forgiveness of late payment amounts.  In 1998, the amount
charged to other accounts reflects consolidation of Energetix/Griffith reserve
for uncollectibles ($0.3 million) and forgiveness of late payments ($0.2
million).  The deductions in 1998 represent true-ups of the estimated reserve
required for uncollectibles. The deductions in the materials and supplies
reserve in 1998 represent actual writeoffs of obsolete material.
<PAGE>
 
                                       78

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.


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 3-3
               in February 1999 on Form 10-K for the year ended December 31,
               1998, 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)



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>
 
                                       79

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)



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. 1-6722)



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)



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)



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)



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)



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)  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)



Exhibit 10-12* (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)

Exhibit 10-13  (A)  Agreement dated January 1, 1999 between the Company and
                    Thomas S. Richards, Chairman of the Board, President and
                    Chief Executive Officer.



Exhibit 10-14  (A)  Agreement dated January 1, 1999 between the Company and Paul
                    C. Wilkens, Senior Vice President, Generation.
<PAGE>
 
                                       80


Exhibit 10-15  (A)  Agreement dated January 1, 1999 between the Company and J.
                    Burt Stokes, Senior Vice President, Corporate Services and
                    Chief Financial Officer.



Exhibit 10-16  (A)  Agreement dated January 26, 1999 between the Company and
                    Michael J. Bovalino, President, Energetix, Inc.



Exhibit 10-17*      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 as Exhibit 10-18 in February 1998 on
                    Form 10-K for the year ended December 31, 1997, SEC File No.
                    1-672)



Exhibit 10-18* (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 10-19  (A)  Agreement, dated January 18, 1999, between the Company and
                    Michael T. Tomaino, Senior Vice President and General
                    Counsel.



Exhibit 10-20*      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 10-21       Global Settlement Agreement as amended October 29, 1998
                    between the Company, General Electric Capital Corporation
                    and Kamine/Besicorp Allegany L.P. and other Kamine
                    affiliates.

Exhibit 23          Consent of PricewaterhouseCoopers 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>
 
                                       81

                                  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 19, 1999



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



SIGNATURE                       TITLE                        DATE
---------                       -----                        ----


Principal Executive Officer:



 /S/ THOMAS S. RICHARDS         Chairman of the Board,    February 19, 1999
----------------------------     President and
 (Thomas S. Richards)           Chief Executive Officer   

                              

Principal Financial Officer:


 /S/   J. B. STOKES             Senior Vice President     February 19, 1999
----------------------------    Corporate Services and
     (J. Burt Stokes)           Chief Financial Officer
                              


Principal Accounting Officer:


 /S/   WILLIAM J. REDDY         Controller                February 19, 1999
----------------------------                                            
     (William J. Reddy)
<PAGE>
 
                                       82

SIGNATURE                     TITLE                   DATE
---------                     -----                   ----


Directors:


/S/   ANGELO J. CHIARELLA     Director                February 19, 1999
---------------------------                                            
     (Angelo J. Chiarella)



/S/   ALLAN E. DUGAN          Director                February 19, 1999
---------------------------                                            
     (Allan E. Dugan)



/S/    MARK B. GRIER          Director                February 19, 1999
----------------------------                                           
     (Mark B. Grier)



/S/   SUSAN R. HOLLIDAY       Director                February 19, 1999
---------------------------                                            
     (Susan R. Holliday)



/S/   JAY T. HOLMES           Director                February 19, 1999
---------------------------                                            
     (Jay T. Holmes)



/S/   SAMUEL T. HUBBARD,JR    Director                February 19, 1999
---------------------------                                            
     (Samuel T. Hubbard,Jr.)




/S/CLEVE L. KILLINGSWORTH,JR. Director                February 19, 1999
-----------------------------                                          
(Cleve L. Killingsworth,Jr.)



/S/   ROGER W. KOBER          Director                February 19, 1999
---------------------------                                            
     (Roger W. Kober)



/S/   CONSTANCE M. MITCHELL   Director                February 19, 1999
---------------------------                                            
   (Constance M. Mitchell)



/S/   CORNELIUS J. MURPHY     Director                February 19, 1999
---------------------------                                            
     (Cornelius J. Murphy)



/S/   CHARLES I. PLOSSER      Director                February 19, 1999
---------------------------                                            
     (Charles I. Plosser)



/S/   THOMAS S. RICHARDS      Director                February 19, 1999
---------------------------                                            
     (Thomas S. Richards)