<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, 2000
                               -----------------
                              OR
     [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
         SECURITIES EXCHANGE ACT OF 1934

     For the transition period from ______________  to _____________________



Commission     Registrant, State of Incorporation      I.R.S. Employer
File Number    Address and Telephone Number            Identification No.
-------------  --------------------------------------  ------------------

0-30338        RGS Energy Group, Inc.                      16-1558410
               (Incorporated in New York)
               89 East Avenue
               Rochester, NY  14649
               Telephone (716)771-4444

1-672          Rochester Gas and Electric Corporation      16-0612110
               (Incorporated in New York)
               89 East Avenue
               Rochester, NY  14649
               Telephone (716)546-2700


Securities Registered Pursuant to section 12(b) of the Act:

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

RGS Energy Group, Inc.
Common stock, $.01 par value          New York Stock Exchange


Securities Registered Pursuant to section 12(g) of the Act:

Title of each class
-------------------

Rochester Gas and Electric Corporation
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
<PAGE>

  Indicate by check mark whether each 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 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, 2001 the aggregate market value of the voting stock of RGS
Energy Group, Inc. ("RGS") held by nonaffiliates was approximately:
$1,118,000,000.

  On January 1, 2001 the aggregate market value of the voting stock of Rochester
Gas and Electric Corporation ("RG&E") held by nonaffiliates was:

None.

  As of the close of business on January 1, 2001, (i) RGS had outstanding
34,577,426 shares of Common Stock ($.01 par value) and, (ii) RG&E had
outstanding 38,885,813 shares of Common Stock ($5 par value) all of which were
held by RGS.

  RG&E meets the conditions set forth in General Instructions (I)(1)(a) and (b)
of Form 10-K and is therefore, filing this form with the reduced disclosure
format pursuant to General Instructions (I)(2).

                      Documents Incorporated By Reference

  Portions of RGS's definitive proxy statement in connection with the 2001
Annual Meeting of Shareholders, to be filed with the Commission pursuant to
Regulation 14A not later than 120 days after December 31, 2000, are incorporated
in Part III of this report.  Information required by Part III with respect to
RG&E has been omitted pursuant to General Instruction (I)(2)(c).
<PAGE>

                           Abbreviations and Glossary

BTU                 British Thermal Unit.  The amount of heat required to raise
                    the temperature of one pound of water one degree Fahrenheit
                    at 60 degrees Fahrenheit.

Cooling degree days A measure that quantifies the extent to which the daily
                    outdoor average temperature exceeds a base of 65 degrees
                    Fahrenheit.  One-degree day is counted for each degree-day
                    falling above the assumed base for each calendar day.

Company or RGS      RGS Energy Group, Inc., a holding company formed August 2,
                    1999, which is the parent company of Rochester Gas and
                    Electric Corporation, RGS Development Corporation and
                    Energetix, Inc.

CWIP                Construction work-in progress

EITF                Emerging Issues Task Force

Electric Settlement Competitive Opportunities Case Settlement among RG&E, PSC
                    and other parties which provides the framework for the
                    development of competition in the electric energy
                    marketplace through June 30, 2002

Energetix           Energetix, Inc., a wholly-owned subsidiary of the Company

Energy Choice       A competitive electric retail access program of RG&E being
                    phased-in over a period ending July, 2001

FERC                Federal Energy Regulatory Commission

Ginna Plant         Ginna Nuclear Plant which is wholly owned by RG&E

Griffith            Griffith Energy, an oil, gasoline and propane distribution
                    company acquired by Energetix in 1998

Heating degree day  A measure that quantifies the extent to which the daily
                    outdoor average temperature falls below a base of 65 degrees
                    Fahrenheit.  One-degree day is counted for each degree-day
                    falling below the assumed base for each calendar day.

LDC                 Local Distribution Company

Nine Mile Two       Nine Mile Point Nuclear Plant Unit No. 2 of which RG&E owns
                    a 14% share

NOI                 Notice of Inquiry

NOPR                Notice of Proposed Rulemaking

NYISO               New York Independent System Operator

NYNOC               New York Nuclear Operating Company

NYPA                New York Power Authority

NYSDEC              New York State Department of Environmental Conservation

NRC                 Nuclear Regulatory Commission

O&M                 Operation and Maintenance

PSC                 New York State Public Service Commission

Regulatory Assets   Deferred costs whose classification as an asset on the
                    balance sheet is permitted by SFAS-71, Accounting for the
                    Effects of Certain Types of Regulation.

RG&E                Rochester Gas and Electric Corporation, a wholly-owned
                    subsidiary of RGS

RGS Development     RGS Development Corporation, a wholly-owned subsidiary of
                    the Company
<PAGE>

RTO                 Regional Transmission Organization

SEC                 Securities and Exchange Commission

SFAS                Statement of Financial Accounting Standards

SFAS 71             Accounting for the Effects of Certain
                    Types of Regulation
<PAGE>

                              RGS ENERGY GROUP, INC.
                     ROCHESTER GAS AND ELECTRIC CORPORATION

                       Information Required on Form 10-K


                                                               Page
                                                               ----
FILING FORMAT                                                       1

FORWARD-LOOKING STATEMENTS                                          1

<TABLE>
<CAPTION>

Item
Number      Description
------      -----------

Part I
------
<S>         <C>                                                <C>
Item 1      Business                                                 1
Item 2      Properties                                              13
Item 3      Legal Proceedings                                       14
Item 4      Submission of Matters to a Vote of Security Holders     16
Item 4A     Executive Officers of the Registrant                    17


Part II
-------

Item 5      Market for the Registrant's Common Equity and
            Related Stockholder Matters                             19
Item 6      Selected Financial Data                                 21
Item 7      Management's Discussion and Analysis of Financial
            Condition and Results of Operations                     24
Item 7A     Quantitative and Qualitative Disclosures about
            Market Risk                                             44
Item 8      Financial Statements and Supplementary Data             45
Item 9      Changes in and Disagreements with Accountants on
            Accounting and Financial Disclosure                     81


Part III
--------

Item 10     Directors and Executive Officers of the Registrant      82
Item 11     Executive Compensation                                  82
Item 12     Security Ownership of Certain Beneficial Owners and
            Management                                              82
Item 13     Certain Relationships and Related Transactions          82

Part IV
-------

Item 14     Exhibits, Financial Statement Schedules and Reports
            on Form 8-K                                             83

            Signatures                                              88
</TABLE>
<PAGE>

                                       1

FILING FORMAT

     This Annual report on Form 10-K is a combined report being filed by two
different registrants: RGS and RG&E.  See "Corporate Structure" in Item 1.
Except where the content clearly indicates otherwise, any references in the
report to "RGS" or the "Company" include all subsidiaries of RGS including RG&E.
RG&E makes no representation as to the information contained in this report in
relation to RGS and its subsidiaries other than RG&E.  When this report is
incorporated by reference into any filing with the SEC made by RG&E, the
portions of this report that relate to RGS and its subsidiaries other than RG&E
are not incorporated by reference therein.

FORWARD-LOOKING STATEMENTS

     This report 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.
Actual results or developments might differ materially from those included in
the forward-looking statements because of factors such as those discussed in
Item 7.

                                     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.

<TABLE>
<CAPTION>

     CAPTION                                       PAGE
     -------                                       ----
    <S>                                            <C>
     Corporate Structure                              1
     Electric Operations                              3
     Gas Operations                                   5
     Unregulated Operations                           5
     Regulatory Matters                               6
     Fuel Supply                                      6
     Financing and Capital Requirements Program       7
     Environmental Quality Control                    9
     Research and Development                        10
     Operating Statistics                            11

</TABLE>
CORPORATE STRUCTURE

  RGS Energy Group Inc.  RGS was incorporated in 1998 in the State of New York
and became the holding company for RG&E on August 2, 1999.  RGS has no employees
and no significant business operations other than through RG&E and RGS's other
subsidiaries as described below.

  Rochester Gas and Electric Corporation.  RG&E was incorporated in 1904 in
the State of New York and is engaged principally in the business of generating,
purchasing, transmitting and distributing electricity, and purchasing,
transporting and distributing natural gas. RG&E produces and distributes
electricity and distributes gas in parts of nine counties including and
surrounding the City of Rochester.  At December 31, 2000 RG&E had 2022
employees.
<PAGE>

                                       2

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

     Energetix, Inc.   Energetix was formed to pursue retail electric, gas and
liquid fuel business throughout Upstate New York.  Energetix and its subsidiary,
Griffith now serve a combined total of over 200,000 customers. Griffith's growth
has been accomplished primarily through acquisitions.  Griffith's most recent
acquisitions were Burnwell(R) Gas and AllEnergy - New York Fuels Division
Companies, which both closed in mid-November.  Energetix' acquisitions have
provided it with access to 123,000 customers, 100,000 of whom reside outside
RG&E's regulated franchise territory.  Excluding any of its acquisitions,
Energetix has over 83,000 customers for natural gas and electricity service.

     In total, Energetix and Griffith had approximately 651 employees and had
operated 28 customer service centers as of December 31, 2000.

     RGS Development Corporation.  In 1998, the Company formed RGS Development
to pursue unregulated business opportunities in the energy marketplace.  Through
December 31,2000 RGS Development's operations have not been material to RGS's
results of operations or its financial condition.

     Seasonal Nature of Business.  The businesses of RGS and RG&E are 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.

     Franchises.  In each of the communities in which it renders regulated
utility service, RG&E, with minor exceptions, holds the necessary municipal
franchises, none of which contains burdensome restrictions.  The franchises are
non-exclusive, and are generally unlimited as to time or run for terms of years.

     Segment Information. 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:

<TABLE>
<CAPTION>
                     RGS     RG&E    RGS     RG&E
                    ------  ------  ------  ------
                     2000    2000    1999    1999    1998
                    -----   -----   -----   -----   -----
<S>                 <C>     <C>     <C>     <C>     <C>
Electric             49.8%   69.1%   57.9%   64.1%   66.4%
Gas                  22.3%   30.9%   23.1%   25.5%   26.6%
Unregulated          27.9%  ----     19.0%   10.4%    7.0%
                    -----   -----   -----   -----   -----
                    100.0%  100.0%  100.0%  100.0%  100.0%
</TABLE>
<PAGE>

                                       3

COMPETITION

     RGS 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.

     See Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading "Competition" for further
information on the Electric Settlement, Energy Choice, Nine Mile Nuclear Plants,
Gas Retail Access Program, NYISO and the competitive challenges the Company
faces in its electric and gas business and how it is responding to those
challenges.

ELECTRIC OPERATIONS

     Overview.  In November 1997, the PSC approved the Electric Settlement among
RG&E, 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 RG&E's electric business, starting
in 1996 FERC issued new rules to facilitate the development of competitive
wholesale markets.  In 1998, FERC issued an order that conditionally authorized
the establishment of the NYISO to administer a state-wide open access tariff.
In 1999 FERC issued an Order approving the NYISO Open Access tariff, the NYISO
Services tariff and the related NYISO Agreements of each of the Member Systems
of the New York Power Pool.  In November 1999 the NYISO implemented a
competitive wholesale market for the sale, purchase and transmission of
electricity in New York State.  In December 1999 FERC issued Rule No. 2000 which
calls for transmission owners to join RTOs to boost competition (see following
discussion under "Regulatory Matters").  At the New York State level, the PSC
endorsed a fundamental restructuring of the electric utility industry in the
state in its "Competitive Opportunities Proceeding".  RG&E'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.  As of December 31, 2000, seven energy service
companies had been qualified by the Company to serve retail customers under the
Energy Choice Program.

     Electric System.  The total net generating capacity of RG&E's electric
system is 1,033,000 kilowatts (Kw).  In addition RG&E purchases 120,000 Kw of
firm power under contract and 35,000 Kw of non-contractual peaking power from
the NYPA, 150,000 Kw of a 1,000,000 Kw pumped storage plant owned by NYPA in
Schoharie County, New York and 44,000 Kw of firm power from NYPA's 821,000 Kw
FitzPatrick Nuclear Power Plant near Oswego, New York.  RG&E's all time net peak
load of 1,433,000 Kw occurred on July 6, 1999.

     The percentages of electricity actually generated and purchased net of Less
energy for pumping and Pumped storage for the years 1996-2000 are as follows:

<TABLE>
<CAPTION>
                                         RGS     RG&E    RGS     RG&E
                                        ------  ------  ------  ------
                                         2000    2000    1999    1999    1998    1997    1996
                                        -----   -----   -----   -----   -----   -----   -----
<S>                                     <C>     <C>     <C>     <C>     <C>     <C>     <C>
Sources of Generated Energy:
Nuclear, Net                             54.1%   54.3%   52.2%   54.9%   59.5%   61.6%   49.4%
Fossil, Net                              17.0    17.1    18.7    19.6    22.0    20.0    18.2
Hydro and Other, Net                      2.3     2.3     1.5     1.6     2.1     2.7     3.0
                                        -----   -----   -----   -----   -----   -----   -----

Total Generated, Net                     73.4    73.7    72.4    76.1    83.6    84.3    70.6
Purchased                                26.6    26.3    27.6    23.9    16.4    15.7    29.4
                                        -----   -----   -----   -----   -----   -----   -----

Total Electric Energy                   100.0%  100.0%  100.0%  100.0%  100.0%  100.0%  100.0%
                                        =====   =====   =====   =====   =====   =====   =====
</TABLE>

     Generating Facilities.   RG&E's four major generating facilities are two
nuclear units, Ginna and the RG&E's 14 percent share of Nine Mile Two, and two
fossil fuel generating stations, the Russell and Allegany
<PAGE>

                                       4

Stations. In terms of capacity these comprise 46%, 15%, 25% and 6%,
respectively, of the Company's current electric generating system.

     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 RG&E (14%), Niagara Mohawk (41%) Long Island Power
Authority (18%), New York State Electric and Gas (NYSEG) (18%) and Central
Hudson Gas & Electric Corporation (Central Hudson) (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.
RG&E, Niagara Mohawk, Central Hudson, and NYSEG entered into an agreement to
sell their ownership interests in Nine Mile Two to Constellation Nuclear, L.L.C.
(Constellation Nuclear). Constellation Nuclear was the successful bidder in a
competitive auction for the plants. The Long Island Power Authority, an 18
percent owner of Nine Mile Two, is not participating in the sale. The NRC, FERC,
PSC and other regulatory bodies must approve the sale. Receipt of such
regulatory approvals, in form and substance reasonably satisfactory to RG&E, is
a condition to RG&E's obligation to close the transaction. (see Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations under the heading, "Nine Mile Nuclear Plants").  The gross and net
book cost of the RG&E's share of the Nine Mile Two generating facility as of
December 31, 2000 were $878 million and $360 million, respectively, including
$374 million of disallowed costs previously written off.

     RG&E's Ginna Plant, which has been in commercial operation since July 1,
1970, provides 480 Mw of RG&E's electric generating capacity and has an
operating license with an expiration date of September 18, 2009.

     The gross and net book costs of the Ginna Plant generating facility as of
December 31, 2000 were $577 million and $228 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 to such directives.  Typically, these
directives are premised on the NRC's obligation to protect the public health and
safety.  RG&E 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 $7.6
million, $7.6 million and $6.4 million for the years 2001, 2002 and 2003,
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.

     RG&E has three licensed hydroelectric generating stations (Stations 2, 5
and 26) with an aggregate capability of 47 megawatts.

     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 of 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.  RG&E's Ginna Plant and its interest
in Nine Mile Two 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.  When and if RG&E sells its interest in
Nine Mile Two, its exposure will be reduced to $88.1 million per incident,
payable at a rate not to exceed $10 million per incident per year.

     As a licensee of a commercial nuclear power plant in the United States,
RG&E is required to have and maintain financial protection to cover radiation
injury claims of certain nuclear workers. RG&E 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 RG&E, or against other licensees who
<PAGE>

                                       5

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, RG&E could be assessed under these former policies along
with the other policyholders.  RG&E's share could be up to $3.1 million in any
one year.

     RG&E 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, RG&E could be subject to maximum assessments
in any one policy year of approximately $1.8 million and $8.5 million relating
to losses under the replacement power and property damage coverages,
respectively.

GAS OPERATIONS

     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 RG&E.
Large industrial and commercial gas customers have had a choice of suppliers
since the mid-1980s, and all other gas customers (i.e. retail) have had a choice
of suppliers since November 1996.  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. For further information concerning issues
relating to RG&E under the PSC's Gas Policy Statement - see Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations under the heading "Rates and Regulatory Matters".

     As of December 31, 2000 RG&E's daily city gate resource capability is
3,520,000 therms and its daily contracted transportation capacity is 4,401,500
therms (where one Therm is equivalent to 100,000 BTUs). RG&E experienced 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) on January 19, 1994.

     RG&E purchases its gas supply from numerous energy marketers under
contracts containing various terms and conditions (including long-term, short-
term, and daily swing or spot market), transported on both firm and
interruptible pipeline transportation contracts.  RG&E acquires and delivers the
most cost efficient reliable gas supply and optimizes its assets by contracting
for gas resources that align with its system requirements of meeting retail gas
demand and balancing transportation gas supply deliveries and demand.  During
2000, approximately 60% of RG&E's natural gas supply was purchased at first-of-
month prices and approximately 40% was purchased on the daily spot market. The
Company hedges its exposure to fluctuations in natural gas commodity prices
through the use of storage assets and risk management.  (See Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations under the heading "Risk Management".)

     RG&E distributes and sells, or transports, natural gas to a geographic
territory in a nine-county area including and surrounding the City of Rochester,
New York.  During 2000, 43.0% of the gas delivered  by RG&E was purchased by
commercial, industrial, municipal, and retail customers directly from energy
marketers.  RG&E provided the transportation of gas on its system to these
customers' premises.  As RG&E retail customers continue to migrate to energy
marketers, including Energetix, RG&E is terminating gas supply and
transportation contracts upon expiration.

UNREGULATED OPERATIONS

  Energetix serves over 83,000 electric and gas customers and through its
acquisition of Griffith and its other acquisitions, an additional 123,000
customers for its other products including fuel oil, diesel, kerosene, propane
and gasoline. See Note 4 of the Notes to Financial Statements for additional
operating information and Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations under the heading "Unregulated
Operating Revenues and Sales" for information on products, revenues and sales.
<PAGE>

                                       6

REGULATORY MATTERS

     RG&E is subject to PSC regulation of rates, service and sale of securities,
among other matters.  RG&E is also regulated by 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, RG&E is also subject to regulation by the NRC.  The impact of
regulation is discussed throughout this report.

     FERC ELECTRIC RESTRUCTURING ORDER NO. 2000.   On December 15, 1999, FERC
adopted Order No. 2000 (the Rule), a significant action regarding electric
industry restructuring which calls for transmission owners to join RTOs. The
RTOs will serve as umbrella organizations that will place all public utility
transmission facilities in a region under common control.  The Rule required all
public utilities that own, operate or control interstate transmission facilities
to file by October 15, 2000 (or, for public utilities, like RG&E, already
participating in an ISO, by January 15, 2001), a proposal for an RTO, or,
alternatively, a description of any efforts made by the utility to participate
in an RTO.

     On January 16, 2001, the NYISO and all the New York State public utilities
made a joint filing with FERC regarding the establishment of a RTO.  In the
consensus filing, the parties submit that the NYISO meets the general
requirements of a RTO, and the NYISO agrees to make certain enhancements of its
structure and programs to benefit the markets.  Minor modifications are proposed
to the governance structure and transmission planning, and the NYISO agrees to
coordinate more closely with other RTOs.

     RG&E cannot predict what effect, if any, the ultimate ruling by FERC will
have on future operations or on the financial condition of the Company.

     FERC GAS MARKET PROPOSALS.

     On February 9, 2000, FERC issued Order No. 637, its final rule addressing
"Regulation of Short-Term Natural Gas Transportation Services" and "Regulation
of Interstate Natural Gas Transportation Services".  On June 5, 2000 FERC issued
Order No.637-A providing clarification and additional guidance. On July 26, 2000
FERC issued Order 637-B upholding Orders 637 and 637-A. The Order revises FERC's
regulations to improve the efficiency of the gas transportation market and to
provide captive customers with the opportunity to reduce their cost of holding
long-term pipeline capacity.

     RG&E cannot predict what effects, if any, FERC's initiatives and the
related pipeline tariff changes will have on future operations or the financial
condition of the Company.  For further information see Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of Operations under
the heading "FERC Gas Market Proposals"

     ADDITIONAL INFORMATION.  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 restructuring policy
statement, gas retail access settlement, and a flexible pricing tariff for major
industrial and commercial electric customers.

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:
<PAGE>

                                       7

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

       Uranium Concentrate           2001/(2)/         2004/(3)/
       Conversion                    2001/(4)          2004/(3)/
       Enrichment                    2009/(5)/         2004/(6)/
       Fabrication                   2009              2004

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

(2)  A contract is in place, which is supplying 500,000 pounds of uranium
     between 2001 and 2004 as scheduled by RG&E.  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.

(3)  Arrangements have been made for procuring 100% of the uranium and
     conversion requirements through 2002 and 61 percent through 2004, leaving
     the remaining portion of the requirements uncommitted.

(4)  A contract is in place covering 100% of requirements in 2001.  Remaining
     requirements will be filled from market purchases or a new long-term
     contract.

(5)  RG&E has a contract for nuclear fuel enrichment services which assures
     provision of 100% of the Ginna Plant's requirements through the end of the
     current operating license.

(6)  Nine Mile Two is covered for 100% of requirements through 2002 and 75%
     through 2004 (with an option to increase to 100%).

     With appropriate lead times, RG&E 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 2 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. RG&E's 2001 coal requirements are expected to be approximately
560,000 tons.  In 2000, 56% of its requirements were purchased under contract
and 44% were purchased on the spot market. RG&E maintains a reserve supply of
coal ranging from 30-60 days supply at maximum burn rates.

     Under existing New York State regulations, RG&E's coal-fired facility may
not burn coal which exceeds a sulfur content of 2.5 pounds per million BTU, and
must average no higher than 1.7 pounds per million BTU over a 12-month period or
1.9 pounds per million BTU over a three-month period. The sulfur content of the
coal utilized in RG&E's coal-fired facility ranges from 1.0 to 2.0 pounds per
million BTU and are in compliance with New York State regulations.  In 2001,
Phase II Acid Rain Requirements will apply, requiring the surrender of (sulfur
dioxide) SO2 allowances to match SO2 emissions.

FINANCING AND CAPITAL REQUIREMENTS PROGRAM

     A discussion of RGS'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.  Through December 31, 2000 RGS has repurchased 4.4 million shares of
Common Stock under a program which began in May 1998.  Common Stock is the only
security issued by RGS.  Preferred Stock and Mortgage Bonds have been issued by
RG&E.  The sale of additional issues of these securities by RG&E depends on
regulatory approval and RG&E's ability to meet certain requirements contained in
its mortgage and Restated Certificate of Incorporation.
<PAGE>

                                       8

     Under the New York State Public Service Law, RG&E is required to secure
authorization from the PSC prior to issuance of any stock or any debt having a
maturity of more than one year.  On November 27, 2000 RG&E obtained the
authorization of the PSC to issue up to $400 million of long-term debt not later
than December 31, 2002.

     RG&E'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 forty supplemental indentures.  The
General Mortgage requires the following financial requirements to be satisfied
before additional First Mortgage Bonds are issued:

(a)  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, 2000 was 6.08.

(b)  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, 2000 the
     amount of additional First Mortgage Bonds, which could be issued on that
     basis, was approximately $463,000,000.  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, 2000, RG&E could issue $257,169,000 of Bonds
     against Bonds that have matured or been redeemed.

     RG&E's Restated Certificate of Incorporation (Charter) provides that,
without consent by two-thirds of the votes entitled to be cast by its preferred
stockholders, RG&E 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, 2000, the coverage ratio under
(b) above (the more restrictive provision) was 2.23.

     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 Charter of RGS does not contain any financial tests for the issuance of
common or preferred stock.  The Charter of RG&E does not contain any financial
tests for the issuance of common or preference stock.  However, it does have
financial tests for preferred stock.

     RGS has not issued any mortgage bonds or preferred stock.  RG&E's
securities ratings at December 31, 2000 were:

<TABLE>
<CAPTION>
                                       First
                                      Mortgage  Preferred
                                       Bonds      Stock
                                      --------  ---------
<S>                                   <C>       <C>

     Standard & Poor's Corporation       A-        BBB
     Moody's Investors Service           A3        baa1
     Fitch                               A-        BBB
</TABLE>

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

                                       9

ENVIRONMENTAL QUALITY CONTROL

     Operations at the Company's facilities are subject to various federal,
state and local environmental standards.  The Company monitors its activities in
order to determine the impact of its activities on the environment and to ensure
compliance with various environmental requirements.  Most of the Company's
environmental compliance issues arise in connection with RG&E's operations;
however, Energetix's subsidiary Griffith has environmental issues relating to
its storage and distribution of petroleum products.  The environmental
regulatory schemes that have the greatest impact on the Company are the federal
Low Level Radioactive Waste Policy Act, the federal Clean Water Act's State
Pollutant Discharge Elimination System ("Water Regulations") and the federal
Clean Air Act, as amended (the "Clean Air Act").  In addition, there are several
initiatives in New York State that, if implemented, may affect the Company in
the future.  Excluding capital expenditures relating to the Federal Clean Air
Act, the Company expects to have environmental capital expenditures of $10.3
million and $3.2 million in 2001 and 2002 respectively.  The 2001 expenditures
are due largely to transmission and delivery expenditures for a spill prevention
countermeasure control project, a breaker replacement project and a regulator
replacement project, all of which will be completed in 2001.

     As a result of RG&E's ownership of the Ginna Plant it must dispose of the
spent nuclear fuel in compliance with the federal Low Level Radioactive Waste
Policy Act.  This act provides for states to join compacts or individually
develop their own low level radioactive waste disposal sites.  New York State
has not passed legislation designating a site for the disposal of low level
radioactive waste, and the Company can provide no assurance the timing and
nature of disposal arrangements, if any, New York State will make.  As permitted
by its license to operate the Ginna Plant, RG&E is now storing spent fuel at the
Ginna Plant.  This license expires in 2009 and, if it is not extended, RG&E
would be required to make alternative disposal arrangements at that time.

     Under the Water Regulations, RG&E is required to cause its wastewater
discharge to satisfy certain requirements.  To comply with the Water
Regulations, RG&E was required to obtain wastewater discharge permits from
NYSDEC for each of its steam electric generating stations.  The Ginna Station
permit is dated February 1998; the Beebee Station permit is dated February 1999;
the Allegany Station permit is dated March 1998, and the Russell Station permit
is dated June 1999.  These permits are each valid for a period of five years
from their effective dates.  RG&E believes that it is in compliance with these
permits and that no material expenditures are presently required to remain in
compliance.

  The Clean Air Act regulates the air emissions from RG&E's fossil-fueled
generating facilities.  In order to be able to comply with the Clean Air Act,
RG&E must continue to make capital expenditures at these generating facilities.
RG&E estimates that its compliance with the Clean Air Act in 2001 will require
capital expenditures of approximately $1.3 to $1.5 million operating and
maintenance costs for emissions control of approximately $2.7 million to $3.4
million.  RG&E estimates that capital expenditures necessary to comply with the
Clean Air Act will range from $1.5 to 2.3 million in 2002.  In addition to
capital improvements, RG&E has purchased emission allowances to assist it in
complying with the Clean Air Act and expects to continue to do so in the future
as necessary.  The estimated cost of these allowances for 2001 are included in
the operating and maintenance estimate.  There are proposals in the New York
State legislature that could limit RG&E's ability to rely upon the emission
allowance market to meet some of its environmental commitments.  If it were
unable to satisfy some of its environmental commitments with emission
allowances, either because of legislative changes or an inability to obtain
emission allowances, RG&E would be required to make additional capital
expenditures to comply with the Clean Air Act, which could be significant.

  In New York State, the Governor of New York has directed the NYSDEC to require
electric generators to further reduce acid rain-causing emissions.  The Governor
has proposed extending the existing oxides of nitrogen (Nox) control program
under which RG&E's Russell Station operates to a year-round program (it is
currently in effect only for the five-month ozone season) and requiring a
targeted reduction of approximately 50% in SO2 emissions below the existing Acid
Rain Phase II limits.  The state emission reductions would be phased-in
beginning in 2003 and be complete by 2007.  Separately, the NYSDEC has issued a
notice of violation to RG&E alleging that certain repair, replacement and
maintenance activities at its coal-fired power plants required permission from
the NYSDEC prior to their occurrence.  Because these New York initiatives
<PAGE>

                                       10

are in preliminary stages, neither RG&E nor RGS can determine their future
impact on RG&E if they are implemented or pursued.

     Because of the nature of RG&E's operations, future changes to environmental
laws and regulations will require RG&E to change aspects of its operations, make
additional capital improvements and incur additional remediating and operating
costs.  RG&E believes that expenditures and costs made necessary by mandated
environmental protection programs will be allowable for ratemaking purposes
under cost of service rate regulation. However under the terms of RG&E's
Competitive Opportunities Settlement Agreement, which sets a threshold of $2.5
million for recoverability of expenditures and costs resulting from mandates, to
the extent that these costs do not meet $2.5 million, the full amount of these
items may not be recoverable.

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

     RG&E'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 2000, 1999 and 1998 were $2.6 million,
$2.9 million and $3.4 million, respectively.  These expenditures represent
RG&E's contribution to research administered by Electric Power Research
Institute, New York Gas Group, and 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>

                                       11

OPERATING STATISTICS
--------------------
Electric Department Statistics  (dollars in millions)

<TABLE>
<CAPTION>
                                                     RGS       RG&E      RGS       RG&E
Year Ended December 31                              2000       2000     1999*      1999*    1998      1997      1996
<S>                                                <C>       <C>       <C>       <C>       <C>       <C>       <C>
----------------------------------------------------------------------------------------------------------------------
Electric Revenue
Residential                                         $247.9    $247.9    $273.2    $273.2    $250.1    $252.5    $254.9
Commercial                                           161.0     161.0     171.1     171.1     203.3     210.6     215.8
Industrial                                           103.9     103.9     115.5     115.5     130.8     144.3     153.3
Municipal and Other                                   35.8      35.8      48.4      48.3      58.9      72.1      66.8
----------------------------------------------------------------------------------------------------------------------
Electric revenue -- retail customers                 548.6     548.6     608.2     608.1     643.1     679.5     690.8
Energy Marketers (including Energetix)                99.5      99.5      65.2      65.2      15.0
Other Electric Utilities                              73.6      73.6      25.3      25.3      29.0      20.8      16.9
Other unregulated electric revenues                    9.3                 4.0       1.5       0.5
----------------------------------------------------------------------------------------------------------------------
  Total electric revenues                            731.0     721.7     702.7     700.1     687.6     700.3     707.7
----------------------------------------------------------------------------------------------------------------------
Electric Expense
Fuel for electric generation                          48.9      48.9      49.3      49.3      54.0      47.7      40.9
Purchased electricity                                 81.0      80.9      53.0      53.0      27.0      28.3      46.5
Other unregulated fuel expense                         4.9                 1.3
Operation and maintenance                            253.4     253.4     233.8     233.8     233.4     246.3     246.2
Unregulated operation  / maintenance                   2.0                 2.2       1.0       2.0
Depreciation and amortization                        100.9      99.6     103.0     103.0     102.1     103.4      92.6
Taxes - local, state and other                        66.6      65.1      84.6      84.0      89.6      91.1      95.0
----------------------------------------------------------------------------------------------------------------------
  Total electric expense                             557.7     547.9     527.2     524.1     508.1     516.8     521.2
----------------------------------------------------------------------------------------------------------------------
Operating Income before Income Tax                   173.3     173.8     175.5     176.0     179.5     183.5     186.5
  Income tax                                          49.0      49.6      55.2      55.5      61.5      61.8      61.9
----------------------------------------------------------------------------------------------------------------------
Operating Income from Electric Operations           $124.3    $124.2    $120.3    $120.5    $118.0    $121.7    $124.6
----------------------------------------------------------------------------------------------------------------------
Electric Sales - MWH (000's)
Residential                                          2,154     2,154     2,269     2,269     2,120     2,139     2,133
Commercial                                           1,680     1,680     1,783     1,783     2,036     2,119     2,062
Industrial                                           1,557     1,557     1,762     1,762     1,914     2,011     2,011
Municipal and Other                                    391       391       482       482       517       537       521
----------------------------------------------------------------------------------------------------------------------
  Total retail sales                                 5,782     5,782     6,296     6,296     6,586     6,806     6,726
Energy Marketers                                     1,134     1,134       763       763       175
Other electric utilities                             1,636     1,636     1,112     1,112     1,499     1,219       995
Other unregulated sales                                162                  23         2
----------------------------------------------------------------------------------------------------------------------
  Total electric sales                               8,714     8,552     8,194     8,173     8,260     8,025     7,721
----------------------------------------------------------------------------------------------------------------------
Electric Distribution Customers at
December 31 (Thousands)
Residential                                            313       313       311       311       310       309       307
Commercial                                              32        32        30        30        30        31        31
Industrial                                               1         1         1         1         1         1         1
Municipal and Other                                      5         5         2         2         3         3         3
----------------------------------------------------------------------------------------------------------------------
  Total electric customers                             351       351       344       344       345       344       342
----------------------------------------------------------------------------------------------------------------------
Electricity Generated and
  Purchased - MWH (000's)
Fossil                                               1,548     1,548     1,693     1,693     1,963     1,665     1,513
Nuclear                                              4,926     4,926     4,735     4,735     5,324     5,120     4,094
Hydro                                                  208       208       133       133       190       228       249
Pumped storage                                          67        67       233       233       233       239       247
Less energy for pumping                               (101)     (101)     (350)     (350)     (348)     (358)     (370)
Other                                                                        1         1                   1         1
----------------------------------------------------------------------------------------------------------------------
Total generated - net                                6,648     6,648     6,445     6,445     7,361     6,894     5,733
Purchased                                            2,422     2,389     2,089     2,068     1,466     1,302     2,437
----------------------------------------------------------------------------------------------------------------------
  Total electric energy                              9,070     9,037     8,534     8,513     8,827     8,195     8,171
----------------------------------------------------------------------------------------------------------------------
RGE System Net Capability
  MW at December 31
  Total system net capability                        1,382     1,382     1,382     1,382     1,588     1,614     1,617
RGE Net Peak Load - MW                               1,367     1,367     1,433     1,433     1,388     1,421     1,305
----------------------------------------------------------------------------------------------------------------------
</TABLE>
* Reclassified for comparative purposes.
<PAGE>

                                       12

Gas Department Statistics (dollars in millions)
-----------------------------------------------

<TABLE>
<CAPTION>
                                                    RGS     RG&E      RGS     RG&E
Year Ended December 31                             2000     2000     1999*    1999*    1998*    1997*    1996*
---------------------------------------------------------------------------------------------------------------
<S>                                                <C>      <C>      <C>      <C>      <C>      <C>      <C>
Gas Revenue
Residential                                        $  6.7   $  6.7   $  5.7   $  5.7   $  2.9   $  5.9   $  6.0
Residential spaceheating                            250.2    250.2    212.8    212.8    201.7    249.1    246.9
Commercial                                           36.3     36.3     31.1     31.1     40.2     51.9     52.1
Industrial                                            3.4      3.4      3.0      3.0      4.2      5.8      6.2
Municipal and other                                   9.0      9.0     19.7     19.7     24.9     23.6     35.1
---------------------------------------------------------------------------------------------------------------
Gas Revenue - retail customers                      305.6    305.6    272.3    272.3    273.9    336.3    346.3
---------------------------------------------------------------------------------------------------------------
Marketers                                            16.8     16.8      6.4      6.4      0.8
Other unregulated gas revenues                       17.6               5.8      2.9
---------------------------------------------------------------------------------------------------------------
 Total gas revenue                                  340.0    322.4    284.5    281.6    274.7    336.3    346.3
---------------------------------------------------------------------------------------------------------------
Gas Expense
Gas purchased for resale                            192.0    192.0    147.0    147.0    155.5    196.6    202.3
Other unregulated fuel expense                       16.5               4.4      2.0
Operation and maintenance                            60.3     60.3     64.0     64.0     68.2     68.8     67.0
Unregulated operation and maintenance                 3.9               2.8      1.3      2.5
Depreciation                                         14.8     12.5     12.6     12.6     12.9     13.1     13.0
Taxes - local, state and other                       28.0     25.0     28.6     27.8     28.2     30.8     31.9
---------------------------------------------------------------------------------------------------------------
 Total gas expense                                  315.5    289.8    259.4    254.7    267.3    309.3    314.2
---------------------------------------------------------------------------------------------------------------
Operating Income before
 Federal Income Tax                                  24.5     32.6     25.1     26.9      7.4     27.0     32.1
Income Tax (Benefit)                                  8.8      9.8      8.0      8.4     (0.1)     3.4      7.6
---------------------------------------------------------------------------------------------------------------
 Gas Operations                                    $ 15.7   $ 22.8   $ 17.1   $ 18.5   $  7.5   $ 23.6   $ 24.5
---------------------------------------------------------------------------------------------------------------
Gas Sales - Therms (Millions)
Residential                                           6.0      6.0      5.9      5.9      3.6      5.8      6.5
Residential spaceheating                            261.8    261.8    264.0    264.0    239.7    285.4    299.1
Commercial                                           41.3     41.3     43.2     43.2     53.6     65.7     70.5
Industrial                                            4.2      4.2      4.5      4.5      6.1      7.8      9.3
Municipal                                             4.6      4.6      5.7      5.7      6.4      7.3      8.1
---------------------------------------------------------------------------------------------------------------
 Total retail sales                                 317.9    317.9    323.4    323.4    309.4    372.0    393.5
Transportation of customer-owned gas                239.6    239.6    200.0    200.0    163.6    166.1    167.8
Other unregulated sales                              36.6              12.5      7.1      1.2
---------------------------------------------------------------------------------------------------------------
 Total gas sold and transported                     594.1    557.5    535.9    530.5    474.1    538.1    561.3
---------------------------------------------------------------------------------------------------------------
Gas Distribution Customers at
 December 31 (000's)
Residential                                          14.3     14.3     16.5     16.5     16.9     16.3     16.7
Residential spaceheating                            251.1    251.1    246.5    246.5    249.7    243.3    240.7
Commercial                                           19.6     19.6     19.5     19.5     19.7     19.2     19.0
Industrial                                            0.8      0.8      0.8      0.8      0.8      0.8      0.9
Municipal                                             1.0      1.0      1.1      1.1      1.1      1.1      1.0
Transportation                                        0.7      0.7      0.7      0.7      0.7      0.7      0.7
 Total gas customers                                287.5    287.5    285.1    285.1    288.9    281.4    279.0
---------------------------------------------------------------------------------------------------------------
RGE, Gas - Therms (millions)
Purchased for resale                                230.7    230.7    200.0    200.0    203.7    274.4    279.4
Gas from storage                                     95.0     95.0    126.2    126.2    111.2    104.3    122.8
Other                                                 1.7      1.7      2.2      2.2      1.5      1.4      1.1
---------------------------------------------------------------------------------------------------------------
 Total gas available - RGE                          327.4    327.4    328.3    328.3    316.3    380.2    403.3
---------------------------------------------------------------------------------------------------------------
Total Daily Capacity - RGE
 Millions of Therms at December 31**                4,402    4,402    4,493    4,493    4,380    4,380    4,480
---------------------------------------------------------------------------------------------------------------
Max. daily throughput, Therms - RGE (millions)      4,305    4,305    4,008    4,008    3,584    4,114    4,023
Degree Days (Calendar Month)
For the period (thousands)                            6.6      6.6      6.3      6.3      5.7      6.9      7.0
Percent colder (warmer) than normal                  (1.9)    (1.9)    (6.6)    (6.6)   (15.9)     2.8      3.9
---------------------------------------------------------------------------------------------------------------
</TABLE>
 *  Reclassified for comparative purposes.
**  Method for determining daily capacity, based on current network analysis,
reflects the maximum demand which the transmission systems can accept without a
deficiency.
<PAGE>

                                       13

Item 2.  PROPERTIES

ELECTRIC PROPERTIES

     The net capability of RG&E's electric generating plants in operation as of
December 31, 2000  and the net generation of each plant for the year ended
December 31, 2000, 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>
Allegany Station
 (Gas Turbine)                Gas                1998             63             124,603

Beebee Station
 (Gas Turbine)                Oil                1969             14                 912

Russell Station
 (Steam)                      Coal          1949-1957            257           1,419,183

Ginna Station
 (Steam)                      Nuclear            1970            480           3,809,539

Nine Mile Point
 Unit No. 2/(1)/
 (Steam)                      Nuclear            1988            158           1,116,460

Station No. 9
 (Gas Turbine)                Gas                1969             14               3,029

Station 5
 (Hydro)                      Water              1917             39             166,941

Other Stations
 (Hydro)                      Water         1906-1960              8              40,597
                                                                ----           ---------
                                                                               6,681,264
Pumped Storage(net)/(2)/                                                         (33,749)
                                                                               ---------
                                                               1,033           6,647,515
                                                               =====
</TABLE>
(1)  Represents 14% share of jointly-owned facility.
(2)  Owned and operated by NYPA.  In May 2000, Gilboa began operating as a
     financial resource rather than operating as a physical energy supply.

     RG&E owns 149 distribution substations having an aggregate rated
transformer capacity of 2,331,054 Kva, of which 140, having an aggregate rated
capacity of 2,151,888 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.  RG&E also has 70,865 line
transformers with a capacity of 2,678,470 Kva.  RG&E also owns 23 transmission
substations having an aggregate rated transformer capacity of 3,335,617 Kva of
which 22, having an aggregate rated capacity of 3,260,950 Kva, were located on
land owned in fee and one, having a rated capacity of 74,667 Kva, was located on
land under easements.  RG&E's transmission system consists of approximately 726
circuit miles of overhead lines and approximately 411
<PAGE>

                                       14

circuit miles of underground lines. The distribution system consists of
approximately 16,379 circuit miles of overhead lines, approximately 4,285
circuit miles of underground lines and 359,019 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
RG&E 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.

GAS PROPERTIES

     The gas distribution systems consist of 4,280 miles of gas mains and
297,217 installed meters.  (See Item 1 - Business, "Gas Operations" and "Gas
Department Statistics".

UNREGULATED SUBSIDIARIES

  Griffith, including its subsidiaries, owns or leases 71 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.

     -  (23) bulk plant facilities: these bulk petroleum facilities are
        primarily supplied by truck and have an aggregate storage capacity of
        157,000 barrels.

     -  (14) service stations: these retail sites are sublet to a dealer who
        provides various services at retail to the general public.

     -  (31) other properties: these are a mixture of other properties including
        office buildings, warehouses, and garage facilities used in the general
        operation of the business.

OTHER PROPERTIES

     RG&E owns a ten-story office building centrally located in Rochester and
other structures and property.  RG&E also leases approximately 485,000 square
feet of facilities for administrative offices and operating activities in the
Rochester area.

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


Item 3.  LEGAL PROCEEDINGS

     RG&E-OWNED WASTE SITE ACTIVITIES. RG&E is conducting proactive Site
Investigation and/or Remediation (SIR) efforts at eight 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 investigating the other three sites. RG&E has
recorded a total liability of approximately $22.4
<PAGE>

                                       15

million at December 31, 2000 which it anticipates spending on SIR efforts at the
eight Company-owned sites. Through December 31, 2000 the Company has incurred
aggregate costs of $6.9 million for these sites. While there are no formal legal
proceedings regarding any of these sites, three of the sites are identified on
the NYSDEC's "The Hazardous Substance Site Inventory". Since RG&E is currently
performing or planning remediation activities at these three sites, the Company
does not anticipate that listing on The Hazardous Substance Site Inventory will
have any effect on its plans.

     Manufactured Gas Plants (MGPs).  RG&E and its predecessors formerly owned
and operated four manufactured gas facilities and acquired (following cessation
of MGP operations) two others for which SIR costs are estimated to be
approximately $20 million.  RG&E estimates that SIR costs at one of these sites
known as East Station may be as much as $14.5 million.  These properties are in
various stages of remediation and RG&E is coordinating its remediation
activities with the NYSDEC.

     SUPERFUND AND NON-OWNED OTHER SITES. RG&E has been or may be associated as
a potentially responsible party at nine sites not owned by it and has recorded
estimated liabilities of approximately $.5 million in connection with SIR
efforts at these sites.  RG&E has signed orders on consent for five of these
sites.  RG&E's ultimate exposure will depend on the final determination of
RG&E's contribution to the waste at these sites and the financial viability of
the other potential responsible parties at these sites.

     In June, 1999, RG&E was named as a codefendant in a legal action brought by
a party who purchased a portion of its Ambrose Yard property.  The party has
claimed that the RG&E's historic activities on the property resulted in the
presence of residual contaminants that have adversely impacted the party's use
of the property.  RG&E is just beginning to investigate the claim and does not
know whether the claim has any merit.  There is insufficient information
available at this time to predict the economic impact of the claim on RG&E.

     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 $1.8 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 a decision by the Court entered June 28, 2000, the
trial court (i) granted summary judgment against the defendant Sun Pipe Line,
(ii) dismissed the complaint against Chevron, USA, (iii) determined that a
question of fact existed as to the liability of Griffith as an operator of the
failed spur, and (iv) denied Sun's motion for indemnification pursuant to an
Access Agreement signed by Griffith upon discovery of the incident.   The Court
also determined in its bench decision that Griffith did not own the failed spur.
This Order has been appealed by all defendants, including Griffith.  Most
significantly, if the Order regarding indemnification is reversed, Griffith
could be held liable for Sun's defense and response costs.

     In connection with the acquisition of Griffith by Energetix, a stock
purchase agreement obligates the seller of Griffith to pay for environmental
claims or remedial action on Griffith property once the amount of environmental
losses incurred by Energetix exceeds $3.5 million less any reserve reflected on
the balance sheet at the time of acquisition.  At December 31, 2000
approximately $1.1 million has been spent and $1.2 million is estimated to be
spent.

     In connection with the acquisition of AllEnergy by Griffith, an asset
purchase agreement in November 2000, an environmental accrual was established
for $1.5 million.  At December 31, 2000 no environmental expenses have been
incurred and $1.5 million is estimated to be spent.
<PAGE>

                                       16

     In June of 2000, Griffith received notification that it is considered a
responsible party in connection with petroleum contamination at its Phelps, New
York facility.  Griffith leases an office and garage at this facility.  From
approximately 1996 through 1998, it stored distillate fuels at the bulk
petroleum storage facility at the site, which was owned by Jeffrey Fuels, Inc.
Earlier this year, NYSDEC received complaints of gasoline contamination
affecting the water wells of local residents.  While no action has been
commenced, it is anticipated that Griffith will be named in any future cost
recovery suit or other action regarding this facility.   The Phelps-Clifton
Springs School District, as well as Jeffrey Fuels, Inc. have also been
identified as responsible parties.  Since Griffith stored only distillate fuels
at this site, and not gasoline, it will continue to disclaim responsibility.

OTHER LAWSUITS AND CLAIMS. RG&E and Griffith are involved in other lawsuits and
claims relating to its operations, including lawsuits and claims relating the
condition of real property which it owns, leases or has owned or leased.
Neither RGS nor RG&E believes that these lawsuits or claims, individually or in
the aggregate, would have a material adverse impact on the operation or results
of operations of RGS or RG&E.

     See Item 8, Note 12 - 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, 2000.
<PAGE>

                                       17

Item 4-A.  EXECUTIVE OFFICERS OF THE REGISTRANT

  The following table sets forth certain information about the officers of RGS
and RG&E as of January 1, 2001.  Unless otherwise indicated all positions and
offices listed are with RG&E.

                       Age,
                      as of   Positions, Offices and Business Experience
Name                  1/1/01               1996 to date
----                 -------               ------------

Thomas S. Richards      57    Chairman, President and Chief Executive
                              Officer of RGS - August 1999 to date.

                              Chairman, President and Chief Executive
                              Officer - January 1998 to date.

                              President and Chief Operating Officer -
                              March 1996 to December 1997.

                              Senior Vice President, Energy Services - September
                              1995 to March 1996.


Michael J. Bovalino     45    Senior Vice President of RGS - August 1999 to
                              date.

                              President, Griffith - August 1998 to date.

                              President and Chief Executive Officer, Energetix,
                              Inc. (a wholly owned subsidiary of RGS) 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          57    Senior Vice President and Chief Financial Officer
                              of RGS - August 1999 to January 31, 2001.

                              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>

                                       18

                       Age,
                      as of         Positions, Offices and Business Experience
Name                  1/1/01                        1996 to date
----                 -------                        ------------

Michael T. Tomaino      63          Senior Vice President and General Counsel of
                                    RGS - August 1999 to date.

                                    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        53           Senior Vice President of RGS - August 1999
                                    to date.

                                    Senior Vice President, Generation - March
                                    1998 to date.

                                    Director, Gas Services - January 1996 -
                                    March 1998.

                                    Principal Consultant - May 1995 - January
                                    1996.


William J. Reddy       53           Controller of RGS - August 1999 to date.

                                    Vice President and Controller - August 1999
                                    to date.

                                    Controller - April 1997 to August 1999.

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


     The term of office of each officer extends to the meeting of the Board of
Directors following the next election of Directors of their company and until
his or her successor is elected and qualified.
<PAGE>

                                       19

                                    PART II

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


COMMON STOCK AND DIVIDENDS

<TABLE>
<CAPTION>
                                    RGS/                                                 RGS/
                              RGS    RGE    RGE                                  RGS      RGE      RGE
Earnings/Dividends           2000   1999   1998     Shares/Shareholders         2000     1999     1998
---------------------------  -----  -----  -----    ------------------------  -------  -------  -------
<S>                          <C>    <C>    <C>      <C>                       <C>      <C>      <C>
Earnings per share                                  Number of shares
                                                    (000's)
       basic                 $2.61  $2.44  $2.32    Weighted average
                                                      basic                    35,178   36,665   38,462
       diluted               $2.60  $2.44  $2.31      diluted                  35,281   36,757   38,600
Dividends paid                                      Actual number at
   per share                 $1.80  $1.80  $1.80     December 31               34,577   35,943   37,379
                                                    Common share price
                                                     at December 31           $ 32.44  $ 20.56  $ 31.25
                                                    Number of  registered
                                                     shareholders
                                                     at December 31            25,518   27,258   28,995
</TABLE>


RGS ENERGY GROUP, INC.

  On August 2, 1999, Rochester Gas and Electric Corporation (RG&E) was
reorganized into a holding company structure pursuant to an Agreement and Plan
of Share Exchange (Exchange Agreement) between RG&E and RGS Energy Group, Inc.
(RGS). As part of the reorganization, all of the outstanding shares of RG&E
common stock were exchanged on a share-for-share basis for shares of RGS and
RG&E became a subsidiary of RGS.  Certificates for shares of RG&E common stock
are automatically valid as certificates for RGS and do not have to be replaced.
The transfer does not affect the value of the stock or RGS's dividend policy.
RG&E shareholders approved the Exchange Agreement on April 29, 1999.

TAX STATUS OF CASH DIVIDENDS

     Cash dividends paid in 2000, 1999 and 1998 were 100 percent taxable for
federal income tax purposes.

DIVIDEND POLICY

     RG&E has paid cash dividends quarterly on its common stock without
interruption since it became publicly held in 1949.  Since its formation in
August 1999, RGS has continued this historic practice of dividend payments.

     The ability of RGS to pay common stock dividends is governed by the ability
of RGS's subsidiaries to pay dividends to RGS.  Because RG&E is by far the
largest of RGS's subsidiaries, it is expected that for the foreseeable future
the funds required by RGS to enable it to pay dividends will be derived
predominantly from the dividends paid to RGS by RG&E.  In the future, dividends
from subsidiaries other than RG&E may also contribute to RGS's ability to pay
dividends.   RG&E's ability to make dividend payments to RGS will depend upon
the availability of retained earnings and the needs of its utility business.
RG&E's Certificate of Incorporation provides for the payment of dividends on its
common stock out of the surplus net profits (retained earnings) of RG&E.  In
addition, pursuant to the PSC order approving the formation of RGS, RG&E may pay
dividends to RGS of no more than 100% of RG&E's net income calculated on a two-
year rolling basis.  The calculation of net income for this
<PAGE>

                                       20

purpose excludes non-cash charges to income resulting from accounting changes or
certain PSC required charges as well as charges that may arise from significant
unanticipated events. This condition does not apply to dividends that would be
used to fund the remaining portion of RG&E's $100 million authorization for
unregulated operations (about $13 million at December 31, 2000).

     Quarterly dividends on Common Stock are generally paid on the twenty-fifth
day of January, April, July and October.  In January 2001, RGS paid a cash
dividend of $.45 per share on its Common Stock.  The January 2001 dividend
payment is equivalent to $1.80 on an annual basis.

STOCK PRICE

  RGS's common stock has been traded on the New York Stock Exchange under the
symbol "RGS" since August 2, 1999.  Prior to that date, RG&E's common stock was
traded on the New York Stock Exchange, also under the symbol "RGS".  RG&E's
common stock is no longer traded because it is all held by RGS.  The closing
stock price for RGS common stock was $31.31 on January 26, 2001.




[Chart appears here showing range of common stock for the years 1998, 1999 and
2000.]




<PAGE>

                                       21

ITEM 6 -  SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
CONSOLIDATED SUMMARY OF OPERATIONS               RGS                      RGS
                              Year Ended     Consolidated    RG&E     Consolidated      RG&E
(Millions of Dollars)         December 31,       2000        2000         1999          1999        1998        1997        1996
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>           <C>        <C>             <C>         <C>         <C>         <C>
Operating Revenues

  Electric                                    $   731.0   $   721.7    $   702.8     $   700.2   $   687.6   $   700.3   $   707.8
  Gas                                             340.0       322.4        284.5         281.6       274.7       336.3       346.2
  Other                                           377.1           -        220.3         108.6        71.2           -           -
                                              ---------   ---------    ---------     ---------   ---------   ---------   ---------

    Total Operating Revenues                  $ 1,448.1     1,044.1      1,207.6       1,090.4     1,033.5     1,036.6     1,054.0

Operating Expenses
   Fuel Expenses
    Fuel for electric generation                   48.9        48.9         49.3          49.3        54.0        47.7        40.9
    Purchased electricity                          85.9        80.9         54.3          53.0        27.0        28.3        46.5
    Gas purchased for resale                      208.5       192.0        151.5         149.0       155.5       196.6       202.3
    Unregulated fuel expenses                     340.3           -        189.4          91.5        59.5           -           -
                                              ---------   ---------    ---------     ---------   ---------   ---------   ---------

     Total Fuel Expenses                          683.6       321.8        444.5         342.8       296.0       272.6       289.7
                                              ---------   ---------    ---------     ---------   ---------   ---------   ---------

Operating Revenues Less Fuel Expenses             764.5       722.3        763.1         747.6       737.5       764.0       764.3

Other Operating Expenses
  Operations and maintenance
    excluding fuel expenses                       313.7       313.7        297.9         297.9       301.6       315.1       313.2
  Unregulated operating and
    maintenance expenses excluding fuel            31.1           -         26.5          14.2        13.5           -           -
  Depreciation and amortization                   116.2       112.1        118.7         117.3       116.1       116.5       105.6
  Taxes - local, state and other                   94.6        90.1        114.6         112.6       118.0       121.8       126.9
  Income tax                                       59.8        59.5         64.4          64.5        60.3        65.3        69.4
                                              ---------   ---------    ---------     ---------   ---------   ---------   ---------

    Total Other Operating Expenses                615.4       575.4        622.1         606.5       609.5       618.7       615.1
                                              ---------   ---------    ---------     ---------   ---------   ---------   ---------

Operating Income                                  149.1       146.9        141.0         141.1       128.0       145.3       149.2

Other (Income) and Deductions
  Allowance for other funds used during
    construction                                   (0.8)       (0.8)        (0.7)         (0.7)       (0.4)       (0.4)       (0.7)
  Income tax                                        1.1         0.2         (1.3)         (1.1)        1.7        (3.7)       (3.5)
  Other, net                                       (9.5)       (8.9)        (8.0)         (8.1)      (13.4)        3.4        (0.6)
                                              ---------   ---------    ---------     ---------   ---------   ---------   ---------

    Total Other (Income) and Deductions            (9.2)       (9.5)       (10.0)         (9.9)      (12.1)       (0.7)       (4.8)

Interest Charges

  Long term debt                                   58.0        56.7         53.7          53.1        43.3        44.6        48.6
  Other, net                                        6.0         5.5          4.8           4.5         3.4         6.6         9.3
  Allowance for borrowed funds used during
    construction                                   (1.3)       (1.3)        (1.1)         (1.1)       (0.7)       (0.6)       (1.4)
                                              ---------   ---------    ---------     ---------   ---------   ---------   ---------

    Total Interest Charges                         62.7        60.9         57.4          56.5        46.0        50.6        56.5

Net Income                                         95.6        95.5         93.6          94.5        94.1        95.4        97.5

Preferred Stock Dividend Requirements               3.7         3.7          4.1           4.1         4.8         5.8         7.5

Net Income Applicable to Common Stock         $    91.9   $    91.8    $    89.5     $    90.4   $    89.3   $    89.6   $    90.0
                                              =========   =========    =========     =========   =========   =========   =========
Earnings per Common Share - Basic             $    2.61                $    2.44                 $    2.32   $    2.30   $    2.32

Earnings per Common Share - Diluted           $    2.60                $    2.44                 $    2.31   $    2.30   $    2.32

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

<PAGE>

                                       22

Condensed Consolidated Balance Sheet

<TABLE>
<CAPTION>
                                                                    RGS                 RGS
                                                               Consolidated  RG&E  Consolidated    RG&E
(Millions of Dollars)                      At December 31,         2000      2000      1999        1999     1998    1997*    1996*
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>           <C>        <C>        <C>      <C>     <C>     <C>
Assets
Utility Plant                                                     $3,396    $3,349      $3,254     $3,231   $3,327  $3,234   $3,160
Less:  Accumulated depreciation and
  amortization                                                     2,005     1,990       1,876      1,874    1,863   1,714    1,569
                                                                  ------    ------      ------     ------   ------  ------   ------
                                                                   1,391     1,359       1,378      1,357    1,464   1,520    1,591
Construction work in progress                                        111       111          95         96       98      74       70
                                                                  ------    ------      ------     ------   ------  ------   ------
Net Utility Plant                                                  1,502     1,470       1,473      1,453    1,562   1,594    1,661
Current Assets                                                       307       277         220        203      203     242      250
Intangible Assets                                                     51         -          21          -       21       -        -
Deferred Debits and Other Assets                                     706       704         749        747      667     432      450
                                                                  ------    ------      ------     ------   ------  ------   ------
     Total Assets                                                 $2,566    $2,451      $2,463     $2,403   $2,453  $2,268   $2,361
------------------------------------------------------            ------    ------      ------     ------   ------  ------   ------
Capitalization and Liabilities
Capitalization
Long term debt                                                    $  824    $  792      $  816     $  796   $  758  $  587   $  647
Preferred stock redeemable at option
  of RG&E                                                             47        47          47         47       47      47       67
Preferred stock subject to mandatory
  redemption                                                          25        25          25         25       25      35       45
Common shareholders' equity:
  Common stock                                                       703       700         700        700      700     699      696
  Retained earnings                                                  182       166         153        138      129     109       91
  Less: Treasury stock at cost                                       117       117          83         83       46       -        -
                                                                  ------    ------      ------     ------   ------  ------   ------
Total common shareholders' equity                                    768       749         770        755      783     808      787
                                                                  ------    ------      ------     ------   ------  ------   ------
  Total Capitalization                                            $1,664    $1,613      $1,658     $1,623   $1,613  $1,477   $1,546
                                                                  ------    ------      ------     ------   ------  ------   ------
Long Term Liabilities                                                131       129         126        125      124     110      106
Current Liabilities                                                  317       258         169        150      183     176      145
Deferred Credits and Other Liabilities                               454       451         510        505      533     505      564
                                                                  ------    ------      ------     ------   ------  ------   ------
     Total Capitalization and Liabilities                         $2,566    $2,451      $2,463     $2,403   $2,453  $2,268   $2,361
------------------------------------------------------            ------    ------      ------     ------   ------  ------   ------
</TABLE>

* Reclassified for comparative purposes.

<PAGE>

                                      23

FINANCIAL DATA

<TABLE>
<CAPTION>
     At December 31
RGS
                                                                            2000    1999  1998  1997  1996
                                                                          ------  ------  ----  ----  ----
<S>                                                                       <C>     <C>     <C>   <C>   <C>
   Capitalization Ratios (a) (percent)
   Long-term debt                                                           52.3    51.9  ---   ---   ---
   Preferred Stock                                                           4.1     4.1  ---   ---   ---
   Common shareholders' equity                                              43.6    44.0  ---   ---   ---
                                                                          ------  ------
     Total                                                                 100.0   100.0  ---   ---   ---

   Book Value per Common Share - Year End                                 $22.19  $21.43  ---   ---   ---
   Rate of Return on Average Common Equity (percent)                       11.82   11.53  ---   ---   ---
   Embedded Cost of Senior Capital (percent)                                              ---   ---   ---
   Long-term debt                                                           7.31    7.20  ---   ---   ---
   Preferred stock                                                          5.24    5.24  ---   ---   ---
   Interest Coverages                                                                     ---   ---   ---
   Before federal income taxes (incld. AFUDC)                               3.39    3.68  ---   ---   ---
                               (excld. AFUDC)                               3.36    3.65  ---   ---   ---
</TABLE>

RG&E
<TABLE>
<CAPTION>
                                                                            2000    1999    1998    1997   1996
                                                                          ------  ------  ------  ------  -----
<S>                                                                       <C>     <C>     <C>     <C>     <C>
Capitalization Ratios (a) (percent)
   Long-term debt                                                           52.0    51.8    49.8    43.0   44.7
   Preferred Stock                                                           4.2     4.2     4.2     5.2    6.9
   Common shareholder's equity                                              43.8    44.0    46.0    51.8   48.4
                                                                          ------  ------  ------  ------  -----
     Total                                                                 100.0   100.0   100.0   100.0  100.0

   Book Value per Common Share - Year End                                 $21.71  $21.00  $20.94  $20.80  20.24
   Rate of Return on Average Common Equity                                 12.12   11.76   11.22   11.00  11.41
    (percent)
   Embedded Cost of Senior Capital (percent)
   Long-term debt                                                           7.29    7.21    7.20    7.32   7.33
   Preferred stock                                                          5.24    5.24    5.56    5.80   6.26
   Interest Coverages
   Before federal income taxes (incld. AFUDC)                               3.49    3.74    4.41    4.06   3.82
                               (excld. AFUDC)                               3.46    3.71    4.38    4.04   3.79
</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.

<PAGE>

                                       24



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 RGS Energy Group,
Inc. and its subsidiaries over the past three years. The Consolidated Financial
Statements and the Notes thereto contain additional data. For the twelve months
ended December 31, 2000, 50 percent of the Company's operating revenues were
derived from electric service, 22 percent from natural gas service, and 28
percent from unregulated businesses.

FORWARD LOOKING STATEMENTS

     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 effect on whether the forward
looking statements ultimately prove to be accurate include:

 1. uncertainties related to the regulatory treatment of RG&E's nuclear
    generation facilities including the proposed sale of RG&E's interest in the
    Nine Mile Two nuclear generating facility;

 2. any state or federal legislative or regulatory initiatives (including the
    results of negotiations between RG&E and the PSC regarding certain gas
    restructurings) 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;

 3. any changes in the ability of RG&E to recover environmental compliance costs
    through increased rates;

 4. the determination in the nuclear generation proceeding initiated by the PSC,
    including any changes in the regulatory status of nuclear generating
    facilities and their related costs, including recovery of costs related to
    spent fuel and decommissioning;

 5. fluctuations in energy supply and demand and market prices for energy,
    capacity and ancillary services;

 6. any changes in the rate of industrial, commercial and residential growth in
    RG&E's and RGS's service territories;

 7. the development of any new technologies which allow customers to generate
    their own energy or produce lower cost energy;

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

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

10. the ability of RGS to manage profitably new unregulated operations;

11. certain unknowable risks involved in operating unregulated businesses in new
    territories and new industries; and

12. any other considerations that may be disclosed from time to time in the
    publicly disseminated documents and filings of RGS and RG&E.
<PAGE>

                                       25

Shown below is a listing of the principal items discussed.

<TABLE>
<S>                                               <C>
     RGS ENERGY GROUP, INC.                         Page 25
          Unregulated Subsidiaries

     ROCHESTER GAS AND ELECTRIC CORPORATION
       Competition                                  Page 26
          Gas Retail Access Settlements
          Gas Retail Access Program
          PSC Electric Settlement
          Energy Choice
          Nine Mile Nuclear Plants
          Fossil Units Status
          New York Independent System Operator
          Prospective Financial Position

       Rates and Regulatory Matters                 Page 34
          PSC Gas Restructuring Policy Statement
          PSC Gas Capacity Assignment
          FERC Gas and Electric Market Proposals
          Flexible Pricing Tariff

     LIQUIDITY AND CAPITAL RESOURCES                Page 36
          Capital and Other Requirements
          Financing
          Redemption of Securities
          Stock Repurchase Plan
          Environmental Issues
          Risk Management
          Year 2000 (Y2K) Computer Operational
            Information

     EARNINGS SUMMARY                               Page 39

     RESULTS OF OPERATIONS                          Page 39
          Operating Revenues and Sales
          Operating Expenses
          Other Statement of Income Items

     DIVIDEND POLICY                                Page 43

</TABLE>

RGS ENERGY GROUP, INC.

     On August 2, 1999, RG&E was reorganized into a holding company structure
pursuant to an Agreement and Plan of Share Exchange between RG&E and RGS. As
part of the reorganization, all of the outstanding shares of RG&E common stock
were exchanged on a share-for-share basis for shares of RGS and RG&E became a
subsidiary of RGS. RG&E's preferred stock was not exchanged as part of the share
exchange and continues as shares of RG&E.

     The holding company structure was formed to enable RGS to respond quickly
to changes in the evolving competitive energy utility industry.  The new
structure permits the use of financing techniques that are better suited to the
particular requirements, characteristics and risks of non-utility operations
without affecting the capital structure or creditworthiness of RG&E.  This
increases RGS's financial flexibility by allowing it to establish different
debt-to-equity ratios for each of its individual lines of business.
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                                       26

     RGS is a holding company and not an operating entity.  RGS's operations are
being conducted through its subsidiaries which include RG&E and two unregulated
subsidiaries - Energetix, Inc. and RGS Development Corporation.  RG&E will
continue to offer regulated electric and natural gas utility service in its
franchise territory.  Energetix, Inc. provides energy products and services
primarily throughout Upstate  New York.  RGS Development Corporation offers
energy systems development and management services.

     Unregulated Subsidiaries. Part of RGS's financial strategy is to seek
growth by entering into unregulated businesses. The Electric Settlement allows
RG&E to provide the funding for RGS to invest up to $100 million in unregulated
businesses and RGS has invested $87 million (including loan guarantees) as of
December 31, 2000.  The first step in this direction was the formation and
operation of Energetix, Inc. (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 throughout Upstate New York.  Energetix has over 83,000
customers for natural gas and electricity service.

     In August 1998, Energetix acquired Griffith Oil Company, Inc. (Griffith),
the second largest oil and propane distribution company in New York State.  This
$31.5 million acquisition was accounted for using purchase accounting and the
results of Griffith's operations are reflected in the consolidated financial
statements of RGS since its acquisition on August 2, 1998.

     In November 2000, Griffith acquired Burnwell(R)  Gas, a  full-service
propane gas retailer and distributor providing fuel, appliances, heating
equipment and service in the Western New York area.  This acquisition adds
29,000 customers to the Griffith customer base. The acquisition was accounted
for using purchase accounting and Burnwell(R)  Gas's results of operations are
reflected in the consolidated financial statements of RGS since the acquisition.

     In November 2000, Griffith also acquired certain assets of the New York
Fuels Division of AllEnergy Marketing Company, L.L.C. related to its petroleum
distribution business. This acquisition adds 24,000 customers to the Griffith
customer base. The acquisition was accounted for using purchase accounting and
the results of the acquired operations are reflected in the consolidated
financial statements of RGS since the acquisition.

     Griffith and its recent acquisitions as discussed above give Energetix
access to over 123,000 customers, approximately 100,000 of whom are outside of
RG&E's regulated franchise territory.  Acquisitions by Griffith since August
1998 have increased its customer base by over 100 percent.  In total, Griffith
has approximately 620 employees and operates 28 customer service centers as of
December 31, 2000.

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

     During the second quarter of 1998, the Company formed RGS Development to
pursue unregulated business opportunities in the energy marketplace.  Through
December 31, 2000, RGS Development's operations have not been material to RGS's
results of operations or its financial condition.

ROCHESTER GAS AND ELECTRIC CORPORATION

COMPETITION

     GAS RETAIL ACCESS SETTLEMENTS.  On January 25, 2001, RG&E reached agreement
with PSC Staff and other parties on a comprehensive rate and restructuring
proposal for its natural gas business (the Gas Rates and Restructuring
Proposal), as contemplated in the PSC's Gas Policy Statement (see heading Rates
and Regulatory Matters,  "PSC Gas Restructuring Policy Statement").

     Since mid-1998, RG&E, PSC Staff and other parties have engaged in
settlement negotiations regarding RG&E's rates and restructuring.  These
negotiations have resulted in two previous agreements among RG&E, PSC Staff and
several other parties.  The first was implemented in September 1999 and
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                                       27

addressed the following issues: a capacity release revenue imputation, capacity
cost mitigation measures, a timetable for public filing and resumption of
negotiations, and improvement of RG&E's retail access program.  The September
1999 agreement was approved by the PSC in an Order issued September 30, 1999.

     Pursuant to the September 1999 agreement, RG&E, on January 28, 2000, made a
filing addressing various issues pertaining to RG&E's natural gas business,
including proposals for restructuring that business and facilitating migration
from fully bundled sales service to retail service provided by natural gas
marketers.  Certain issues presented by the January 28, 2000 filing, principally
relating to the commencement of a single-retailer retail access program for gas,
in substantially the same form as currently in effect for electric retail access
(see "Energy Choice" heading), and the establishment of a "backout credit" to be
paid to natural gas marketers serving retail customers, were resolved in a June
2000 Gas Settlement.

     The Gas Rates and Restructuring Proposal is intended to resolve all issues
identified by the parties and not resolved in either the September 1999
settlement or the June 2000 Gas Settlement, as approved by the PSC.  It is
anticipated that this Proposal will be approved by the PSC in February 2001 and
made effective on March 1, 2001, although no assurance may be given as to such
approval or its timing.

     The Gas Rates and Restructuring Proposal contains a number of features that
are intended to extend for different periods.  The two most significant periods
are the Rate Term, which applies principally to rate-related provisions and
extends from July 1, 2000 through June 30, 2002, and the Rate and Restructuring
Program which applies to most other provisions and extends from the date of
approval of the Proposal through March 31, 2004. The principal features of the
Proposal are as follows:

     (1) for the purpose of setting base, or local delivery, rates for the
period beginning July 1, 2000, natural gas revenues shall be decreased a total
of $2,806,000 from the levels in effect on June 30, 2000.  This rate level is
based on an agreed-upon return on equity of 11.00 percent;

     (2) base rates will be adjusted effective March 1, 2001 to reflect the
revenue requirements decrease.  Because the current base rates that will be in
effect through February 28, 2001 are higher than those agreed to by the parties,
RG&E, in March 2001, will pass back to all its retail gas customers a temporary
credit applied to rates, on a volumetric basis, equal to the amount of the
reduction in rates for the period July 1, 2000 through February 28, 2001;

     (3) RG&E is allowed to defer any prudent and verifiable cost for recovery
after the Rate Term of the Proposal, subject to PSC approval;

     (4) in the event that RG&E achieves a return on equity in excess of 12.5
percent in any Rate Year covered by this Proposal, 90 percent of the excess over
that level shall be deferred for the benefit of customers;

     (5) RG&E shall be entitled to defer any costs associated with mandates and
catastrophic events that occur during the Rate Term of this Proposal.  If the
incremental cost impact of any individual mandate or any individual catastrophic
event exceeds $600,000 per rate year, RG&E is entitled to defer the entire
amount for recovery.  Amounts deferred shall be recovered from RG&E customers
after the Rate Term of this Proposal;

     (6) RG&E is entitled to defer for recovery after June 30, 2002, all
incremental expenditures for competition implementation costs to the extent that
such costs exceed $300,000 per year;

     (7) if migration to retail access is expected to exceed 30 percent of the
small-volume customer market (i.e., customers eligible under Service
Classification No. 5 - Small General Service) during the Rate Term of the
Proposal, the parties will meet to discuss the PSC Transition Cost Surcharge
with a view to considering changes that would reduce the allocation of capacity
costs to Service Classification No. 1 - General Service customers;

     (8) RG&E is authorized to implement a Retail Access Capacity Program,
contemplated to begin before the 2001-2002 heating season, pursuant to which
RG&E would release pipeline capacity it currently
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                                       28

holds to marketers serving customers in RG&E's service area. This Program will
help to avoid stranded capacity costs that might otherwise result from migration
of customers to marketers;

     (9) RG&E will implement a Capacity Incentive Program, consisting of a
Capacity Cost Incentive and a Capacity Cost Imputation.  Both elements are
intended to encourage aggressive management of RG&E's capacity costs.  The
Capacity Cost Incentive is designed to share, between RG&E and its customers,
the savings resulting from the difference between a base level of capacity costs
and the actual capacity costs achieved. The Capacity Cost Imputation is intended
to provide customers with a guaranteed level of short-term savings through the
gas cost adjustment provision.  "Short-term" refers to periods of one year or
less.  "Savings" refers to capacity release savings, as well as net revenues
from off-system sales, if any.  The imputed level of savings will be $1,100,000
per year for the period beginning April 1, 2001 and extending through June 30,
2002.  The level will then be $500,000 per year for the period beginning July 1,
2002 and extending through March 31, 2004;

     (10) RG&E will implement a Low-Income Program for customers who require
assistance.  The Low-Income Program will be funded through a surcharge in
customer bills; and

     (11) RG&E will implement a Service Quality Performance Program to be
effective as of January 1, 2001 through at least June 30, 2002.  This Program
establishes performance targets for six specific measures of service and
provides for a maximum overall penalty of 42 basis points of gas return on
equity for failure to meet the minimum levels specified.

     GAS RETAIL ACCESS PROGRAM.  On December 1, 2000, RG&E implemented the
single-retailer system for small volume gas customers, following the approval of
a tariff filing with the PSC.  Under the June 2000 Gas Settlement discussed
above,  RG&E is permitted to recover the difference between the backout credit
paid marketers ($3.75 per customer per month) and RG&E's short-run avoided costs
associated with the migration of gas sales customers to retail access under the
single retailer system.  For purposes of the June 2000 Gas Settlement, this
assumed difference was set at $2.55 per customer per month. Both the backout
credit and the assumed difference are to remain in effect at these levels over
the term of the Settlement (generally through June 30, 2002), subject to
possible further negotiations in the event of a particularly rapid migration of
customers.

     As of December 31, 2000, seventeen energy service companies, including
Energetix, are qualified by RG&E to serve retail gas customers under RG&E's Gas
Retail Access Program.

     RG&E attempts to mitigate its risks of energy marketer defaults by
requiring security deposits as permitted by PSC Transportation Gas Customer
tariffs.

     PSC ELECTRIC 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 (Electric Settlement).  The Electric Settlement sets the
framework for the introduction and development of open competition in the
electric energy marketplace and lasts through June 30, 2002.  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 Electric Settlement sets RG&E's electric rates for each year during its
five-year term. Over the five-year term of the Electric 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.

     In the event that RG&E earns a return on common equity in its regulated
electric business in excess of an effective rate of 11.50 percent over the
entire five-year term of the Electric Settlement, 50 percent of such excess will
be used to write down deferred costs accumulated during the term of the Electric
Settlement.
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                                       29

Any remaining amounts of this 50 percent shall be retained as earnings by RG&E.
The other 50 percent shall be used to write down accumulated deferrals or
investment in electric plant or regulatory assets (the Return on Equity Test).
(See the discussion under "Results of Operations - 2000 Compared to 1999"
regarding Management's estimate of return on equity reserves established in
accordance with the terms of the Electric Settlement.) 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
RG&E or any other party to the Electric Settlement would have the right to
petition the PSC for review of the Electric Settlement and appropriate remedial
action.

     The Electric Settlement requires unregulated energy retailing operations to
be structurally separate from the regulated utility functions.  Although the
Electric Settlement provides incentives for the sale of generating assets, it
does not require RG&E to divest generating or other assets or to write off
stranded costs.

     RG&E believes that the Electric Settlement has not adversely affected its
eligibility to continue to apply certain accounting rules applicable to
regulated industries. In particular, RG&E believes it continues 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.  The Electric Settlement provides RG&E a reasonable opportunity to
recover substantially all of its prudently incurred costs, except certain
operational costs associated with non-nuclear generation.

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

     ENERGY CHOICE. On July 1, 1998, RG&E officially began implementation of its
full-scale electric retail access Energy Choice program.  As of July 1, 2000,
RG&E entered its third year of this program. There are five basic components of
the sale of energy as follows:

     (1) the sale of electricity which is the amount of energy actually used by
the consumer;

     (2) the sale of capacity which is the ability, through generating
facilities or otherwise, to provide electricity when it is needed;

     (3) the sale of transmission services, which is the physical transportation
of electricity to RG&E's distribution system;

     (4) the sale of distribution services, which is the physical delivery of
electricity to the consumer over RG&E's distribution system; and

     (5) retail services such as billing and metering.

Historically, RG&E has sold all five components bundled together for a fixed
rate approved by the PSC.

     The implementation of Energy Choice included a four year phase-in process
to allow RG&E and other parties to manage the transition to electric competition
in an orderly fashion.  During the first year of the program, participation in
Energy Choice was limited to no more than 10 percent of RG&E's total annual
retail electric kilowatt-hour sales (670,000 annualized megawatt-hours).
Essentially, until this 10 percent limit was achieved, RG&E's electric retail
customers could seek out or be approached by alternative energy service
companies for electricity to be resold and then delivered over RG&E's
distribution system.  By February 1, 1999, only six months into the Energy
Choice program, this 10 percent limit was achieved by qualified competitive
energy service companies in RG&E's service territory. For the second year of the
program, beginning July 1, 1999, this limit increased from 10 percent to
approximately 20 percent.  As of July 1, 2000, beginning the third year of the
program, this limit increased to 30 percent. As of December 31, 2000,
approximately 24 percent of total RG&E sales had shifted to competitive energy
service companies, including the Company's unregulated subsidiary Energetix.
Beginning July 1, 2001, all retail customers will be eligible to purchase
energy, capacity and retailing services from competitive energy service
companies. Throughout the
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                                       30

term of the Electric 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 such service.

     Energy Choice adopted the single-retailer model for the relationship
between RG&E 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.  Except for providing emergency
services, satisfying requests for distribution services, and scheduling outages,
which remain RG&E's responsibility, the retail customer's primary point of
contact for billing questions, technical advice and other energy-related needs,
is with the customer's 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).

     RG&E attempts to mitigate its risks of energy marketer defaults by
requiring security deposits as permitted by PSC Electric Distribution Customer
tariffs.

     As of December 31 , 2000, seven energy service companies, including
Energetix, are qualified by RG&E to serve retail customers under Energy Choice.

     During the initial Energy-Only stage of the Energy Choice program, which
began on July 1, 1998 and ended on November 18, 1999, energy service companies
were able to choose their own sources of energy supply, while RG&E continued to
provide to them, through its bundled distribution rates, the generating capacity
(installed reserve) needed to serve their retail customers. In addition, during
the Energy-Only stage, energy service companies had the option of purchasing
"full-requirements" (i.e., delivery services plus energy) from RG&E.

     During the initial Energy-Only stage of the retail access program, RG&E's
distribution rate was set by deducting approximately 2.31 cents per kilowatt-
hour from its full service (bundled) rates.  The 2.31 cents per kilowatt-hour
was comprised of 1.91 cents per kilowatt-hour (an estimate of the wholesale
market price of electricity) plus 0.40 cents per kilowatt-hour for RG&E's
avoided cost of retailing services.

     During the Energy and Capacity stage, which began on November 18, 1999,
RG&E's distribution rates equaled the bundled rate less RG&E's cost of both the
electric commodity and its non-nuclear generating capacity.  Throughout this
stage of the program, up until June 30, 2000, RG&E's distribution rates were set
by deducting 3.07 cents per kilowatt-hour from its full service rates.  The 3.07
cents per kilowatt-hour is comprised of 2.67 cents per kilowatt-hour (an
estimate of the wholesale market price of electric energy and capacity) plus
0.40 cents per kilowatt-hour for its avoided cost of retailing services.
Beginning July 1, 2000, RG&E's distribution rates were set by deducting 3.08
cents per kilowatt-hour from its full service rates.  The 3.08 cents per
kilowatt-hour is comprised of 2.68 cents per kilowatt-hour for energy and
capacity plus 0.40 cents per kilowatt-hour for its avoided cost of retailing
services.  This change in the distribution rates, set by deducting 3.07 cents
per kilowatt-hour and then 3.08 cents per kilowatt-hour, is a result of pre-
determined changes in average gross receipts taxes.

     The Energy and Capacity stage, the second stage of the phase-in, began with
the implementation of the New York Independent System Operator on November 18,
1999 (see discussion under "New York Independent System Operator").  The
responsibility for purchasing not only energy, but also capacity, was to have
shifted to the energy service companies.  However, the PSC and FERC had also
approved a request by RG&E to extend "full-requirements" availability to energy
service companies through the current winter capability period (from October 31,
2000 through April 30, 2001).  As of December 31, 2000, all energy service
companies serving customers under retail access have opted to continue
purchasing "full requirements" through the current winter capability period.

     Through April 30, 2001, energy service companies will have the option to
serve a portion or all of their load from the competitive wholesale market, but
once they make this change, they will not be able to return
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                                       31

this load to "full requirements". Once RG&E no longer provides "full
requirements" to the energy service companies, they will assume responsibility
for obtaining their own supplies. RG&E will experience a revenue decrease when
it no longer collects the rates described above for energy and capacity. This
will be offset to some extent by decreased costs resulting from no longer
acquiring energy and capacity for the energy service companies. The extent of
this offset will be determined by market prices.

     In December 1999, two petitions were filed with the PSC, one by an electric
utility operating in New York State and the other jointly by five energy
marketers and consultants, calling upon the PSC to examine RG&E's retail access
program and to order certain changes in the program.  In particular, these
petitioners objected to the single-retailer form of RG&E's program, under which
the retail marketer assumes responsibility for most retail service functions.
They claim that the "backout credit" (the amount by which RG&E's rates for
retail electric service are reduced to derive the rates charged for the delivery
service provided by RG&E to marketers) is too low, that it affords insufficient
prospect of profitable operation by marketers, and that it should be increased.
They further assert that the phased schedule for implementation of the program,
under which increasing percentages of customers in RG&E's service area are
eligible to obtain competitive service during the term of the Electric
Settlement, is too slow and should be significantly accelerated.  On February
28, 2000 RG&E filed with the PSC its reply to both petitions.  As set forth in
that reply, RG&E believes that its single-retailer program offers unique
opportunities for marketers, that its retail backout credit (in conjunction with
RG&E's rate for wholesale power sales to marketers) affords a sound basis for
competitive service, and that its implementation schedule is reasonable and
appropriate; moreover, each of these essential elements of the retail access
program is expressly established by the Electric Settlement.  RG&E believes that
the program fully and fairly advances the goals of increased competition for
energy services and is in full compliance with the Electric Settlement.
Nevertheless, it is not possible at this time to predict with assurance whether
or not, in response to the petitions, the PSC might require that the program be
changed in some manner.

     The PSC is conducting proceedings that are intended to bring more
administrative consistency among New York State utilities and potentially offer
additional services for energy service companies to provide. These include an
on-going national effort regarding uniform business practices, and proceedings
regarding standardized billing (single billing options), provider of last
resort, electronic data interchange, and competitive metering.  RG&E continues
to assess the scope and impact of such changes on its operations as retail
access continues to evolve.

     NINE MILE NUCLEAR PLANTS.   On June 24, 1999, Niagara Mohawk and New York
State Electric and Gas Corporation (NYSEG) announced their intention to sell
their interests in the Nine Mile One and Nine Mile Two nuclear plants to AmerGen
Energy Company, L.L.C. (AmerGen), a joint venture of PECO Energy and  British
Energy. Niagara Mohawk owns 41 percent of Nine Mile Two and 100 percent of Nine
Mile One and NYSEG owns 18 percent of Nine Mile Two.

     RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal but RG&E has a right of first refusal to buy the interests of the other
owners of Nine Mile Two on terms at least as favorable as those offered.  RG&E
exercised its right of first refusal and broadened it to include Nine Mile One
with which Nine Mile Two was paired in the proposal. However, in the ensuing
discussions with the PSC staff it became clear that the transaction on the terms
proposed would not be approved by the PSC.

     On April 25, 2000, the PSC issued an order that allowed NYSEG and Niagara
Mohawk to withdraw their petition to sell their interests in the Nine Mile
plants to AmerGen. The order concluded that Nine Mile's market value is "greatly
in excess of the original AmerGen purchase price" and that multiple entities are
now interested in the Nine Mile plants.  The order also concluded that
"...failure for the utilities to determine the market value of the Nine Mile
facilities at this time, through an open process, would raise serious prudence
questions."  With respect to stranded costs, the PSC order indicates that
stranded costs cannot be finally quantified "until the disposition of the plants
by the utilities is decided."  The PSC's order does, however, observe that (1) a
sale would be considered within its policy of separating generation from
transmission and distribution, (2) a sale at current market values would
constitute appropriate mitigation of stranded costs and
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                                       32

(3) ratemaking treatment of a sale would be resolved in accordance with each
company's competitive opportunities/restructuring order taking into account
reduced risk and corollary divestiture effects.

     After issuance of the PSC's order, RG&E decided to determine the market
value of its interest in Nine Mile Two.  On June 1, 2000, RG&E issued a press
release announcing an auction process by RG&E, Central Hudson Gas & Electric
Corporation (Central Hudson), NYSEG and Niagara Mohawk in connection with their
ownership interests in Nine Mile Two and Niagara Mohawk's interest in Nine Mile
One.

     On December 11, 2000, RG&E, Niagara Mohawk, Central Hudson and NYSEG
entered into an agreement to sell their ownership interests in Nine Mile Two to
Constellation Nuclear, L.L.C. (Constellation Nuclear).  Constellation Nuclear
was the successful bidder in a competitive auction conducted for the plants. The
Long Island Power Authority, an 18 percent owner of Nine Mile Two, is not
participating in the sale.

     The purchase price for RG&E's 14% ownership interest in Nine Mile Two is
$99.2 million, $49.6 million of which will be paid in cash at closing and $49.6
million of which will be paid in five equal annual principal installments plus
interest at a rate of 11% pursuant to a five year promissory note.  Principal
and interest payments under the promissory note will total approximately $66
million unless the note is pre-paid. The purchase price is subject to adjustment
at the time of closing. The aggregate purchase price for 82 percent of Nine Mile
Two is $581 million. The aggregate purchase price, including cash payments at
closing and payments of principal and interest to all of the sellers under the
promissory notes, is $676.6 million for 82 percent of Nine Mile Two.

     Also, part of the transaction is a power purchase agreement whereby
Constellation Nuclear has agreed to sell 90 percent of RG&E's 14 percent
interest in Nine Mile Two's actual output back to RG&E for approximately 10
years at an average price of less than $35 per MWh over the term of the power
purchase agreement.

     After the completion of the power purchase agreement, a 10-year revenue
sharing agreement begins.  The revenue sharing agreement will provide RG&E with
a hedge against electricity price increases and could provide RG&E additional
revenue through 2021.  The revenue sharing agreement provides that, to the
extent market prices (for energy and capacity) exceed certain strike prices, 14%
of the market value of Nine Mile Two's actual output (capped at 160 MW) above
the strike price will be shared 80% to RG&E and 20% to Constellation Nuclear.
When actual market prices are lower than strike prices, such negative amounts
will be carried forward as credits against subsequent payments.

     At closing, the sellers' pre-existing decommissioning funds will be
transferred to Constellation Nuclear and Constellation Nuclear will assume the
sellers' obligation to decommission Nine Mile Two.

     The Nuclear Regulatory Commission (NRC), FERC, PSC and other regulatory
bodies must approve the sale. Receipt of such regulatory approvals (including,
without limitation, the PSC's authorization to establish a regulatory asset and
return thereon for the full amount of RG&E's unamortized plant and capital costs
of Nine Mile Two remaining after the closing of the sale), in form and substance
reasonably satisfactory to RG&E, is a condition to RG&E's obligation to close
the transaction. The transaction is targeted to close in mid-2001. At December
31, 2000, the net book value of RG&E's 14 percent interest in the Nine Mile Two
generating facility was approximately $360 million.  RG&E also had investments
in fuel of approximately $8.9 million, transmission and distribution facilities
of $3.4 million and construction work in progress of $4.6 million.

     On January 31, 2001, RG&E, together with Niagara Mohawk, Central Hudson,
NYSEG and Constellation Nuclear filed a Section 70 petition with the PSC.  The
petition requests that the PSC authorize the sellers to transfer to
Constellation Nuclear their interests in Nine Mile Two in accordance with the
rate treatment proposed.  For RG&E, the rate treatment proposed includes full
recovery of the regulatory asset remaining after the sale.

     Prior to the events discussed above, the PSC had initiated a proceeding to
examine the appropriate role of the nuclear power plants in the State in
developing a competitive market for electricity.  Collaborative efforts of the
parties led to the development of a report on the subject which the PSC
discussed at a July 1999
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                                       33

session without issuing an order. No significant activity has since occurred in
the proceeding and RG&E cannot predict what the PSC may do to continue or
conclude it. Since all nuclear plants in the State either have now been sold or
are under contract to be sold, except for RG&E's Ginna Plant, the PSC could
regard the proceeding as moot.

     FOSSIL UNITS STATUS. In 1999, RG&E ceased operations at and retired its
Beebee Station (80 Megawatt) coal-fueled generating facility. The retirement of
Beebee Station did not have a material effect on the financial position or
results of operations of RGS or RG&E. The Electric Settlement provides that all
prudently incurred incremental costs associated with the retirement and
decommissioning of the plant are recoverable through RG&E's distribution access
rates.

     In early June 1999 the Allegany Station, a combined-cycle unit fueled by
natural gas, began generating electricity.  The 63 megawatt capacity unit is
expected to generate electricity during the peak demand summer months and when
the economics of producing electricity for sale are favorable.  The plant is
being operated and maintained for RG&E by Bell Harbert Energy L.L.C.  Allegany
Station, which was built as a co-generation facility in the early 1990s, was
obtained by RG&E as part of a legal settlement in December 1998 with General
Electric Capital Corporation, Kamine/Besicorp Allegany L.P. (Kamine) and other
Kamine affiliates.

     Oswego Unit Sale. On October 22, 1999, RG&E and Niagara Mohawk sold their
respective 12% and 88% interests in the Oswego Generation Facility to Oswego
Harbor Power L.L.C., a wholly-owned affiliate of NRG Energy, Inc. for
approximately $91 million.  Additionally, the buyer agreed to assume RG&E's
obligations under a June 8, 1998 transmission services agreement as it pertains
to the Oswego Generation Facility.  This assumption represents a net present
value of approximately $25 million, which was deducted from RG&E's approximately
$11 million share of the sale proceeds.  Accordingly, RG&E was required to make
a net payment of approximately $14 million in connection with the sale. Under
the terms of the Electric Settlement, RG&E is permitted to recover through its
distribution rates any losses and related costs on a sale of generation.
Pursuant to an October 21, 1999 PSC order, RG&E was required to file with the
PSC a detailed calculation of its net book loss after tax impacts. RG&E made
this filing with the PSC on December 21, 1999. Including the impact of the $25
million relating to the transmission services agreement, RG&E's net loss and
associated costs are approximately $79 million.  In the filing, RG&E indicated
that $2.2 million of depreciation charges and $4.3 million of transmission
contract payments, currently included in rates, will be used to amortize the net
loss during the remaining term of the Electric Settlement.

     At the time of the sale of the Oswego Generating Facility, RG&E and Niagara
Mohawk also entered into a contract for the sale of RG&E's interest in a 345
kilovolt substation at the Oswego site to Niagara Mohawk for $1.1 million.
Approval of the transaction was received from both the PSC and FERC and the sale
is currently pending.  The net proceeds will be used to offset the loss which
has been deferred as an regulatory asset.

     NEW YORK INDEPENDENT SYSTEM OPERATOR.  In November 1999 following FERC
approval, the New York State Independent System Operator (NYISO) sought to
implement a competitive wholesale market for the sale, purchase and transmission
of electricity and ancillary services in New York State. NYISO tariffs provide
market-based rates for energy, ancillary services, and installed capacity sold
through the NYISO. The NYISO and the New York State Reliability Council were
formed to restructure the New York Power Pool in response to FERC Order 888.

  In early 2000, the NYISO's total cost of providing operating reserves on an
hourly basis exceeded the cost that would be expected in a workable competitive
marketplace.  During the first quarter of 2000, RG&E, in addition to other New
York State public utilities and several load-serving entities, experienced
rising prices to maintain operating reserves within the NYISO system. As a
result of, among other things, the implementation of bidding restrictions that
limit reserve prices, as discussed in the following two paragraphs, the average
cost per MWH for operating reserves in the third and fourth quarters decreased
to $.65 and $.38, respectively.

     On March 27, 2000, the NYISO filed with FERC for immediate authority to
suspend the use of market-based bids in the New York markets for operating
reserves. On April 7, 2000, RG&E also filed a complaint
<PAGE>

                                       34

with FERC against the NYISO. RG&E sought corrective re-calculation of operating
reserve prices for prior periods and prospective relief from injuries resulting
from the NYISO's operating reserves market. Niagara Mohawk and NYSEG filed
similar complaints with FERC against the NYISO. On May 31, 2000 FERC issued an
order accepting the NYISO's request and capped prices for the 10-minute non-
spinning reserve market at $2.52/MWH. In response to various complaints, FERC
directed the NYISO to permit self-supply of operating reserves and file a plan
to correct software problems inhibiting self supply by September 1, 2000.
However, FERC denied the requests by RG&E and Niagara Mohawk for retroactive
rate relief. On June 30, 2000, RG&E filed a request for rehearing seeking, in
part, retroactive rate relief for operating reserve overpayments. This request
is currently pending with FERC.

     As directed by FERC, on September 1, 2000 the NYISO made a comprehensive
compliance filing addressing a number of compliance issues, including operating
reserves issues.  Because the filing did not, in violation of FERC orders,
permit self-supply of operating reserves, RG&E filed a protest of the compliance
filing.  RG&E also protested a new proposal made by the NYISO to pay suppliers
of operating reserves prices based on whether the supplier is located in the
west, east or on Long Island, while charging purchasers of operating reserves a
single, state-wide rate.  On November 8, 2000, FERC issued an order extending
the existing bid cap of $2.52/MWH (plus opportunity costs) until such time as
FERC determines that the non-spinning reserve markets are demonstrated to be
workably competitive.  FERC again stressed the requirement that the NYISO permit
self-supply of operating reserves.  FERC suspended the proposal on pricing of
operating reserves based on location for the maximum 5 month period.  FERC
established a technical conference which was held on January 22 and 23, 2001, to
deal with market flaws and market performance in the NYISO, including operating
reserves issues.

     At the present time, RG&E cannot predict what effects, if any, action
ultimately taken by FERC on these issues will have on future operations or the
financial condition of RGS or RG&E.

     COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. With PSC
approval, RG&E has deferred certain costs rather than recognize them on its
statement of income 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 and RG&E's Balance Sheet and a discussion and
summary of such regulatory assets is presented in Note 3 to Financial
Statements.

     In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. Estimates of
strandable assets are highly sensitive to the competitive wholesale market price
assumed in the estimation. In a competitive natural gas market, strandable
assets would arise where customers migrate away from dependence on RG&E for full
service, leaving RG&E with surplus pipeline and storage capacity, as well as
natural gas supplies under contract.  A discussion of strandable assets is
presented in Note 3 to Financial Statements.

     As of December 31, 2000, RG&E believed that its regulatory assets are
probable of recovery.  The Electric Settlement does not impair the opportunity
of RG&E to recover its investment in these assets.  However, the PSC initiated a
proceeding in 1998 to address issues surrounding nuclear generation (see Nine
Mile Nuclear Plants).  The ultimate determination in this proceeding or any
proceeding to consider RG&E's proposed sale of Nine Mile Two as discussed under
that heading could have an impact on strandable assets and the recovery of
nuclear costs.

RATES AND REGULATORY MATTERS

     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 addressed 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
<PAGE>

                                       35

that are common to both the gas and the electric industries. The PSC has
encouraged settlement negotiations with each gas utility pertaining to the
transition to a fully competitive gas market. RG&E, the PSC Staff and other
interested parties engaged in settlement discussions in response to the specific
requirements of the Gas Policy Statement. In January 2001, RG&E reached
agreement with PSC Staff and other parties on a comprehensive rate and
restructuring proposal for its natural gas business, as contemplated in the
PSC's Gas Policy Statement (See "Gas Retail Access Settlements").

     PSC ASSIGNMENT OF GAS CAPACITY.  Under a March 1996 Order, the PSC
permitted RG&E and other gas distribution companies to assign to marketers, as
necessary,  to serve their customers the pipeline and storage capacity held by
RG&E.  In its Gas Policy Statement, the PSC ordered that the 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.
On March 24, 1999, the PSC issued an Order Concerning Assignment of Capacity for
all gas utilities in the State, generally requiring the removal of restrictions
on customer migration from utility service to service from marketers.  RG&E has
complied with the PSC's directives.  The Retail Access Capacity Program and the
Capacity Incentive Program contained in the Gas Rates and Restructuring Proposal
(see "Gas Retail Access Settlements") will, if adopted by the PSC, help to
mitigate potential stranded costs resulting from migration of customers to
marketers.

     FERC GAS MARKET PROPOSALS. On February 9, 2000, FERC issued Order No. 637,
its final rule addressing "Regulation of Short-Term Natural Gas Transportation
Services"  and "Regulation of Interstate Natural Gas Transportation Services" .
On June 5, 2000 FERC issued Order No. 637-A providing clarification and
additional guidance. On July 26, 2000 FERC issued Order No. 637-B upholding
Orders No. 637 and No. 637-A.  Order No. 637 as clarified revises FERC's
regulations to improve the efficiency of the gas transportation market and to
provide captive customers with the opportunity to reduce their cost of holding
long-term pipeline capacity. Specifically, Order No. 637 as clarified:

     (1) waives the price ceiling for released capacity of less than one year
until September 30, 2002;

     (2) permits pipelines to propose peak, off-peak and term differentiated
rates, provided that they still satisfy the revenue and cost constraints of
traditional rate-making, and excess revenues are split with firm customers;

     (3) revises FERC's regulations on scheduling procedures, capacity
segmentation and pipeline penalties;

     (4) states that the right of first refusal will apply in the future to
contracts for 12 consecutive months or more of service at maximum rates; and

     (5) amends and supplements reporting requirements to require interstate
pipelines to report additional information on transactions, operationally
available capacity, and an expanded index of customers.

     Order No. 637 as clarified requires each pipeline to make a compliance
filing. All of the pipelines' initial compliance filings were submitted to FERC
by August 15, 2000.  FERC has established technical and settlement conference
procedures for many of the pipelines, including those on which RG&E holds
transportation capacity. FERC staff has indicated at the respective pipeline
settlement and technical conferences that no action on various pipeline
proposals  will be taken prior to April 2001, after the heating season has
ended.

     Neither RGS nor RG&E can predict what effects, if any, FERC's initiatives
and the related pipeline tariff changes will have on future operations or the
financial condition of RGS or RG&E.

     FERC ELECTRIC RESTRUCTURING ORDER NO. 2000.   On December 15, 1999, FERC
adopted Order No. 2000 (the Rule), a significant action regarding electric
industry restructuring which calls for transmission owners to join regional
transmission organizations (RTOs). The RTOs will serve as umbrella organizations
that will place all public utility transmission facilities in a region under
common control.  The Rule
<PAGE>
                                        36

required all public utilities that own, operate or control interstate
transmission facilities to file by October 15, 2000 (or, for public utilities,
like RG&E, already participating in an ISO, by January 15, 2001), a proposal for
an RTO, or, alternatively, a description of any efforts made by the utility to
participate in an RTO.

     On January 16, 2001, the NYISO and all the New York State public utilities
made a joint filing with FERC regarding the establishment of an RTO.  In the
consensus filing, the parties submit that the NYISO meets the general
requirements of an RTO, and the NYISO agrees to make certain enhancements of its
structure and programs to benefit the markets.  Minor modifications are proposed
to the governance structure and transmission planning, and the NYISO agrees to
coordinate more closely with other RTOs.

     RG&E cannot predict what effect, if any, the ultimate ruling by FERC will
have on future operations or on the financial condition of the Company.

     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
Electric Settlement, 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 regulated electric sales to customers are made under long-term
contracts, primarily to large industrial customers.  These contracts represent
approximately 48 percent of RG&E's revenues from its commercial and industrial
customers.

LIQUIDITY AND CAPITAL RESOURCES

     During 1998, 1999 and 2000, RGS's and RG&E's cash flow from operations (see
Statements of Cash Flows) provided the funds for utility plant construction
expenditures, the payment of dividends, the purchase of treasury stock, the
retirement of long-term debt and, in 1999, the retirement of short-term debt. In
addition, RG&E completed long-term financings in 1998 and 1999.  Compared to
1999, cash used for investing activities in 2000 was higher due to increased net
additions to utility plant and acquisitions by Griffith during the year.  Cash
flow from financing activities for 2000 reflect higher proceeds from short-term
borrowings, partially offset by the retirement of long-term debt.  Capital
requirements of the Company during 2001 are anticipated to be satisfied from the
combination of internally generated funds, short-term credit arrangements, and
possibly some external long-term financing. In addition, completion of the Nine
Mile Two sale would also provide additional funds as previously discussed under
the heading  Nine Mile Nuclear Plants.  RG&E may also refinance long-term
securities obligations during 2001 depending on prevailing financial market
conditions.

     CAPITAL AND OTHER REQUIREMENTS.   RGS's and RG&E's capital requirements
relate primarily to expenditures for energy delivery, including electric
transmission and distribution facilities and gas mains and services, as well as
for nuclear fuel, electric production, and the repayment of existing debt. RG&E
has no plans to install additional baseload generation.

     1998 Labor Day Storm.  On September 7, 1998, a severe lightning and
windstorm struck RG&E's franchise area.  The storm damaged RG&E's electrical
system at several hundred different locations. Several counties within RG&E's
franchise area were declared State and federal disaster areas.  RG&E has
deferred approximately $9.3 million of costs and carrying charges associated
with this storm.  Under the Electric Settlement, if incremental costs resulting
from a "catastrophic event" exceed $2.5 million, RG&E is entitled to defer the
entire amount of such costs for future recovery.  RG&E submitted a petition to
the PSC for deferral of costs associated with this storm and this petition is
currently pending.

     Settlement with Co-generator.   In May 1998, RG&E 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 Global Settlement
Agreement became effective. Under the terms of the Global Settlement Agreement,
a Power Purchase Agreement was terminated in consideration of payment by RG&E of
$168 million over 16 years, without interest, with an initial payment of $10
million. Also, under the terms of the Global Settlement
<PAGE>

                                       37

Agreement, RG&E paid an additional $15 million for the purchase of the Kamine
generation facility. In June 1999, the plant began generating electricity (see
"Fossil Units Status"). RG&E does not expect the terms of the Global Settlement
Agreement to have any material effect on its earnings or the earnings of RGS.
Pursuant to the PSC order approving the terms of the Global Settlement
Agreement, regulatory assets have been established by RG&E to account for the
initial payment, the facility purchase and future payments. RG&E has no other
long-term obligations to purchase energy from co-generation facilities.

     Capital Requirements - Summary.  Capital requirements for the Company over
the three-year period 1998 to 2000 and the current estimate of capital
requirements through 2003 are summarized in the Capital Requirements table.
RG&E's portion of total construction requirements as presented in the Capital
Requirements table for 2001, 2002, and 2003 are $161 million, $161 million, and
$142 million, respectively.

     The Company's capital expenditures program is under continuous review and
could be revised for many reasons.  Also, RG&E may consider, as conditions
warrant, the redemption or refinancing of certain outstanding long-term
securities.

Capital Requirements - RGS

<TABLE>
<CAPTION>
                                              Actual                     Projected
                                       1998    1999   2000           2001   2002   2003
Type of Facilities                                   (Millions of Dollars)
<S>                                   <C>    <C>    <C>            <C>    <C>    <C>
Electric Property
 Production                           $  16   $  14  $  12          $  17  $  23  $ 14
 Energy Delivery                         41      42     63             79     77    69
                                      -----   -----  -----          -----  -----  ----
  Subtotal                               57      56     75             96    100    83
 Nuclear Fuel                            14      14     22              7     19    16
                                      -----   -----  -----          -----  -----  ----
  Total Electric                         71      70     97            103    119    99
Gas Property                             21      19     23             31     25    26
Common Property                          21      20     23             28     18    19
                                      -----   -----  -----          -----  -----  ----
  Total                                 113     109    143            162    162   144
Carrying Costs
 Allowance for Funds Used During
  Construction                            1       2      2              2      2     2
                                      -----   -----  -----          -----  -----  ----

 Total Construction Requirements        114     111    145            164    164   146
Securities Redemptions, Maturities
 and Sinking Fund Obligations*           66      10     30             --    100    80
                                      -----   -----  -----          -----  -----  ----
  Total Capital Requirements          $ 180   $ 121  $ 175          $ 164  $ 264  $226
                                      -----   -----  -----          -----  -----  ----
</TABLE>
* Excludes prospective refinancings.

     FINANCING. In December 2000, RG&E filed a shelf registration with the
Securities and Exchange Commission to issue up to $400 million of long-term debt
securities on terms to be determined at the time the securities are sold.  This
registration statement became effective in January 2001 and allows RG&E
financing flexibility regarding the timing of the issuance of debt.  Net
proceeds from any financings under this shelf registration may be used by RG&E
to finance a portion of its capital expenditures, to repay short-term debt or
maturing securities, to redeem or purchase outstanding preferred stock or debt
securities, or for general corporate purposes.

     RG&E generally utilizes its credit agreements and unsecured lines of credit
to meet any interim external financing needs prior to issuing long-term
securities.   For information with respect to RGS's and RG&E's short-term
borrowing arrangements and limitations, see Note 10 of the Notes to Financial
Statements.  As financial market conditions warrant, RG&E may also, from time to
time, redeem higher-cost senior securities.
<PAGE>

                                       38

     The number of outstanding shares of common stock of RG&E and RGS, as
applicable, increased by 23,466 shares in 1998 and 70,913 shares in 2000 as a
result of options that were actually exercised under the Company's Performance
Stock Option Plan.  These were the only shares of common stock issued in 1998
and 2000.  Neither RGS nor RG&E issued any additional shares of common stock in
1999.

     REDEMPTION OF SECURITIES. In addition to first mortgage bond maturities and
mandatory sinking fund obligations of $80 million over the past three years,
discretionary redemption of long-term securities totaled  $25.5 million in 1998.
There were no discretionary redemptions of long-term securities in 1999 or 2000.

     STOCK REPURCHASE PLAN.  In April 1998, the PSC approved a stock repurchase
plan for RG&E providing for the repurchase of common stock having an aggregate
market value not to exceed $145 million. RG&E began the repurchase program in
May 1998 and an aggregate of 4,379,300 shares of RG&E and RGS common stock have
been repurchased for approximately $117.2 million through December 31, 2000.
The average cost per share purchased during 2000 was $23.66.

     ENVIRONMENTAL ISSUES.  The production and delivery of energy are
necessarily accompanied by the release of by-products subject to environmental
controls.  RGS and RG&E have 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.

     RGS and RG&E have 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 RGS and RG&E do 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 RGS's and RG&E's environmental matters
can be found in Note 12 to Financial Statements.

     RISK MANAGEMENT.  RGS has established and enforces formal internal policies
regarding price, credit, and operating risk, which govern the risk practices of
all subsidiaries.  Recognizing the critical and increasing importance of risk
management, RGS established a formal risk management function within the
organization and continues to work with consultants and strategic partners to
further implement and integrate risk management practices throughout the
organization.

     The Company faces significant commodity price risk. Commodity price risk
relates to market fluctuations in the price of natural gas, electricity, and
other petroleum-related products used for resale.  Under its Electric
Settlement, RG&E's electric rates are capped at specified levels through June
30, 2002.  Owned electric generation and long-term supply contracts
significantly reduce RG&E's exposure to market fluctuations for procurement of
its electric supply.

     While owned generation provides the Company with a natural hedge against
electric price risk, it also subjects the Company to operating risk.  Operating
risk is managed through a combination of strict operating and maintenance
practices and the use of financial instruments.  In the event RG&E's generation
assets fail to perform as planned, generation insurance and purchased call
options reduce the Company's exposure to electric price spikes in the summer
months.  In addition, RG&E and Energetix rely on various derivative contracts to
cover supply positions and commitments, and to hedge energy price exposure.
Derivative contracts are entered into solely to optimize resources in
conjunction with serving customers.  Neither RGS nor any subsidiary enters into
speculative contracts for trading purposes.

     YEAR 2000 (Y2K) COMPUTER OPERATIONAL INFORMATION.  On and after January 1,
2000, the Company and RG&E have experienced normal operations of their computer
and microprocessor-based
<PAGE>

                                       39

devices with no loss or interruption of energy generation or delivery and no
operating difficulties of its mission critical internally developed applications
or critical devices. RG&E's two major electric generating plants, Ginna and
Russell Station, performed without any difficulties. Likewise, operations at the
Nine Mile Two electric power plant proceeded normally and there has been no
major impact on gas service. RG&E is not aware of any regional or statewide
power systems that failed to perform as the result of Y2K-related problems.

     RG&E funded its Y2K Project internally and incurred $9.5 million of
incremental costs associated with making the necessary modifications identified
to applications and devices. Neither RGS nor RG&E has deferred any major
corporate information technology projects due to this effort.

EARNINGS SUMMARY

     RGS.  RGS reported consolidated earnings of $2.61 per share in 2000
compared to $2.44 in 1999.  Higher wholesale electric sales, the recognition of
increased non-cash pension income, lower taxes, and the Company's share buyback
program positively affected 2000 results.  Having a negative effect on earnings
in 2000 were electric and gas rate reductions, increased purchased power
expenses arising from industry restructuring and generation plant availability,
cooler summer weather which mitigated electric air conditioning load sales, and
the establishment of reserves in accordance with the Return on Equity Test
pursuant to the Electric Settlement.

     RGS continues to grow its unregulated business through its subsidiary,
Energetix, which provides electric, natural gas, and petroleum-based energy
products and services throughout the Upstate New York region.  Energetix's
unconsolidated operating revenues were $484 million in 2000, of which sales from
Griffith and its subsidiaries contributed approximately $377 million.  These
Griffith revenues are included under "Other Revenues" on RGS's and, where
applicable, RG&E's Income Statements and, compared with a year earlier, reflect
an increase due to customer growth and increases in fuel oil prices. Energetix's
revenues for 2001 are expected to increase over 2000 levels as Energetix expands
its customer base and the operations from businesses recently acquired by
Griffith are reflected for an entire year; although no assurance may be given
that Energetix will achieve a net operating gain in 2001.

     RG&E.  Earnings for RG&E in 2000 were impacted by the same factors
discussed above for RGS except that discussions relating to Energetix and
Griffith are not applicable.  On August 2, 1999, RGS was formed and RG&E,
Energetix and RGS Development then became subsidiaries of RGS.  The RG&E Income
Statements reflect the consolidated operations of RG&E and its former
subsidiaries, Energetix and RGS Development prior to August 2, 1999.  Starting
August 2, 1999, the RG&E Income Statements reflect only the operating results of
RG&E.

RESULTS OF OPERATIONS

     The following financial review identifies the causes of significant changes
in the amounts of revenues and expenses for RGS (regulated and unregulated
business) and RG&E (regulated business), comparing 2000 to 1999 and 1999 to
1998.  The operating results of the regulated business reflect RG&E's electric
and gas sales and services and the operating results of the unregulated business
reflect Energetix's operations. Currently, the majority of RGS's operating
results reflect the operating results of RG&E and the factors that affect
operating results for RG&E are the significant factors that affect comparable
operating results for RGS, unless otherwise noted. The Notes to Financial
Statements contain additional information.

2000 COMPARED TO 1999
---------------------

      OPERATING REVENUES AND SALES. Increased electric revenues for RGS and RG&E
reflect higher revenues from the sale of energy to other electric utilities.
Revenues from these sales were up $48.2 million due to higher market prices,
coupled with an increase in energy kilowatt-hour sales. 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.
<PAGE>

                                       40

     Partially offsetting the favorable results of energy sales to other
utilities was a drop of $25.2 million in 2000 from a combination of electric
revenues from regulated retail electric sales and electric sales to energy
marketers reflecting a June 1999 unbilled electric revenue adjustment of $7.1
million  (see heading "1999 Compared to 1998"), unfavorable weather conditions
for air conditioning load during the summer of 2000 which was nearly 40% colder
than a year earlier based on cooling degree days, and electric base rate
reductions effective July 1, 1999 and July 1, 2000 (see "Energy Choice").

     A drop in commercial and industrial regulated electric unit sales reflects,
in part, the opening of the electric market under the terms of the Electric
Settlement.  RG&E, however, sells electric energy, as well as distribution
services, to qualified energy marketers in its franchise territory which has the
effect of increasing wholesale sales to energy marketers.  Included in RG&E's
electric operating revenues for 2000 are $99.5 million of revenues from electric
sales to energy marketers and $73.6 million of revenues from wholesale sales to
other utilities.

     Regulated gas margins (revenues less cost of purchased gas) were down
about $1.3 million in 2000.  Gas revenues in 2000 reflect a $1.4 million rate
reduction pursuant to the terms of the Gas Rates and Restructuring Proposal (see
"Competition").  In addition, the favorable effect of increased gas spaceheating
sales resulting, in part, from 5.6 percent cooler weather (based on heating
degree days) for the year was offset by the effects of a June 1999 unbilled gas
revenue adjustment of $6.1 million  (see heading "1999 Compared to 1998").

     Gas revenues from therms of gas sold and transported for the regulated
business were $31.3 million in 2000 compared with $21.2 million in 1999.  The
transportation of gas for customers who are able to purchase natural gas from
sources other than RG&E is an important component of RG&E's marketing mix.  In
2000, RG&E's small customer aggregate transportation market appeared as a
significant addition to RG&E's marketing mix.  Company facilities are used to
distribute this gas, which in total amounted to 24.0 million dekatherms in 2000
and 20.0 million dekatherms in 1999.  These purchases by eligible customers have
caused decreases in RG&E'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 gas and transporting it to RG&E's city gate, are the same as
the rates charged RG&E's retail gas service customers.  Moreover, under the
current regulatory environment, RG&E does not earn a return on the gas commodity
it acquires for distribution.  Gas supplies transported in this manner are not
included in RG&E's retail therm sales, depressing reported gas sales to such
retail customers.

      Seventy-eight percent of Energetix's total operating revenues in 2000 were
from the sale of fuel oil, propane and gasoline by Griffith (see discussion
under "Earnings Summary").  For heating oil and propane, 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.  Moreover, operations
from businesses acquired by Griffith have been reflected in Griffith's
operations since their acquisition (see "Unregulated Subsidiaries").

      OPERATING EXPENSES. Higher regulated electric fuel expenses reflect
increased purchased electricity costs driven by an increase in the cost per unit
purchased, hedging activities, the effect of decreased generation availability
from the Nine Mile Two nuclear plant primarily due to a scheduled refueling in
2000, and the absence of generation from the Oswego Generating Facility which
was closed in August 1999. The cost of purchased power may fluctuate depending
on the availability of electric generation from RG&E's facilities, the wholesale
energy market and the total availability of energy, and the availability of
transmission facilities. Since July 1996, Common Stock shareholders have assumed
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 RG&E's production cost.

     The cost of gas purchased for resale increased in 2000 driven mainly by the
rise in the commodity cost of gas.  RG&E's regulated gas tariffs include a
monthly gas adjustment clause which allows RG&E to recover pipeline and storage
capacity costs and the commodity cost of gas purchased for its customers.  On
<PAGE>

                                       41

an annual basis, RG&E reconciles the costs collected through the monthly gas
adjustment clause and the actual gas costs for the prior twelve months. As
stated above, RG&E does not earn a return on the gas capacity and commodity it
acquires for distribution to its customers.

     Unregulated fuel expenses on both RGS's and RG&E's Income Statements
reflect mainly the cost of purchased fuel for Griffith's operations.

     The increase in non-fuel operating expenses in 2000 for RGS and RG&E
includes an increase of $18.4 million for electric transmission and wheeling
charges related to the implementation of the NYISO (see discussion under "New
York Independent System Operator"), increased regulatory amortization associated
with the closing of Oswego Station ($5.2 million) and an accrual for site
remediation costs ($3.9 million).  These increases were offset by an $8.0
million drop in RG&E welfare expense associated with the performance of pension
assets (see Note 5 to Financial Statements), lower expenses in 2000 due to an
increase in 1999 ($7.1 million) of the RG&E reserve for uncollectible accounts,
the absence of Y2K expenses ($4.8 million), a one-time refund of NYISO start-up
costs ($4.5 million), and the reversal of a $3.0 million liability established
in 1999 for Nine Mile Two inventory losses due to the currently anticipated sale
of Nine Mile Two ($6.0 million).

      The financial results for 2000 resulted in the establishment of reserves
totaling $18.3 million in accordance with the terms of the Electric Settlement.
These reserves are comprised of a $16.3 million reserve based on the provisions
of the Return on Equity Test (as previously discussed under the heading Electric
Settlement) and a $2.0 million reserve for estimated property tax savings.
These reserves are reflected in non-fuel operating expenses.

     The variance in unregulated non-fuel operating expenses between 2000 and
1999 reflects primarily payroll, Griffith's fleet expenses, and incremental
operating expenses from the companies acquired by Griffith during 2000.

      Depreciation expense for both RGS and RG&E reflects a decrease in
regulated depreciation mainly associated with the retirement of RG&E generating
plant facilities in 1999 (see discussion under "Fossil Units Status").
Depreciation and amortization expense for unregulated operation increased $0.9
million in 2000 to $4.1 million due primarily to acquisitions.

     Local, State and other taxes for RGS and RG&E declined mainly as a result
of lower regulated revenues, a lower gross receipts tax, elimination of the
excess dividends tax effective January 1, 2000, and lower property taxes
resulting from the retirement of RG&E generating facilities in 1999 as mentioned
in the previous paragraph.  Partially offsetting the reduction in these taxes
was the imposition of new State income taxes that totaled $10.0 million in 2000
(see discussion under Note 1 to Financial Statements, "New York State Tax
Changes").

      The difference in income tax expense for RGS and RG&E is attributable
mainly to differences in pretax earnings, a reclassification of the State gross
receipts tax to State income tax and a true-up of both federal and State income
tax for a new State income tax effective January 1, 2000 (see discussion under
Note 1 to Financial Statements, "New York State Tax Changes").

      OTHER STATEMENT OF INCOME ITEMS. The change in non-operating income taxes
for both RGS and RG&E results from variances in non-operating earnings before
income taxes and a true-up of both federal and State income tax for the new
State income tax effective January 1, 2000 as discussed in the previous
paragraph.

      The change between 2000 and 1999 in RGS's and RG&E's Other Income and
Deductions, Other-net reflects reduced expenses in 2000 associated with RG&E
management performance awards ($4.8 million).  Compared with a year earlier, the
change in 2000 also reflects the effect of income in 1999 resulting primarily
from the gain on the disposal of property ($2.8 million).
<PAGE>

                                       42

     The increase in interest expense for both RGS and RG&E reflects the
interest on $100 million of first mortgage bonds issued in October 1999.  Higher
other interest expenses are due mainly to interest costs associated with RG&E's
annual gas supply reconciliation adjustments and interest on security deposits
provided by certain energy marketers.  Partially offsetting this increase in
interest expense was a reduction of RG&E interest expense on short-term debt.

1999 COMPARED TO 1998
---------------------

     OPERATING REVENUES AND SALES. Increased electric revenues in 1999 for RGS
and RG&E reflect increased demand for air conditioning usage resulting from
summer weather that was 25% warmer than during 1998 (on a cooling degree day
basis).  This increase in revenues was partially offset by a base rate reduction
pursuant to the terms of the Electric Settlement and lower regulated electric
sales due largely to RG&E's reduced capacity to sell power to other electric
utilities because of a refueling and in-service inspection outage at the Ginna
Plant and an unscheduled 30-day outage at Nine Mile Two.  Regulated sales and
revenues for 1999 compared to 1998 also reflect a one-time adjustment to reflect
a change in the estimating process for unbilled sales and revenues.  This
adjustment increased regulated electric revenues by $7.1 million and increased
regulated gas revenues by $6.1 million.  Regulated electric sales increased by
74,000 megawatt-hours and regulated gas sales were higher by 7,610,000 therms as
a result of this one-time adjustment. Included in RGS's electric operating
revenues for 1999 are $65.2 million of revenues from electric sales to energy
marketers and $25.3 million of revenues from wholesale sales to other utilities.
Revenues in 1999 from energy marketers were up $50.2 million compared with 1998
reflecting the opening of the electric marketplace and increased sales of
electricity and distribution services.  Revenues from the sales of electric
energy to other utilities dropped $3.7 million from 1998 due mainly to the
unavailability of RG&E's generating plants as discussed above, partially offset
by an increase in the average revenue per unit sold.

      Regulated gas margins (revenues less cost of purchased gas) were up over
$12 million reflecting 11 percent cooler weather (based on heating degree days)
for the year and the change in unbilled sales methodology discussed above.
Therms of gas sold and transported for the regulated business were up 10.7
percent in 1999.

     Approximately 78 percent of Energetix's total operating revenues in 1999
were from the sale of fuel oil, propane and gasoline by Griffith. Unregulated
sales reflect Griffith's operations since its acquisition by Energetix on August
2,1998 and the migration of electric and gas customers from the regulated to the
unregulated business.

     OPERATING EXPENSES. Higher regulated electric fuel expenses reflect
increased purchased electricity costs that were driven by a combination of lower
generation from the Ginna nuclear plant, hydro plants, and the closing of Beebee
Station on April 30, 1999, coupled with an increase in the cost per unit
purchased. Fuel expense for electric generation was down in 1999 reflecting
lower generation from RG&E's facilities.  Despite an increase in retail
regulated gas therm sales, gas purchased for resale expense declined in 1999
reflecting a lower average cost per unit due, in part, to a reduction in
pipeline costs.  Other fuel expense on both RGS's and RG&E's Income Statements
reflects mainly the cost of purchased fuel for Griffith's operations since its
acquisition by Energetix.

     The decrease in non-fuel operating expenses for RGS and RG&E includes a
$4.8 million drop in RG&E welfare expense from 1998 due mainly to the
performance of pension assets and a change in the discount rate used to value
the aggregate pension liability (see Note 5 to Financial Statements),
elimination in the first quarter of 1999 of property insurance and storm
reserves no longer required totaling $2.1 million, lower non-fuel net expenses
of $1.5 million associated with Ginna Plant refueling outages, a decrease of
$2.8 million relating to the completion in 1998 of the amortization of costs of
RG&E's billing system, insurance dividends of $1.8 million, and lower employee
performance incentive program costs of $1.1 million. Offsetting these declines
was a June 1999 increase in the allowance for uncollectible accounts of
approximately $7.1 million to better match RG&E's actual collection history, the
establishment in the fourth quarter of 1999 of a $3.0 million liability for
anticipated Nine Mile Two inventory losses due to a change in the expected
ownership of that facility, and increased Y2K costs of $6.0 million.
<PAGE>

                                       43


     The variance in unregulated non-fuel operating expenses reflects primarily
an increase in payroll expenses, other operating expenses for Griffith, and
general and administrative expenses.  The increase in these expenses reflects
twelve months of Griffith's operations in 1999 compared with only five months of
Griffith's operations in 1998 following its acquisition in August 1998.

     Depreciation expense for both RGS and RG&E in 1999 includes an incremental
one-time charge in the second quarter of approximately $2.1 million associated
with the closing of Beebee Station in April 1999. Depreciation and amortization
expense for unregulated operations in 1999 was $3.2 million, up $2.1 million
from 1998, due to the acquisition of Griffith.

     Local, State and other taxes for RGS and RG&E declined in 1999 compared to
1998 reflecting a New York State use tax audit refund, lower tax rates for State
and local revenue taxes, and lower assessments for property taxes.  These
results were partially offset by higher unbilled revenue taxes resulting from an
increase in unbilled revenues.  For unregulated operations, local, State and
other taxes in 1999 increased $2.9 million to $4.0 million compared to 1998 due
to the acquisition of Griffith.

     The difference in federal income tax expense for RGS and RG&E reflects pre-
tax earnings and, regarding RG&E, the settlement of RG&E audits in 1998 and a
$4.8 million increase in the 1999 tax reserve related to disputed tax issues.

     OTHER STATEMENT OF INCOME ITEMS. The change in non-operating federal income
taxes for both RGS and RG&E results from variances in non-operating earnings
before federal income taxes.

     The change between 1999 and 1998 in RGS's and RG&E's Other Income and
Deductions, Other-net reflects mainly the recognition of income ($17.4 million)
in 1998 due to the elimination of certain pension and other post-employment
benefit deferred credits and Nine Mile Two operating and maintenance expenses in
accordance with the Electric Settlement.  This variance in Other Income and
Deductions, Other-net was partially offset by non-cash carrying charges of $8.6
million related to deferral of Kamine (Allegany Station) facility costs in 1999
for the regulated business.  These carrying charges, which are primarily
associated with the deferred recovery of costs associated with the Kamine
settlement (see following paragraph), were allowed under the Electric Settlement
and the Kamine settlement. In addition, expenses associated with RG&E management
performance awards decreased $4.4 million in 1999 compared with 1998.

     The increase in RGS's interest charges reflects mainly an increase in long-
term debt outstanding, resulting mainly from the Kamine settlement, the
acquisition of Griffith by Energetix, and the issuance of $50 million of long
term debt by RG&E in December 1998. The increase in RG&E's interest charges was
impacted by the same factors except the debt incurred for the Griffith
acquisition.  Interest expense in 1999 for both RGS and RG&E also reflects the
interest on $100 million of first mortgage bonds issued in October 1999.

DIVIDEND POLICY

The ability of RGS to pay common stock dividends is governed by the ability of
RGS's subsidiaries to pay dividends to RGS.  Because RG&E is by far the largest
of RGS's subsidiaries, it is expected that for the foreseeable future the funds
required by RGS to enable it to pay dividends will be derived predominantly from
the dividends paid to RGS by RG&E.  In the future, dividends from subsidiaries
other than RG&E may also contribute to RGS's ability to pay dividends.  RG&E's
ability to make dividend payments to RGS will depend upon the availability of
retained earnings and the needs of its utility business.  RG&E's Certificate of
Incorporation provides for the payment of dividends on its common stock out of
the surplus net profits (retained earnings) of RG&E.  In addition, pursuant to
the PSC order approving the formation of RGS, RG&E may pay dividends to RGS of
no more than 100% of RG&E's net income calculated on a two-year rolling basis.
The calculation of net income for this purpose excludes non-cash charges to
income resulting from accounting changes or certain PSC required charges as well
as charges that may arise from significant unanticipated events.  This condition
does not apply to dividends that would be used to fund the remaining portion of
RG&E's $100 million authorization for unregulated operations (about $13 million
at December 31, 2000).
<PAGE>

                                       44


Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
          MARKET RISK

     RG&E 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.
RG&E 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 RG&E's long-term debt consists of long-term
Promissory Notes, the interest component of which resets on a periodic basis
reflecting current market conditions.  See "Note 6 - Long Term Debt". RG&E was
not participating in any derivative financial instruments to manage interest
rate risk as of December 31, 2000 or December 31, 1999.

     The commodity price risk relates to market fluctuations in the price of
natural gas, electricity, and other petroleum-related products used for resale.
Commodity purchases and electric generation are based on projected demand for
power generation and customer delivery of electricity, natural gas, and
petroleum products.  RG&E enters into forward contracts for natural gas to hedge
the effect of price increases and reduce volatility on gas purchased for resale.
Owned electric generation significantly reduces RG&E's exposure to market
fluctuations in electric prices.  RG&E does not hold open speculative positions
in any commodity for trading purposes.

     RG&E's exposure to market price fluctuations of the cost of natural gas is
further limited as the result of the Gas Cost Adjustment (GCA), a regulatory
mechanism that transfers substantially all gas commodity price risk to the
customer. Nonetheless, RG&E does hedge approximately 70% of its gas supply price
through the purchase of derivative contracts and the use of storage assets.  The
balance of RG&E's natural gas requirements is procured through spot market
purchases and is subject to market price fluctuations.

     Under the Electric Settlement, RG&E's electric rates are capped at
specified levels through June 30, 2002. As a result of owned generation and
long-term fixed rate supply contracts, RG&E is largely insulated from market
price fluctuations for procurement of its electric supply. In the event RG&E's
generation assets fail to perform as planned, RG&E is exposed to market price
fluctuations, and under the current rate agreement, fully absorbs this operating
risk.

     Energetix has entered into electric and natural gas purchase commitments
with numerous suppliers. These commitments support fixed price offerings to
retail electric and gas customers. Griffith is in the business of purchasing
various petroleum-related commodities for resale to its customers. To manage the
resulting market price risk, Griffith enters into various exchange-traded
futures and option contracts and over-the-counter contracts with third parties.
Through December 31, 2000, all hedge contracts have been 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. These contracts are closely monitored on a daily basis to
manage the price risk associated with inventory and future sales commitments. At
December 31, 2000 and 1999 Griffith's net deferred gains on open hedge contracts
were not significant.
<PAGE>

                                       45

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A.   FINANCIAL STATEMENTS

     The financial statements listed below are shown under Item 8 of this
     Report.

     Report of Independent Accountants.

     RGS  Consolidated Statement of Income for each of the three years ended
          December 31, 2000.
     RGS  Consolidated Statement of Retained Earnings for each of the three
          years ended December 31, 2000.
     RGS  Consolidated Balance Sheet at December 31, 2000 and 1999.
     RGS  Consolidated Statement of Cash Flows for each of the three years ended
          December 31, 2000.

     RG&E Statement of Income for each of the three years ended December 31,
          2000.
     RG&E Statement of Retained Earnings for each of the three years ended
          December 31, 2000.
     RG&E Balance Sheet at December 31, 2000 and 1999.
     RG&E Statement of Cash Flows for each of the three years ended December 31,
          2000.

     RGS and RG&E 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 of RGS and RG&E.

B.   SUPPLEMENTARY DATA

     Interim Financial Data.
<PAGE>

                                       46


                       Report of Independent Accountants


To the Shareholders and Board of Directors of
RGS Energy Group, Inc. and the
Shareholders and Board of Directors of
Rochester Gas and Electric Corporation


In our opinion, the accompanying 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 RGS Energy Group, Inc. and its
subsidiaries ("RGS") at December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 and the accompanying 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
("RG&E") at December 31, 2000 and 1999, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 2000
in conformity with accounting principles generally accepted in the United States
of America.  These financial statements are the responsibility of the RGS and
RG&E 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 auditing standards generally accepted in the United States of
America, 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 our opinion.



January 31, 2001
<PAGE>

                                       47

RGS Energy Group, Inc.
CONSOLIDATED STATEMENT OF INCOME


<TABLE>
<CAPTION>
(Thousands of Dollars)                Year Ended December 31,             2000              1999              1998
----------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>               <C>               <C>
Operating Revenues
   Electric                                                           $   731,006       $   702,751       $   687,622
   Gas                                                                    340,014           284,476           274,657
   Other                                                                  377,099           220,310            71,212
                                                                      -----------       -----------       -----------

      Total Operating Revenues                                          1,448,119         1,207,537         1,033,491

Operating Expenses
   Fuel Expenses
     Fuel for electric generation                                          48,851            49,297            53,954
     Purchased electricity                                                 85,858            54,337            27,024
     Gas purchased for resale                                             208,588           151,458           155,497
     Unregulated fuel expenses                                            340,306           189,465            59,490
                                                                      -----------       -----------       -----------

      Total Fuel Expenses                                                 683,603           444,557           295,965

Operating Revenues Less Fuel Expenses                                     764,516           762,980           737,526

Other Operating Expenses
   Operations and maintenance excluding fuel expenses                     313,721           297,890           301,625
   Unregulated operating and maintenance expenses excluding fuel           31,125            26,464            13,524
   Depreciation and amortization                                          116,184           118,695           116,102
   Taxes - local, state and other                                          94,576           114,639           117,973
   Income tax                                                              59,832            64,374            60,236
                                                                      -----------       -----------       -----------

      Total Other Operating Expenses                                      615,438           622,062           609,460

Operating Income                                                          149,078           140,918           128,066

Other (Income) and Deductions
Allowance for other funds used during construction                           (825)             (657)             (408)
Income tax                                                                  1,145            (1,255)            1,665
Other, net                                                                 (9,521)           (8,178)          (13,370)
                                                                      -----------       -----------       -----------

      Total Other (Income) and Deductions                                  (9,201)          (10,090)          (12,113)

Interest Charges
   Long term debt                                                          58,044            53,681            43,306
   Other, net                                                               5,995             4,798             3,388
   Allowance for borrowed funds used during construction                   (1,319)           (1,051)             (653)
                                                                      -----------       -----------       -----------

      Total Interest Charges                                               62,720            57,428            46,041
                                                                      -----------       -----------       -----------

Net Income                                                                 95,559            93,580            94,138

Preferred Stock Dividend Requirements                                       3,700             4,083             4,842

Net Income Applicable to Common Stock                                 $    91,859       $    89,497       $    89,296
                                                                      -----------       -----------       -----------

Earnings per Common Share - Basic                                     $      2.61       $      2.44       $      2.32
Earnings per Common Share - Diluted                                   $      2.60       $      2.44       $      2.31
                                                                      ===========       ===========       ===========

<CAPTION>

CONSOLIDATED STATEMENT OF RETAINED EARNINGS

(Thousands of Dollars)                Year Ended December 31,             2000              1999              1998
----------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>               <C>               <C>
Balance at Beginning of Period                                        $   153,186         $ 129,484         $ 109,313
Add
   Net Income Applicable to Common Stock                                   91,859            89,497            89,296
                                                                      -----------       -----------       -----------
      Total                                                               245,045           218,981           198,609
                                                                      -----------       -----------       -----------

Deduct
   Dividends declared on capital stock
     Common Stock                                                          62,989            65,594            68,927
   Other Adjustments                                                          510               201               198
                                                                      -----------       -----------       -----------
      Total                                                                63,499            65,795            69,125
                                                                      -----------       -----------       -----------

Balance at End of Period                                              $   181,546       $   153,186       $   129,484
                                                                      -----------       -----------       -----------
Cash Dividends Declared per Common Share                              $      1.80       $      1.80       $      1.80
                                                                      ===========       ===========       ===========
</TABLE>

The accompanying notes are an integral part of the financial statements.

<PAGE>

                                       48

RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>

(Thousands of Dollars)                                                At December 31,               2000                   1999
====================================================================================================================================
<S>                                                                   <C>                        <C>                    <C>
Assets
Utility Plant
Electric                                                                                         $ 2,467,289            $ 2,399,532
Gas                                                                                                  471,051                453,634
Common                                                                                               164,872                130,118
Nuclear                                                                                              292,588                270,447
                                                                                       ---------------------    -------------------
                                                                                                   3,395,800              3,253,731
Less:  Accumulated depreciation                                                                    1,750,493              1,636,955
       Nuclear fuel amortization                                                                     254,435                239,243
                                                                                       ---------------------    -------------------
                                                                                                   1,390,872              1,377,533
Construction work in progress                                                                        111,486                 95,862
       Net Utility Plant                                                               ---------------------    -------------------
                                                                                                   1,502,358              1,473,395
                                                                                       ---------------------    -------------------

Current Assets
Cash and cash equivalents                                                                             16,258                  8,288
Accounts receivable, net of allowance for doubtful accounts:
 2000 - $34,550; 1999 - $34,026                                                                      136,374                 90,239
Unbilled revenue receivable                                                                           71,120                 58,005
Fuels                                                                                                 46,868                 28,704
Materials and supplies                                                                                 8,187                  9,502
Prepayments                                                                                           26,268                 24,576
Other current assets                                                                                   2,292                    523
                                                                                       ---------------------    -------------------
       Total Current Assets                                                                          307,367                219,837
                                                                                       ---------------------    -------------------

Intangible Assets
Goodwill, net                                                                                         27,971                 13,894
Other intangible assets, net                                                                          22,614                  7,338
                                                                                       ---------------------    -------------------
       Total Intangible Assets                                                                        50,585                 21,232
                                                                                       ---------------------    -------------------

Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund                                                        244,514                220,815
Nine Mile Two deferred costs                                                                          27,155                 28,206
Unamortized debt expense                                                                              16,602                 17,984
Other deferred debits                                                                                  4,674                 13,137
Regulatory assets                                                                                    411,212                466,231
Other assets                                                                                           1,331                  2,037
                                                                                       ---------------------    -------------------
       Total Deferred Debits and Other Assets                                                        705,488                748,410
                                                                                       ---------------------    -------------------
       Total Assets                                                                              $ 2,565,798            $ 2,462,874
============================================================================           =====================    ===================
</TABLE>
The accompanying notes are an integral part of the financial statements.

<PAGE>

                                       49

RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET


(Thousands of Dollars)       At December 31,                  2000       1999
--------------------------------------------------------------------------------
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds                            $  580,132 $  580,070
               - promissory notes                             243,728    235,395
Preferred stock redeemable at option of RG&E                   47,000     47,000
Preferred stock subject to mandatory redemption                25,000     25,000
Common shareholders' equity
Common stock
 Authorized 100,000,000 shares; 38,956,726 shares issued at
 December 31, 2000 and 38,885,813 shares issued at December
 31, 1999                                                     702,807    700,268
Retained earnings                                             181,546    153,186
                                                           ---------- ----------
                                                              884,353    853,454
Less: Treasury stock at cost (4,379,300 shares at December
       31, 2000 and 2,942,600 shares at December 31, 1999)    117,238     83,252
                                                           ---------- ----------
      Total Common Shareholders' Equity                       767,115    770,202
                                                           ---------- ----------
      Total Capitalization                                  1,662,975  1,657,667
                                                           ---------- ----------

Long Term Liabilities
 Nuclear waste disposal                                        97,291     91,743
 Uranium enrichment decommissioning                             9,649     10,911
 Site remediation                                              24,420     23,698
                                                           ---------- ----------
                                                              131,360    126,352
                                                           ---------- ----------
Current Liabilities
Long term debt due within one year                             12,095     37,643
Short term debt                                               122,400     10,500
Accounts payable                                              108,618     54,221
Dividends payable                                              16,515     17,078
Equal payment plan                                                  -     10,529
Other                                                          57,491     39,385
                                                           ---------- ----------
      Total Current Liabilities                               317,119    169,356
                                                           ---------- ----------

Deferred Credits and Other Liabilities
Accumulated deferred income taxes                             277,787    318,694
Pension costs accrued                                          26,547     48,628
Kamine deferred credit                                         51,920     58,738
Post employment benefits                                       54,505     48,653
Other                                                          43,585     34,786
                                                           ---------- ----------
      Total Deferred Credits and Other Liabilities            454,344    509,499
                                                           ---------- ----------

Commitments and Other Matters (See Note 12)                         -          -
                                                           ---------- ----------
      Total Capitalization and Liabilities                 $2,565,798 $2,462,874
=====================================================      ========== ==========
The accompanying notes are an integral part of the financial statements.


<PAGE>

                                       50

RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
(Thousands of Dollars)                                   Year Ended December 31,          2000           1999 *         1998
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>            <C>            <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income                                                                              $  95,559      $  93,580      $  94,138
Adjustments to reconcile net income to net cash provided
      from operating activities:
Depreciation & amortization                                                               132,410        135,094        135,289
Deferred recoverable fuel costs                                                            10,873          1,401         (3,565)
Income taxes deferred                                                                     (14,002)         9,901         (9,141)
Allowance for funds used during construction                                               (2,144)        (1,708)        (1,061)
Power contract termination costs                                                                -              -        (10,000)
Unbilled revenue                                                                          (13,115)       (20,083)        10,516
Post employment benefit/pension costs                                                      10,900          4,100         (2,700)
Provision for doubtful accounts                                                               152          7,472           (372)
Changes in certain current assets and liabilities; net of
assets acquired and liabilities assumed in acquisitions:
      Accounts receivable                                                                 (37,756)        (8,420)        27,549
      Materials, supplies and fuels                                                       (12,903)         4,818            141
      Taxes accrued                                                                        (4,711)         4,095         (1,448)
      Accounts payable                                                                     52,615          1,767         (7,031)
      Other current assets and liabilities, net                                             8,721          1,516          1,327
Other, net                                                                                  1,070        (13,742)        (8,029)
                                                                                        ---------      ---------      ---------
         Total Operating                                                                  227,669        219,791        225,613
=============================================================================           ---------      ---------      ---------

CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant                                                           (142,496)      (108,339)      (129,286)
Nuclear generating plant decommissioning fund                                             (20,736)       (20,736)       (20,827)
Acquisitions, net of cash                                                                 (48,889)        (3,152)       (30,977)
Proceeds from sale of Oswego #6                                                                 -         10,920              -
Electric transmission contract termination costs                                                -        (26,935)             -
Other, net                                                                                   (289)          (147)           484
                                                                                        ---------      ---------      ---------
         Total Investing                                                                 (212,410)      (148,389)      (180,606)
=============================================================================           ---------      ---------      ---------

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
      Sale/Issuance of common stock                                                         1,772              -            586
      Issuance of long term debt and promissory notes                                      17,540        103,509         99,422
      Short term borrowings, net                                                          111,900        (46,500)        30,500
Retirement of long term debt                                                              (30,000)        (3,104)       (55,500)
Retirement of preferred stock                                                                   -        (10,000)       (10,000)
Repayment of promissory notes                                                              (7,290)        (5,958)        (7,790)
Dividends paid on preferred stock                                                          (3,700)        (4,274)        (5,031)
Dividends paid on common stock                                                            (63,552)       (66,262)       (69,592)
Payment for treasury stock                                                                (33,986)       (36,819)       (46,433)
Other, net                                                                                     27           (229)           (51)
                                                                                        ---------      ---------      ---------
         Total Financing                                                                   (7,289)       (69,637)       (63,889)
                                                                                        ---------      ---------      ---------
         Increase (Decrease) in cash and cash equivalents                               $   7,970      $   1,765      $ (18,882)
         Cash and cash equivalents at beginning of year                                 $   8,288      $   6,523      $  25,405
                                                                                        ---------      ---------      ---------
         Cash and cash equivalents at end of year                                       $  16,258      $   8,288      $   6,523
-----------------------------------------------------------------------------           ---------      ---------      ---------


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars)                               Year Ended December 31,               2000           1999           1998
-------------------------------------------------------------------------------------------------------------------------------

Cash Paid During the Period

      Interest paid (net of capitalized amount)                                         $  59,060      $  54,059      $  43,793
                                                                                        ---------      ---------      ---------
      Income taxes paid                                                                 $  47,038      $  58,750      $  75,600
                                                                                        ---------      ---------      ---------
Transfer from utility plant to regulatory asset, net                                    $       -      $  54,255      $       -
-----------------------------------------------------------------------------           ---------      ---------      ---------
</TABLE>
* Reclassified for comparative purposes

The accompanying notes are an integral part of the financial statements.

<PAGE>

                                       51

Rochester Gas and Electric Corporation
STATEMENT OF INCOME

<TABLE>
<CAPTION>
(Thousands of Dollars)                           Year Ended December 31,        2000             1999              1998
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>              <C>               <C>
Operating Revenues
   Electric                                                                   $  721,737       $  700,194        $  687,622
   Gas                                                                           322,412          281,555           274,657
   Other                                                                               -          108,699            71,212
                                                                           --------------   --------------    --------------

      Total Operating Revenues                                                 1,044,149        1,090,448         1,033,491

Operating Expenses
   Fuel Expenses
     Fuel for electric generation                                                 48,851           49,297            53,954
     Purchased electricity                                                        80,938           53,046            27,024
     Gas purchased for resale                                                    192,038          148,983           155,497
     Unregulated fuel expenses                                                         -           91,505            59,490
                                                                           --------------   --------------    --------------

      Total Fuel Expenses                                                        321,827          342,831           295,965

Operating Revenues Less Fuel Expenses                                            722,322          747,617           737,526

Other Operating Expenses
   Operations and maintenance excluding fuel expenses                            313,721          297,890           301,625
   Unregulated operating and maintenance expenses excluding fuel                       -           14,236            13,524
   Depreciation and amortization                                                 112,110          117,289           116,102
   Taxes - local, state and other                                                 90,090          112,613           117,973
   Income tax                                                                     59,451           64,454            60,236
                                                                           --------------   --------------    --------------

      Total Other Operating Expenses                                             575,372          606,482           609,460

Operating Income                                                                 146,950          141,135           128,066

Other (Income) and Deductions
Allowance for other funds used during construction                                  (825)            (657)             (408)
Income tax                                                                           221           (1,144)            1,665
Other, net                                                                        (8,897)          (8,111)          (13,370)
                                                                           --------------   --------------    --------------

      Total Other (Income) and Deductions                                         (9,501)          (9,912)          (12,113)

Interest Charges
   Long term debt                                                                 56,673           53,067            43,306
   Other. net                                                                      5,568            4,543             3,388
   Allowance for borrowed funds used during construction                          (1,319)          (1,051)             (653)
                                                                           --------------   --------------    --------------

      Total Interest Charges                                                      60,922           56,559            46,041
                                                                           --------------   --------------    --------------

Net Income                                                                        95,529           94,488            94,138
                                                                           --------------   --------------    --------------

Dividends on Preferred Stock                                                       3,700            4,083             4,842
                                                                           --------------   --------------    --------------

Net Income Applicable to Common Stock                                         $   91,829       $   90,405        $   89,296
                                                                           --------------   --------------    --------------
</TABLE>




STATEMENT OF RETAINED EARNINGS

<TABLE>
<CAPTION>
(Thousands of Dollars)                              Year Ended December 31,     2000             1999              1998
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>             <C>              <C>
Balance at Beginning of Period                                                  $ 137,854        $ 129,484         $ 109,313
Add
   Net Income                                                                      95,529           94,488            94,138
                                                                            --------------   --------------    --------------
      Total                                                                       233,383          223,972           203,451
                                                                            --------------   --------------    --------------

Deduct
   Dividends declared on capital stock
     Cumulative preferred stock - at required rates                                 3,700            4,083             4,842
     Common Stock                                                                  62,989           65,594            68,927
   Adjustment Associated with RGS Energy Group Formation                                -           16,243                 -
   Other Adjustments                                                                  510              198               198
                                                                            --------------   --------------    --------------
      Total                                                                        67,199           86,118            73,967
                                                                            --------------   --------------    --------------

Balance at End of Period                                                        $ 166,184        $ 137,854         $ 129,484
                                                                            ==============   ==============    ==============
</TABLE>

The accompanying notes are an integral part of the financial statements.

<PAGE>

                                       52

ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET

<TABLE>
<CAPTION>
(Thousands of Dollars)                                      At December 31,                      2000                    1999
====================================================================================================================================
<S>                                                                                <C>                    <C>
Assets
Utility Plant
Electric                                                                            $          2,467,289    $         2,399,532
Gas                                                                                              471,051                453,634
Common                                                                                           117,473                107,469
Nuclear                                                                                          292,588                270,447
                                                                                    --------------------    -------------------
                                                                                               3,348,401              3,231,082
Less:  Accumulated depreciation                                                                1,735,752              1,634,334
          Nuclear fuel amortization                                                              254,435                239,243
                                                                                    --------------------    -------------------
                                                                                               1,358,214              1,357,505
Construction work in progress                                                                    111,486                 95,862
                                                                                    --------------------    -------------------
          Net Utility Plant                                                                    1,469,700              1,453,367
                                                                                    --------------------    -------------------

Current Assets
Cash and cash equivalents                                                                          4,851                  6,443
Accounts receivable, net of allowance for doubtful accounts:
  2000 - $33,482; 1999 - $33,365                                                                  93,699                 70,388
Affiliate receivable                                                                              50,989                 13,197
Unbilled revenue receivable                                                                       61,838                 55,661
Fuels                                                                                             33,896                 23,876
Materials and supplies                                                                             8,187                  9,502
Prepayments                                                                                       23,782                 23,439
                                                                                    --------------------    -------------------
          Total Current Assets                                                                   277,242                202,506
                                                                                    --------------------    -------------------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund                                                    244,514                220,815
Nine Mile Two deferred costs                                                                      27,155                 28,206
Unamortized debt expense                                                                          16,602                 17,984
Other deferred debits                                                                              4,674                 13,760
Regulatory assets                                                                                411,212                466,231
                                                                                    --------------------    -------------------
          Total Deferred Debits and Other Assets                                                 704,157                746,996
                                                                                    --------------------    -------------------
          Total Assets                                                              $          2,451,099    $         2,402,869
=============================================================================       ====================    ===================
</TABLE>
The accompanying notes are an integral part of the financial statements.

<PAGE>

                                       53

ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET



(Thousands of Dollars)       At December 31,                  2000       1999
--------------------------------------------------------------------------------
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds                            $  580,132 $  580,070
               - promissory notes                             211,703    215,930
Preferred stock redeemable at option of RG&E                   47,000     47,000
Preferred stock subject to mandatory redemption                25,000     25,000
Common shareholder's equity
 Authorized 50,000,000 shares; 38,885,813 shares issued at
 December 31, 2000 and at December 31, 1999                   700,318    700,268
 Retained earnings                                            166,184    137,854
                                                           ---------- ----------
                                                              866,502    838,122
Less: Treasury stock at cost (4,379,300 shares at December
       31, 2000 and 2,942,600 shares at December 31, 1999)    117,238     83,252
                                                           ---------- ----------
      Total Common Shareholder's Equity                       749,264    754,870
                                                           ---------- ----------
      Total Capitalization                                  1,613,099  1,622,870
                                                           ---------- ----------

Long Term Liabilities
 Nuclear waste disposal                                        97,291     91,743
 Uranium enrichment decommissioning                             9,649     10,911
 Site remediation                                              22,356     22,357
                                                           ---------- ----------
                                                              129,296    125,011
                                                           ---------- ----------
Current Liabilities
Long term debt due within one year                              4,227     33,781
Short term debt                                                98,000          -
Accounts payable                                               79,356     42,263
Affiliate payable                                              18,451     12,961
Dividends payable                                              16,515     17,078
Equal payment plan                                                  -     10,529
Other                                                          41,664     33,234
                                                           ---------- ----------
      Total Current Liabilities                               258,213    149,855
                                                           ---------- ----------

Deferred Credits and Other Liabilities
Accumulated deferred income taxes                             274,299    314,683
Pension costs accrued                                          26,548     48,628
Kamine deferred credit                                         51,920     58,738
Post employment benefits                                       54,505     48,653
Other                                                          43,219     34,431
                                                           ---------- ----------
      Total Deferred Credits and Other Liabilities            450,491    505,133
                                                           ---------- ----------

Commitments and Other Matters (See Note 12)                         -          -
                                                           ---------- ----------
      Total Capitalization and Liabilities                 $2,451,099 $2,402,869
=====================================================      ========== ==========
The accompanying notes are an integral part of the financial statements.

<PAGE>

                                       54

ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
(Thousands of Dollars)                          Year Ended December 31,                     2000           1999 *         1998 *
====================================================================================================================================
<S>                                                                                      <C>            <C>            <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income                                                                               $  95,529      $  94,488      $  94,138
Adjustments to reconcile net income to net cash provided
      from operating activities:
Depreciation & amortization                                                                128,629        131,903        135,289
Deferred recoverable fuel costs                                                             10,873          1,401         (3,565)
Income taxes deferred                                                                      (12,820)         5,889         (9,141)
Allowance for funds used during construction                                                (2,144)        (1,708)        (1,061)
Power contract termination costs                                                                 -              -        (10,000)
Unbilled revenue                                                                            (6,177)       (17,739)        10,516
Post employment benefit/pension costs                                                       10,900          4,100         (2,700)
Provision for doubtful accounts                                                                117          7,066           (372)
Changes in certain current assets and liabilities:
      Accounts receivable                                                                  (61,220)       (10,248)        27,549
      Materials, supplies and fuels                                                         (8,705)         7,164            141
      Taxes accrued                                                                         (5,333)         2,822         (1,448)
      Accounts payable                                                                      42,602         (3,298)        (7,031)
      Other current assets and liabilities, net                                              2,144            663          1,327
Other, net                                                                                     970        (11,876)        (8,029)
                                                                                      -------------  -------------  -------------
         Total Operating                                                                   195,365        210,627        225,613
===============================================================================       =============  =============  =============


CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant                                                            (140,084)      (106,359)      (129,286)
Nuclear generating plant decommissioning fund                                              (20,736)       (20,736)       (20,827)
Acquisition, net of cash                                                                         -              -        (30,977)
Proceeds from sale of Oswego #6                                                                  -         10,920              -
Electric transmission contract termination costs                                                 -        (26,935)             -
Other, net                                                                                     769            467            484
                                                                                      -------------  -------------  -------------
         Total Investing                                                                  (160,051)      (142,643)      (180,606)
===============================================================================       =============  =============  =============


CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
      Sale/Issuance of common stock                                                              -              -            586
      Issuance of long term debt                                                                 -        100,000         99,422
      Short term borrowings, net                                                            98,000        (50,500)        30,500
Retirement of long term debt                                                               (30,000)             -        (55,500)
Retirement of preferred stock                                                                    -        (10,000)       (10,000)
Repayment of promissory notes                                                               (3,781)        (2,449)        (7,790)
Dividends paid on preferred stock                                                           (3,700)        (4,274)        (5,031)
Dividends paid on common stock                                                             (63,552)       (66,262)       (69,592)
Payment for treasury stock                                                                 (33,986)       (36,819)       (46,433)
Corporate restructuring to establish holding company                                             -         (6,824)             -
Other, net                                                                                     113          9,064            (51)
                                                                                      -------------  -------------  -------------
         Total Financing                                                                   (36,906)       (68,064)       (63,889)
                                                                                      -------------  -------------  -------------
         Decrease in cash and cash equivalents                                           $  (1,592)     $     (80)     $ (18,882)
         Cash and cash equivalents at beginning of year                                  $   6,443      $   6,523      $  25,405
                                                                                      -------------  -------------  -------------
         Cash and cash equivalents at end of year                                        $   4,851      $   6,443      $   6,523
===============================================================================       =============  =============  =============
</TABLE>

<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars)                          Year Ended December 31                      2000           1999           1998
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>            <C>            <C>
Cash Paid During the Period
      Interest paid (net of capitalized amount)                                           $ 58,753      $  53,061      $  43,793
                                                                                      -------------  -------------  -------------
      Income taxes paid                                                                   $ 46,438      $  58,750      $  75,600
                                                                                      -------------  -------------  -------------
Transfer from utility plant to regulatory asset, net                                      $      -      $  54,255      $       -
===============================================================================       =============  =============  =============
</TABLE>

* Reclassified for comparative purposes

The accompanying notes are an integral part of the financial statements.


<PAGE>

                                       55


NOTES TO FINANCIAL STATEMENTS

Note 1.   SUMMARY OF ACCOUNTING PRINCIPLES

     HOLDING COMPANY FORMATION.  On August 2, 1999, Rochester Gas and Electric
Corporation (RG&E) was reorganized into a holding company structure in
accordance with the Agreement and Plan of Exchange between RG&E and RGS Energy
Group, Inc. (the Company or RGS Energy).  RG&E's common stock was exchanged on a
share-for-share basis for RGS Energy's common stock.  RG&E's preferred stock was
not exchanged as part of the share exchange and will continue as shares of RG&E.

     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 accounting principles generally accepted in the
United States of America (GAAP) 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.

     BASIS OF PRESENTATION.  This is a combined report of RGS Energy and RG&E, a
regulated Electric and Gas subsidiary.  The Notes to Financial Statements apply
to both RGS Energy and RG&E.  RGS Energy's Consolidated Financial Statements
include the accounts of RGS Energy and its wholly owned subsidiaries, including
RG&E, and two non-utility subsidiaries, Energetix and RGS Development
Corporation (RGS Development).  RGS Energy's prior period consolidated financial
statements have been prepared from RG&E's prior period consolidated financial
statements, except that accounts have been reclassified to reflect RGS Energy's
structure.  RG&E's financial statements also include Energetix and RGS
Development prior to August 2, 1999.

     PRINCIPLES OF CONSOLIDATION.  The consolidated financial statements include
the accounts of the Company and its wholly-owned subsidiaries RG&E, Energetix
and RGS Development.  All intercompany balances and transactions have been
eliminated.  Energetix's financial statements are consolidated with its wholly-
owned subsidiary Griffith Energy (Griffith).

     During the second quarter of 1998, the Company formed a new unregulated
subsidiary, RGS Development.  RGS Development was formed to pursue unregulated
business opportunities in the energy marketplace.  Through December 31, 2000,
RGS Development operations have not been material to the Company's results of
operation or its financial condition.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.

   NEW YORK STATE TAX CHANGES.  On May 15, 2000 changes to the New York State
tax laws were signed into law effective January 1, 2000.  In June 2000 the
Company recorded taxes in accordance with these changes.  The effect of these
changes was a reduction in the gross receipts tax rate, elimination of excess
dividends taxes, and the imposition of a state income tax.  As a result,
deferred state income taxes were established in accordance with the transition
rules to recognize timing differences between book and tax deductibility.  This
transition item results in a one-time tax benefit that has been deferred for
future rate treatment in accordance with the Electric Settlement.
<PAGE>

                                       56

     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).  When circumstances change, the
Company reviews the recoverability of goodwill based primarily upon an analysis
of undiscounted cash flows from the acquired businesses.  Other intangible
assets include predominately dealer improvements, customer lists and covenants
not to compete and are being amortized between one and fifteen years.
Accumulated amortization amounted to $3.5 million and $1.7 million at December
31, 2000 and December 31, 1999 respectively.

     ACQUISITIONS.  In August 1998, Energetix acquired Griffith Oil, Co., Inc.,
for $31.5 million.  The acquisition was accounted for as a purchase resulting in
goodwill as reflected on the consolidated financial statements.  The principal
tangible assets acquired were vehicles, tanks, pumps, buildings and commodity
inventory.

     During 2000, Energetix acquired seven companies for an aggregate purchase
price of $48.9 million, net of cash acquired.  These acquisitions were recorded
under the purchase method of accounting and, therefore, the purchase prices have
been allocated to assets acquired and liabilities assumed based on estimated
fair values, which are subject to further refinement.  The results of operations
of the acquired companies were included in the consolidated results of the
Company from their respective acquisition dates.

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

     RG&E's regulated gas tariffs include a monthly gas adjustment clause, which
allows RG&E to recover pipeline and storage capacity costs and the commodity
cost of gas purchased for its customers.  On an annual basis, RG&E reconciles
the costs collected through the monthly gas adjustment clause and the actual gas
costs for the prior twelve months.

     RG&E eliminated its electric fuel cost adjustment clause in a prior rate
settlement agreement with the PSC.  This clause adjusted tariff rates monthly to
reflect changes in the actual average cost of fuels.

     Griffith revenues are recognized when products are delivered to customers
or services have been rendered.

     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%
during the three-year period ended December 31, 2000.  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 3.1% in the three-year
period ended December 31, 2000.  The annual depreciation provision of Energetix
is 7.8% in the three-year period ended December 31, 2000.

     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.
<PAGE>

                                       57

     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 brokers.

     Energetix has entered into electric and natural gas purchase commitments
with numerous suppliers. These commitments support fixed price offerings to
retail electric and gas customers. 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 Griffith's inventory or future purchases and sales of
commodities used in Griffith's operation. These contracts are closely monitored
on a daily basis to manage the price risk associated with the company's
inventory and future product commitments. All hedge contracts are accounted for
under the deferral method with gains and losses from the hedging activity
included in the cost of sales as inventories are sold or as the hedge
transaction occurs. Commodity instruments not designated as effective hedges are
marked to market at the end of the reporting period, with the resulting gains or
losses recognized in cost of sales. As of December 31, 2000 Griffith's net
deferred gains on open hedge contracts were immaterial.

     In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). This statement was subsequently
amended by SFAS 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133", and SFAS
138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an amendment of SFAS 133". SFAS 133, as amended, established
accounting and reporting standards for derivative instruments including certain
derivative instruments embedded in other contracts and for hedging activities.
This statement requires the Company to recognize all derivatives, with limited
exception, as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. The intended use of the
derivatives and their designation as either a fair value or cash flow hedge
determines when the gains or losses on the derivatives are reported in earnings
and when they are reported as a component of other comprehensive income. The
statement allows hedge accounting for the derivative instruments employed to
manage market price risk, provided stringent documentation requirements are met
prior to execution of the hedge transaction. Where applicable, the Company
intends to elect hedge accounting for derivatives under the statement.

     The Company has adopted SFAS 133 as of January 1, 2001. The cumulative
effect of this change will not materially impact the Company's annual net
income. This broad and complex standard requires, with limited exception,
derivative transactions to be recognized and recorded on the Company's balance
sheet at fair value. The balance sheet effect is an increase to assets and
liabilities of approximately $9.5 million.

     JOINTLY OWNED FACILITIES.  The Company is a 14% owner of the Nine Mile
Point Nuclear Plant Unit No. 2 (Nine Mile Two) generating facility.  Nine Mile
Two is operated by Niagara Mohawk Power Corporation (Niagara Mohawk).  Each
participant must provide its own financing for any additions to the facility.
The Company's share of direct expenses associated with this unit is included in
the appropriate operating expenses in the Consolidated Statement of Income.

     RESEARCH AND DEVELOPMENT COSTS.  Research and Development costs are charged
to expense as incurred.  Expenditures for the years 2000, 1999 and 1998 were
$2.6 million, $2.9 million and $3.4 million respectively.
<PAGE>

                                       58

     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.

     MATERIALS, SUPPLIES AND FUELS.  Materials and supplies inventories are
valued at the lower of cost or market using the first-in, first-out or weighted
average cost 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.

     NUCLEAR OUTAGE COSTS.  The Company levelizes estimated incremental non-fuel
expenses due to planned refueling outages at its two nuclear power plants.  Such
costs are levelized between refueling outages.

     STOCK-BASED COMPENSATION.  The Company accounts for its stock-based
compensation using the fair value method in accordance with SFAS-123 (Accounting
for Stock-Based Compensation).  The aggregate amount recorded as a
(benefit)/expense as a result of the Company's stock based compensation plans
for the years 2000, 1999 and 1998 approximates $(1.9) million, $2.2 million and
$5.9 million respectively.

     COMPREHENSIVE INCOME.  There were no items of comprehensive income during
the three-year period ended December 31, 2000; therefore, net income is
equivalent to total comprehensive income.

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


Note 2.  NUCLEAR - RELATED MATTERS

     NINE MILE NUCLEAR PLANTS.   On June 24, 1999, Niagara Mohawk and New York
State Electric and Gas Corporation (NYSEG) announced their intention to sell
their interests in the Nine Mile One and Nine Mile Two nuclear plants to AmerGen
Energy Company, L.L.C. (AmerGen), a joint venture of PECO Energy and  British
Energy. Niagara Mohawk owns 41 percent of Nine Mile Two and 100 percent of Nine
Mile One and NYSEG owns 18 percent of Nine Mile Two.

     RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal but RG&E has a right of first refusal to buy the interests of the other
owners of Nine Mile Two on terms at least as favorable as those offered.  RG&E
exercised its right of first refusal and broadened it to include Nine Mile One
with which Nine Mile Two was paired in the proposal. However, in the ensuing
discussions with the PSC staff it became clear that the transaction on the terms
proposed would not be approved by the PSC.

     On April 25, 2000, the PSC issued an order that allowed NYSEG and Niagara
Mohawk to withdraw their petition to sell their interests in the Nine Mile
plants to AmerGen. The order concluded that Nine Mile's market value is "greatly
in excess of the original AmerGen purchase price" and that multiple entities are
now interested in the Nine Mile plants.  The order also concluded that
"...failure for the utilities to determine the market value of the Nine Mile
facilities at this time, through an open process, would raise serious prudence
questions."  With respect to stranded costs, the PSC order indicates that
stranded costs cannot be finally quantified "until the disposition of the plants
by the utilities is decided."  The PSC's order does, however, observe that (1) a
sale would be considered within its policy of separating generation from
transmission and distribution, (2) a sale at current market values would
constitute appropriate mitigation of stranded costs and (3) ratemaking treatment
of a sale would be resolved in accordance with each company's competitive
opportunities/restructuring order taking into account reduced risk and corollary
divestiture effects.

     After issuance of the PSC's order, RG&E decided to determine the market
value of its interest in Nine Mile Two.  On June 1, 2000, RG&E issued a press
release announcing an auction process by RG&E, Central
<PAGE>

                                       59

Hudson Gas & Electric Corporation (Central Hudson), NYSEG and Niagara Mohawk in
connection with their ownership interests in Nine Mile Two and Niagara Mohawk's
interest in Nine Mile One.

     On December 11, 2000, RG&E, Niagara Mohawk, Central Hudson and NYSEG
entered into an agreement to sell their ownership interests in Nine Mile Two to
Constellation Nuclear, L.L.C. (Constellation Nuclear).  Constellation Nuclear
was the successful bidder in a competitive auction conducted for the plants. The
Long Island Power Authority, an 18 percent owner of Nine Mile Two, is not
participating in the sale.

     The purchase price for RG&E's 14% ownership interest in Nine Mile Two is
$99.2 million, $49.6 million of which will be paid in cash at closing and $49.6
million of which will be paid in five equal annual principal installments plus
interest at a rate of 11% pursuant to a five year promissory note.  Principal
and interest payments under the promissory note will total approximately $66
million unless the note is pre-paid. The purchase price is subject to adjustment
at the time of closing. The aggregate purchase price for 82 percent of Nine Mile
Two is $581 million. The aggregate purchase price, including cash payments at
closing and payments of principal and interest to all of the sellers under the
promissory notes, is $676.6 million for 82 percent of Nine Mile Two.

     Also, part of the transaction is a power purchase agreement whereby
Constellation Nuclear has agreed to sell 90 percent of RG&E's 14 percent
interest in Nine Mile Two's actual output back to RG&E for approximately 10
years at an average price of less than $35 per MWh over the term of the power
purchase agreement.

     After the completion of the power purchase agreement, a 10-year revenue
sharing agreement begins.  The revenue sharing agreement will provide RG&E with
a hedge against electricity price increases and could provide RG&E additional
revenue through 2021.  The revenue sharing agreement provides that, to the
extent market prices (for energy and capacity) exceed certain strike prices, 14%
of the market value of Nine Mile Two's actual output (capped at 160 MW) above
the strike price will be shared 80% to RG&E and 20% to Constellation Nuclear.
When actual market prices are lower than strike prices, such negative amounts
will be carried forward as credits against subsequent payments.

     At closing, the sellers' pre-existing decommissioning funds will be
transferred to Constellation Nuclear and Constellation Nuclear will assume the
sellers' obligation to decommission Nine Mile Two.

     The Nuclear Regulatory Commission (NRC), FERC, PSC and other regulatory
bodies must approve the sale. Receipt of such regulatory approvals (including,
without limitation, the PSC's authorization to establish a regulatory asset and
return thereon for the full amount of RG&E's unamortized plant and capital costs
of Nine Mile Two remaining after the closing of the sale), in form and substance
reasonably satisfactory to RG&E, is a condition to RG&E's obligation to close
the transaction. The transaction is targeted to close in mid-2001. At December
31, 2000, the net book value of RG&E's 14 percent interest in the Nine Mile Two
generating facility was approximately $360 million.  RG&E also had investments
in fuel of approximately $8.9 million, transmission and distribution facilities
of $3.4 million and construction work in progress of $4.6 million.

     On January 31, 2001, RG&E, together with Niagara Mohawk, Central Hudson,
NYSEG and Constellation Nuclear filed a Section 70 petition with the PSC.  The
petition requests that the PSC authorize the sellers to transfer to
Constellation Nuclear their interests in Nine Mile Two in accordance with the
rate treatment proposed.  For RG&E, the rate treatment proposed includes full
recovery of the regulatory asset remaining after the sale.

     Prior to the events discussed above, the PSC had initiated a proceeding to
examine the appropriate role of the nuclear power plants in the State in
developing a competitive market for electricity.  Collaborative efforts of the
parties led to the development of a report on the subject which the PSC
discussed at a July 1999 session without issuing an order.  No significant
activity has since occurred in the proceeding and RG&E cannot predict what the
PSC may do to continue or conclude it.  Since all nuclear plants in the State
either have now been sold or are under contract to be sold, except for RG&E's
Ginna Plant, the PSC could regard the proceeding as moot.
<PAGE>

                                       60

     DECOMMISSIONING TRUST.  RG&E is collecting amounts in its electric rates
for the eventual decommissioning of its Ginna Plant and for its 14 percent 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, RG&E has collected
decommissioning costs of approximately $182.9 million through December 31, 2000
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 RG&E's 14 percent 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.  RG&E's plan,
filed in 1990, consists of an external decommissioning trust fund covering both
its Ginna Plant and its share of Nine Mile Two.  Since 1990, RG&E has
contributed $148.7 million to this fund and, including realized and unrealized
investment returns, the fund has a balance of $244.5 million as of December 31,
2000.  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, 2000 is $34.2 million.  NRC regulations require biennial
reports on the status of decommissioning trust funds and RG&E reported to the
NRC that both the Ginna and Nine Mile Two decommissioning trusts exceed the NRC
minimum funding amounts required as of December 31, 1999.

     During December 2000, Constellation Nuclear was the successful bidder in an
auction of the Company's 14 percent interest in the Nine Mile Two nuclear plant.
As part of the purchase agreement, upon closing RG&E will transfer approximately
$29.0 million to Constellation Nuclear to fully fund RGE's pro-rata share of the
plant's decommissioning liability.  As of December 31, 2000, Nine MileTwo
decommissioning assets were sufficient to meet RG&E's funding obligation. Upon
completion of the sale, Constellation Nuclear will assume all decommissioning
liabilities for Nine Mile Two.

     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 a 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 Nine MileTwo,
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 examine the future treatment of
nuclear generation.  The initial collaborative conference in this proceeding was
held in January 1999.  RG&E's potentially strandable assets in nuclear plants
could be impacted by the outcome of this proceeding. The parties in this
proceeding developed a collaborative, non-binding interim report entitled
"Nuclear Generation and the Competitive Electric Market" which was issued in
July 1999.  RG&E is actively involved in this proceeding which is continuing.
RG&E is unable to determine when this proceeding may conclude.

     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
<PAGE>

                                       61

accounting for the decommissioning costs of RG&E's nuclear plants. 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 a determination by the PSC.

     URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND.  On June 12,
1998, 16 electric utilities from across the country, including RG&E, filed
multi-count complaints against the United States government in the United States
District Court for the Southern District of New York. The suits challenge 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 matter is proceeding through the courts.

     The assessments for Ginna and RG&E's share of Nine Mile Two are estimated
to total $22.1 million, excluding inflation and interest. Installments
aggregating approximately $14.7 million have been paid through 2000. A liability
has been recognized on the financial statements along with a corresponding
regulatory asset. For the two facilities RG&E's liability at December 31, 2000
is $11.4 million ($9.6 million as a long-term liability and $1.8 million as a
current liability). RG&E is recovering these costs in rates.

     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, at the
earliest.  In December 1996 the DOE notified RG&E that the DOE would not start
accepting 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 RG&E in June 1985.  RG&E estimates the fees,
including accrued interest, owed to the DOE to be $97.3 million at December 31,
2000.  RG&E is allowed by the PSC to recover these costs in rates.  The
estimated fees are classified as a long-term liability and interest is accrued
at the current three-month Treasury bill rate, adjusted quarterly.  The Nuclear
Waste Act also requires the DOE to provide for the disposal of nuclear fuel
irradiated after April 6, 1983, for a charge of approximately one mill ($.001)
per KWH of nuclear energy generated and sold.  This charge (approximately $4.0
million per year) is currently being collected from customers and paid to the
DOE pursuant to PSC authorization.  RG&E 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
RG&E'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 RG&E completed
installation of seven high-capacity spent fuel racks in the Ginna 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.

LITIGATION

     SPENT NUCLEAR FUEL LITIGATION.   The federal Nuclear Waste Act obligated
the DOE to remove disposal spent nuclear fuel (SNF) from utilities' powerplants
by January 31, 1998 (statutory deadline).  Since the mid-1980s, RG&E and other
nuclear plant owners and operators have paid substantial fees to the DOE to fund
that obligation (Nuclear Waste Fund).  The DOE has not satisfied its obligation
under the Nuclear Waste Act and there is no way to determine when and if it will
begin removing SNF for disposal.

     The DOE's failure to meet its statutory deadline has given rise to numerous
lawsuits in both the U.S. Court of Appeals for the District of Columbia and the
U.S. Court of Federal Claims.
<PAGE>

                                       62

     Although the DOE has been found to have breached its obligations, it is not
possible to predict the outcome of these cases, the future course of the DOE
obligation or the resolution of the SNF movement and storage concern that
underlies it.  Similarly, the ultimate outcome of nuclear waste legislation in
Congress that could address these and related concerns, is uncertain.  The court
rulings on the DOE's default in meeting its obligation to remove SNF for
disposal by the statutory deadline, and on its contractual liability therefore,
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. RG&E and other nuclear utilities continue to work
toward those objectives in judicial, legislative and administrative.

Note 3: REGULATORY MATTERS

REGULATORY ASSETS

     With PSC approval RG&E has deferred certain costs rather than recognize
them as expense 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, Accounting for the Effects of
Certain Types of Regulation.  These deferred costs are shown as regulatory
assets on the Company's and RG&E's Balance Sheets.  Such cost deferral is
appropriate in a 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 RG&E was no longer allowed to defer some or a
portion of these costs under SFAS-71, these assets would be adjusted
accordingly, which may include up to the entire amount being written off.

     Below is a summary of RG&E's regulatory assets as of December 31, 2000 and
1999:

<TABLE>
<CAPTION>

                                                  Millions of Dollars
                                                      2000     1999
                                                    ------   ------
<S>                                               <C>        <C>
     Kamine Settlement                              $179.1   $187.5
     Income Taxes                                    101.9    129.5
     Oswego Plant Sale                                74.4     78.6
     Deferred Environmental SIR costs                 16.6     20.5
     Uranium Enrichment Decommissioning Deferral      12.7     13.9
     Gas Deferred Fuel                                (1.6)     9.3
     Labor Day 1998 Storm Costs                        9.3      8.5
     Other, net                                       18.8     18.4
                                                    ------   ------

     Total - Regulatory Assets                      $411.2   $466.2
                                                    ======   ======
</TABLE>

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

-    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.
<PAGE>

                                       63

-    Oswego Plant Sale: This amount results from the sale of RG&E's interest in
     the Oswego generation facility including closing costs and the buyer's
     assumption of RG&E's obligations under a transmission services agreement.

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

-    Uranium Enrichment Decommissioning Deferral:  The Energy Policy Act of 1992
     requires utilities to contribute amounts to the DOE based on the amount of
     uranium enriched by the DOE for each utility.  This amount is mandated to
     be paid to the DOE through the year 2007.  The recovery of these costs is
     through base rates of fuel.

-    Gas Deferred Fuel: These costs result from a PSC-approved monthly gas
     adjustment clause which allows RG&E to recover pipeline and storage
     capacity costs and the commodity cost of gas purchased for its customers.
     On an annual basis, RG&E reconciles the costs collected through the monthly
     gas adjustment clause and the actual gas costs for the prior twelve months.

-    Labor Day 1998 Storm Costs: These costs result from a 1998 Labor Day storm.
     Under the Electric Settlement, RG&E 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.
     RG&E filed a petition with the PSC notifying it of the deferral of these
     storm costs.

     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.  An example
includes 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, 2000 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 the amount could be significant.  Strandable assets, if any, could be
written down for impairment of recovery based on SFAS-121, "Accounting for the
Impairment of Long Lived Assets and for Long Lived Assets to be Disposed of",
which requires write-down of  long-lived assets whenever events or circumstances
occur which indicate that the carrying amount of a long-lived asset may not be
recoverable.

     At December 31, 2000 RG&E believed that its regulatory assets are probable
of recovery.  The Electric Settlement does not impair the opportunity of RG&E to
recover its investment in these assets.  However, the Electric Settlement
provides for the non-nuclear generation to-go costs to be subject to market
forces during the current Settlement term.  Should the costs of non-nuclear
generation exceed market prices, the Company may no longer be able to apply
SFAS-71.  These costs have been below prevailing market prices.  The PSC issued
an Opinion and Order Instituting Further Inquiry on March 20, 1998 to address
issues surrounding nuclear generation.  RG&E is unable to determine when this
proceeding may conclude.  The ultimate determination in this proceeding or any
proceeding to consider RG&E's proposed sale of its interest in Nine Mile Two as
discussed under "Nuclear-Related Matters" could have an impact on strandable
assets and the recovery of nuclear costs.

     In a competitive natural gas market, strandable assets would arise where
customers migrate away from dependence on RG&E for full service, leaving RG&E
with surplus pipeline and storage capacity, as well as natural gas supplies
under contract.  RG&E has been restructuring its transportation, storage and
supply portfolio to reduce its potential exposure to strandable assets.
Regulatory developments referred to under "Gas Settlements" 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.
<PAGE>

                                       64

GAS SETTLEMENTS

     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 addressed 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
industries.  The PSC has encouraged settlement negotiations with each gas
utility pertaining to the transition to a fully competitive gas market.   RG&E,
the PSC Staff and other interested parties engaged in settlement discussions in
response to the specific requirements of the Gas Policy Statement.  In January
2001, RG&E reached agreement with PSC Staff and other parties on a comprehensive
rate and restructuring proposal for its natural gas business, as contemplated in
the PSC's Gas Policy Statement.

     GAS RETAIL ACCESS SETTLEMENTS.  On January 25, 2001, RG&E reached agreement
with PSC Staff and other parties on a comprehensive rate and restructuring
proposal for its natural gas business (the Gas Rates and Restructuring
Proposal), as contemplated in the PSC's Gas Policy Statement (see heading Rates
and Regulatory Matters,  "PSC Gas Restructuring Policy Statement").

     Since mid-1998, RG&E, PSC Staff and other parties have engaged in
settlement negotiations regarding RG&E's rates and restructuring.  These
negotiations have resulted in two previous agreements among RG&E, PSC staff and
several other parties.  The first was implemented in September 1999 and
addressed the following issues: a capacity release revenue imputation, capacity
cost mitigation measures, a timetable for public filing and resumption of
negotiations, and improvement of RG&E's retail access program.  The September
1999 agreement was approved by the PSC in an Order issued September 30, 1999.

     Pursuant to the September 1999 agreement, RG&E, on January 28, 2000, made a
filing addressing various issues pertaining to RG&E's natural gas business,
including proposals for restructuring that business and facilitating migration
from fully bundled sales service to retail service provided by natural gas
marketers.  Certain issues presented by the January 28, 2000 filing, principally
relating to the commencement of a single-retailer retail access program for gas,
in substantially the same form as currently in effect for electric retail access
(see "Energy Choice" heading), and the establishment of a "backout credit" to be
paid to natural gas marketers serving retail customers, were resolved in a June
2000 Gas Settlement.

     The Gas Rates and Restructuring Proposal is intended to resolve all issues
identified by the parties and not resolved in either the September 1999
settlement or the June 2000 Gas Settlement, as approved by the PSC.  It is
anticipated that this Proposal will be approved by the PSC in February 2001 and
made effective on March 1, 2001, although no assurance may be given as to such
approval or its timing.

     The Gas Rates and Restructuring Proposal contains a number of features that
are intended to extend for different periods.  The two most significant periods
are the Rate Term, which applies principally to rate-related provisions and
extends from July 1, 2000 through June 30, 2002, and the Rate and Restructuring
Program which applies to most other provisions and extends from the date of
approval of the Proposal through March 31, 2004. The principal features of the
Proposal are as follows:

     (1) for the purpose of setting base, or local delivery, rates for the
period beginning July 1, 2000, natural gas revenues shall be decreased a total
of $2,806,000 from the levels in effect on June 30, 2000.  This rate level is
based on an agreed-upon return on equity of 11.00 percent;

     (2) base rates will be adjusted effective March 1, 2001 to reflect the
revenue requirements decrease.  Because the current base rates that will be in
effect through February 28, 2001 are higher than those agreed to by the parties,
RG&E, in March 2001, will pass back to all its retail gas customers a temporary
credit applied to rates, on a volumetric basis, equal to the amount of the
reduction in rates for the period July 1, 2000 through February 28, 2001;
<PAGE>

                                       65

     (3) RG&E is allowed to defer any prudent and verifiable cost for recovery
after the Rate Term of the Proposal, subject to PSC approval;

     (4) in the event that RG&E achieves a return on equity in excess of 12.5
percent in any Rate Year covered by this Proposal, 90 percent of the excess over
that level shall be deferred for the benefit of customers;

     (5) RG&E shall be entitled to defer any costs associated with mandates and
catastrophic events that occur during the Rate Term of this Proposal.  If the
incremental cost impact of any individual mandate or any individual catastrophic
event exceeds $600,000 per rate year, RG&E is entitled to defer the entire
amount for recovery.  Amounts deferred shall be recovered from RG&E customers
after the Rate Term of this Proposal;

     (6) RG&E is entitled to defer for recovery after June 30, 2002, all
incremental expenditures for competition implementation costs to the extent that
such costs exceed $300,000 per year;

     (7) if migration to retail access is expected to exceed 30 percent of the
small-volume customer market (i.e., customers eligible under Service
Classification No. 5 - Small General Service) during the Rate Term of the
Proposal, the parties will meet to discuss the PSC Transition Cost Surcharge
with a view to considering changes that would reduce the allocation of capacity
costs to Service Classification No. 1 - General Service customers;

     (8) RG&E is authorized to implement a Retail Access Capacity Program,
contemplated to begin before the 2001-2002 heating season, pursuant to which
RG&E would release pipeline capacity it currently holds to marketers serving
customers in RG&E's service area.  This Program will help to avoid stranded
capacity costs that might otherwise result from migration of customers to
marketers;

     (9) RG&E will implement a Capacity Incentive Program, consisting of a
Capacity Cost Incentive and a Capacity Cost Imputation.  Both elements are
intended to encourage aggressive management of RG&E's capacity costs.  The
Capacity Cost Incentive is designed to share, between RG&E and its customers,
the savings resulting from the difference between a base level of capacity costs
and the actual capacity costs achieved. The Capacity Cost Imputation is intended
to provide customers with a guaranteed level of short-term savings through the
gas cost adjustment provision.  "Short-term" refers to periods of one year or
less.  "Savings" refers to capacity release savings, as well as net revenues
from off-system sales, if any.  The imputed level of savings will be $1,100,000
per year for the period beginning April 1, 2001 and extending through June 30,
2002.  The level will then be $500,000 per year for the period beginning July 1,
2002 and extending through March 31, 2004;

     (10) RG&E will implement a Low-Income Program for customers who require
assistance.  The Low-Income Program will be funded through a surcharge in
customer bills; and

     (11) RG&E will implement a Service Quality Performance Program to be
effective as of January 1, 2001 through at least June 30, 2002.  This Program
establishes performance targets for six specific measures of service and
provides for a maximum overall penalty of 42 basis points of gas return on
equity for failure to meet the minimum levels specified.

     PSC ASSIGNMENT OF GAS CAPACITY.  Under a March 1996 Order, the PSC
permitted RG&E and other gas distribution companies to assign to marketers, as
necessary,  to serve their customers the pipeline and storage capacity held by
RG&E.  In its Gas Policy Statement, the PSC ordered that the 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.
On March 24, 1999, the PSC issued an Order Concerning Assignment of Capacity for
all gas utilities in the State, generally requiring the removal of restrictions
on customer migration from utility service to service from marketers.  RG&E has
complied with the PSC's directives.  The Retail Access Capacity Program and the
Capacity Incentive Program contained in the Gas Rates and Restructuring Proposal
<PAGE>

                                       66

will, if adopted by the PSC, help to mitigate potential stranded costs resulting
from migration of customers to marketers.


     FERC GAS MARKET PROPOSALS. On February 9, 2000, FERC issued Order No. 637,
its final rule addressing "Regulation of Short-Term Natural Gas Transportation
Services"  and "Regulation of Interstate Natural Gas Transportation Services" .
On June 5, 2000 FERC issued Order No. 637-A providing clarification and
additional guidance. On July 26, 2000 FERC issued Order No. 637-B upholding
Orders No. 637 and No. 637-A.  Order No. 637 as clarified revises FERC's
regulations to improve the efficiency of the gas transportation market and to
provide captive customers with the opportunity to reduce their cost of holding
long-term pipeline capacity. Specifically, Order No. 637 as clarified:

     (1) waives the price ceiling for released capacity of less than one year
until September 30, 2002;

     (2) permits pipelines to propose peak, off-peak and term differentiated
rates, provided that they still satisfy the revenue and cost constraints of
traditional rate-making, and excess revenues are split with firm customers;

     (3) revises FERC's regulations on scheduling procedures, capacity
segmentation and pipeline penalties;

     (4) states that the right of first refusal will apply in the future to
contracts for 12 consecutive months or more of service at maximum rates; and

     (5) amends and supplements reporting requirements to require interstate
pipelines to report additional information on transactions, operationally
available capacity, and an expanded index of customers.

     Order No. 637 as clarified requires each pipeline to make a compliance
filing. All of the pipelines' initial compliance filings were submitted to FERC
by August 15, 2000.  FERC has established technical and settlement conference
procedures for many of the pipelines, including those on which RG&E holds
transportation capacity. FERC staff has indicated at the respective pipeline
settlement and technical conferences that no action on various pipeline
proposals  will be taken prior to April 2001, after the heating season has
ended.

     Neither RGS nor RG&E can predict what effects, if any, FERC's initiatives
and the related pipeline tariff changes will have on future operations or the
financial condition of RGS or RG&E.


Note 4.  OPERATING SEGMENT FINANCIAL INFORMATION

     The Company has 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 GAAP and PSC accounting policies.  The Unregulated segment's
financial records are maintained in accordance with GAAP.

     During the reported periods, substantially all revenues are from United
States sources, and substantially 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.
<PAGE>

                                       67

     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.  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 electricity, gasoline, natural gas, oil, propane, and appliance warranty
and repair.  RGS Development was formed to pursue unregulated business
opportunities in the energy marketplace.
<TABLE>
<CAPTION>

                                                    (thousands of dollars)

Regulated Electric                             2000         1999          1998
------------------                             ----         ----          ----
<S>                                        <C>          <C>           <C>
Operating Income                            $  124,149   $  120,599    $  119,937
Revenues from External Customers            $  721,737   $  698,745    $  687,100
Revenues from Intersegment Transactions     $   78,175   $   44,510    $    8,974
Interest Revenue                            $   10,986   $   10,799    $    1,694
Depreciation and Amortization               $   99,662   $  102,946    $  102,123
Regulatory Amortization                     $   18,219   $   14,287    $   15,080
Nuclear Fuel Amortization                   $   15,493   $   15,622    $   18,138
Interest Expense                            $   50,045   $   45,653    $   36,122
Operating Income Tax Expense                $   49,614   $   55,752    $   61,477
Capital Expenditures, net                   $  109,962   $   78,599    $   96,206

Total Identifiable Assets                   $1,915,002   $1,925,809    $1,941,622

<CAPTION>

Regulated Gas                                   2000         1999          1998
-------------                                   ----         -----         ----
<S>                                        <C>          <C>           <C>
Operating Income                            $   22,801   $   19,343    $   10,393
Revenues from External Customers            $  322,412   $  278,659    $  274,540
Revenues from Intersegment Transactions     $    1,856   $      420    $      594
Interest Revenue                            $      413   $      315    $      424
Depreciation and Amortization               $   12,448   $   12,548    $   12,867
Regulatory Amortization                     $      494   $      220    $    1,461
Interest Expense                            $   10,877   $    9,648    $    9,030
Operating Income Tax Expense/(Benefit)      $    9,837   $    8,580    $      (92)
Capital Expenditures, net                   $   30,405   $   24,746    $   28,075

Total Identifiable Assets                   $  462,470   $  438,290    $  433,029

<CAPTION>

Unregulated                                       2000         1999          1998
-----------                                       ----         ----          ----
<S>                                        <C>          <C>           <C>
Operating Income/(Loss)                     $    2,078   $      543    $   (2,460)
Revenues from External Customers            $  484,001   $  275,063    $   81,419
Interest Revenue                            $    1,198   $      398    $      158
Depreciation and Amortization               $    3,325   $    2,450    $      834
Goodwill Amortization                       $      749   $      751    $      278
Interest Expense                            $    2,571   $    2,171    $      916
Operating Income Tax Expense/(Benefit)      $      354   $      (50)   $   (1,255)
Capital Expenditures, net                   $    2,129   $    4,994    $    5,005

Total Assets                                $  179,010   $   90,580    $   59,946
</TABLE>
<PAGE>

                                       68

          There are intersegment transactions which occur between the Regulated
segments and the Unregulated segment.  These transactions are governed by
guidelines established in the Electric 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 Company
consolidated amounts as shown in the Consolidated Statement of Income.  This is
due to the elimination of certain intersegment revenues during consolidation.
Additionally, the operations of RGS Development are included in Other (Income)
and Deductions in the RGS Energy Group, Inc. Consolidated Statement of Income.
The operations of RGS Development are not significant.  The total assets
identified by operating segment do not equal the total Company consolidated
amounts as shown in the RGS Energy Group, Inc. Consolidated Balance Sheet.  This
is due to the elimination of certain intersegment transactions during
consolidation, and certain common assets unidentifiable by segment.
Intersegment eliminations result from intercompany receivables and payables from
affiliates.  A reconciliation follows:
<TABLE>
<CAPTION>

                                                    (thousands of dollars)
Revenues                                         2000          1999          1998
--------                                         ----          ----          ----
<S>                                          <C>           <C>           <C>
Regulated Electric                            $  721,737    $  698,745    $  687,100
Regulated Gas                                 $  322,412       278,659       274,540
Unregulated                                   $  484,001       275,063        81,419
                                              ----------    ----------    ----------

   Total                                      $1,528,150    $1,252,467    $1,043,059

Reported on Consolidated Income Statement     $1,448,119     1,207,537     1,033,491
                                              ----------    ----------    ----------

Difference to reconcile                       $   80,031    $   44,930    $    9,568

Intersegment Revenues
   Regulated Electric from Unregulated        $   78,175    $   44,510    $    8,974
   Regulated Gas from Unregulated             $    1,856    $      420    $      594
                                              ----------    ----------    ----------

   Total Intersegment                         $   80,031    $   44,930    $    9,568

     Assets

Regulated Electric                            $1,915,002    $1,925,809
Regulated Gas                                    462,470       438,290
Unregulated                                      179,010        90,580
Cash and Cash Equivalents,
   Regulated Operations                            4,851         6,443
Unamortized Debt Expense                          16,602        17,984
Other                                                617           367
Intersegment eliminations                        (12,754)      (16,599)
                                              ----------    ----------

Total Assets                                  $2,565,798    $2,462,874

</TABLE>
<PAGE>

                                       69



Note 5.     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, 2000 and 1999:

<TABLE>
<CAPTION>
                                                                                      (Millions)
                                                                     Pension Benefits            Other Benefits
                                                                     2000        1999             2000     1999
                                                                     ----        ----             ----     ----
<S>                                                                <C>         <C>               <C>      <C>
Change in benefit obligation
Benefit obligation at beginning of year                            $ 473.8     $ 516.8           $ 80.2   $ 99.0
Service cost                                                           6.3         6.9              1.0      1.1
Interest cost                                                         35.2        32.7              5.9      5.5
Plan amendments                                                       13.8        (0.5)             0.0      0.9
Actuarial (gain) loss                                                 11.5       (48.7)             2.7    (22.0)
Curtailments                                                           0.0        (3.5)             0.0      0.0
Special termination benefits                                           0.0         8.4              0.0      0.0
Benefits paid                                                        (41.3)      (38.3)            (4.5)    (4.3)
                                                                   -------     -------           ------   ------
Benefit obligation at end of year                                  $ 499.3     $ 473.8           $ 85.3   $ 80.2

Change in plan assets
---------------------
Fair value of plan assets at beginning of year                     $ 768.3     $ 706.4           $  0.0   $  0.0
Actual return on plan assets                                         (15.0)       99.5              0.0      0.0
Company contribution                                                   0.7         0.7              4.5      4.3
Benefits paid                                                        (41.3)      (38.3)            (4.5)    (4.3)
                                                                   -------     -------           ------   ------
Fair value of plan assets at end of year                           $ 712.7     $ 768.3           $  0.0   $  0.0
                                                                   =======     =======           ======   ======


Funded status                                                      $ 213.4     $ 294.5           $(85.3)  $(80.2)
Unrecognized actuarial (gain) loss                                  (260.9)     (352.5)            (8.0)   (10.8)
Unrecognized prior service cost                                       20.7         8.6             11.5     12.6
Unrecognized net transition obligation                                 0.3         0.8             27.3     29.8
                                                                   -------     -------           ------   ------
Accrued benefit                                                    $ (26.5)    $ (48.6)          $(54.5)  $(48.6)
                                                                   =======     =======           ======   ======


Weighted-average assumptions as of December 31
Discount rate                                                         7.25%       7.50%            7.25%    7.50%
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

                                                            2000      1999        1998    2000     1999     1998
                                                            ----      ----        ----    ----     ----     ----
<S>                                                       <C>      <C>         <C>       <C>     <C>      <C>
Components of net periodic (benefit) cost
-----------------------------------------
Service cost                                              $  6.3   $   6.9     $   7.0   $ 1.0   $  1.1   $  1.1
Interest cost                                               35.2      32.7        32.9     5.9      5.5      6.0
Expected return on plan assets                             (54.0)    (49.6)      (44.8)    0.0      0.0      0.0
Unrecognized transition obligation                           0.5       0.5         0.5     2.5      2.5      2.8
Amortization of prior service                                1.7       0.8         0.9     1.1      1.0      0.6
Recognized actuarial (gain) loss                           (11.0)     (5.5)       (4.3)   (0.1)     0.0      0.0
                                                          ------   -------     -------   -----   ------   ------
Net periodic (benefit) cost                               $(21.3)  $ (14.2)    $  (7.8)  $10.4   $ 10.1   $ 10.5
                                                          ======   =======     =======   =====   ======   ======

</TABLE>

     In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits on a defined dollar basis.  In 2000, the
health care benefit consists of a contribution of up to $230 per retiree per
month towards the cost of a group health policy provided by the Company.  The
life insurance benefit consists of a Basic Group Life benefit, covering
substantially all employees, providing a death benefit equal to one-half of the
retiree's final pay.

     In addition 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 2000, 1999, and 1998 were $3.1
million, $2.8 million, and $2.5 million, respectively.
<PAGE>

                                       70

     During 1999, a generation plant was shut down creating a staff reduction of
36 employees, resulting in a net curtailment charge of  $4.9 million, including
$8.4 million cost of special termination benefits provided to affected employees
offset by a curtailment gain of  $3.5 million.  Pursuant to the Company's
settlement agreement, this charge has been deferred.


Note 6.  LONG-TERM DEBT

FIRST MORTGAGE BONDS OF RG&E

<TABLE>
<CAPTION>

                                                                                 (Thousands of  Dollars)
                                                                                     Principal Amount
                                                                                       December 31
%                             Series                           Due                   2000        1999
-                             ------                           ---                   ----        ----
<S>                           <C>                              <C>            <C>          <C>
9 3/8                         PP                               Apr.  1, 2021     $100,000    $100,000
8 1/4                         QQ                               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                                                           Jan. 14, 2000           --      30,000
7.15                                                           Feb. 10, 2003       39,000      39,000
7.13                                                           Mar.  3, 2003        1,000       1,000
7.64                                                           Mar. 15, 2023       33,000      33,000
7.66                                                           Mar. 15, 2023        5,000       5,000
7.67                                                           Mar. 15, 2023       12,000      12,000
6.375                                                          July 30, 2003       40,000      40,000
7.45                                                           July 30, 2023       40,000      40,000
5.84                                                           Dec. 22, 2008       50,000      50,000
7.60                                                           Oct. 27, 2009      100,000     100,000
                                                                                 --------  ----------
                                                                                 $580,500    $610,500
Net bond discount                                                                    (368)       (430)
Less:  Due within one year                                                                     30,000
                                                                                 --------    --------
Total                                                                            $580,132    $580,070
                                                                                 ========    ========

</TABLE>

(a) The 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 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 RG & E.  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.

     The First Mortgage provides security for the bonds through a first lien on
substantially all the property owned by RG&E (except cash and accounts
receivable).  Sinking and improvement fund requirements aggregate $0.3 million
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.

     Sinking fund requirements and bond maturities during the next five years
are $100 million in 2002, and $80 million in 2003.
<PAGE>

                                       71

PROMISSORY NOTES AND OTHER

<TABLE>
<CAPTION>
                                                                (Thousands of Dollars)
                                                                      December 31
Issued                                  Due Date                    2000           1999
------                                  --------                    ----           ----
<S>                                    <C>                     <C>            <C>
September 2, 1998(a)                    September 1, 2033       $ 25,500       $ 25,500
August 19, 1997(a)                      August 1, 2032           101,900        101,900
December 1, 1998(b)                     March 31, 2014            88,530         92,311
                                                                --------       --------
Total                                                           $215,930       $219,711
Less:  RG&E Due within one year                                    4,227          3,781
                                                                --------       --------
Total RG&E                                                      $211,703       $215,930
August 3, 1998(c)                       August 3, 2005            17,545         21,054
November, 2000 (d)                      November, 2005            13,617             --
Other Long Term Debt of Subsidiaries                               8,730          2,273
                                                                --------       --------
        Total                                                   $251,595       $239,257
Less:  RGS Due within one year                                     7,868          3,862
                                                                --------       --------
Total  RGS                                                      $243,728       $235,395
</TABLE>

(a)  Issued in connection with NYSERDA's Pollution Control Revenue Bonds.
     Payment of the principal of, and interest on the Series A Bonds is
     guaranteed under a Bond Insurance Policy by MBIA Insurance Corporation.
     RG&E 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.

(b)  The Promissory Note was issued in connection with the Kamine Global
     Settlement Agreement and is collateralized by a mortgage, the lien for
     which is subordinate to the lien of the First Mortgage.  During 1999 and
     2000, RG&E made payments totaling $9.6 million for each year.  The Company
     expects to make future payments totaling $10.6 million per year.

(c)  The Promissory Note was issued in connection with the acquisition of
     Griffith by Energetix and is secured by a pledge of the stock of Griffith.
     RGS has made a financial guarantee on behalf of Energetix which obligates
     RGS in the event of a default by Energetix in payments under the Note.
     Beginning in 1998 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.

(d)  The Promissory Note was issued in connection with the acquisition of
     Burnwell by Griffith.  RGS has made a financial guarantee on behalf of
     Griffith which obligates RGS in the event of a default by Griffith.
     Beginning in 2001, payments of principal are made in five annual
     installments and interest accrues at the rate of 8 % per year.

     Based on an estimated borrowing rate at year-end 2000 of 6.88% for long-
term debt with similar terms and average maturities (11 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $863 million at December 31, 2000.

     Based on an estimated borrowing rate at year-end 1999 of 7.60% for long-
term debt with similar terms and average maturities (11 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $829 million at December 31, 1999.
<PAGE>

                                       72


Note 7.  PREFERRED AND PREFERENCE STOCK OF RG&E

<TABLE>
<CAPTION>
                                                       Par     Shares       Shares
Type by Order of Seniority                            Value  Authorized  Outstanding
--------------------------                            -----  ----------  ------------
<S>                                                   <C>    <C>         <C>
Preferred Stock (cumulative)                           $100   2,000,000      720,000*
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, 2000         2000         1999  (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.


B.   PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:

     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.

     At December 31, 2000  and 1999 there were 250,000 shares of Series V, 6.60%
preferred stock shares outstanding with a value of $25,000,000.

     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 2000 of 5.46% for Preferred
Stock, subject to mandatory redemption, with similar terms and average
maturities (7.25 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $27 million at December 31,
2000.

     Based on an estimated dividend rate at year-end 1999 of 6.40% for Preferred
Stock, subject to mandatory redemption, with similar terms and average
maturities (8.25 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $26 million at December 31,
1999.


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 1,436,700 and 1,435,600 of the shares were
purchased in 2000 and 1999 respectively.
<PAGE>

                                       73

     COMMON STOCK. At December 31, 2000, there were 100,000,000 shares of 1 cent
par value Common Stock authorized, of which 34,577,426 were outstanding. No
shares of Common Stock are reserved for warrants, conversions, or other rights.
There were 1,883,854 shares of Common Stock reserved and unissued for employees
under the 1996 Performance Stock Option Plan, as further described below.

<TABLE>
<CAPTION>
                                         RGS           RGS          RG&E         RG&E
                                        Shares       Amount        Shares       Amount
                                     Outstanding   (Thousands)  Outstanding   (Thousands)
                                     ------------  -----------  ------------  -----------
<S>                                  <C>           <C>          <C>           <C>

Balance, December 31, 1998            37,378,813     $653,297    37,378,813     $653,297

RG&E Shares                          (38,885,813)               (38,885,813)
RGS Shares                            38,885,813                 38,885,813
Additional Paid in Capital                                486                        486
Repurchase Plan                       (1,435,600)     (36,819)    1,507,000      (36,819)
Decrease in Capital Stock Expense                          52                         52
                                                     --------                   --------

Balance, December 31, 1999            35,943,213     $617,016    38,885,813     $617,016

Shares Issued through Stock Plans         70,913        1,772
Additional Paid in Capital                                717
Repurchase Plan                       (1,436,700)     (33,986)                   (33,986)
Decrease in Capital Stock Expense                          50                         50
                                                     --------                   --------

Balance, December 31, 2000            34,577,426     $585,569    38,885,813     $583,080
</TABLE>

     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 1 cent 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 2000, the Board of Directors granted 267,576 options at an exercise
price of $20.50 per share. These options are exercisable for a period of 10
years, and vest three years after the options are granted. The average grant
date option fair value and exercise prices are $6.28 and $20.50 respectively.
None of these options were exercised during 2000, and are included in the
summary of stock option activity presented on the following page. During 2000,
70,913 shares were exercised from the 1997 grant date.

     In 1999, the Board of Directors granted 177,322 options at an exercise
price of $29.69 per share. These options are exercisable for a period of 10
years, and vest three years after the options are granted. The average grant
date option fair value and exercise prices are $9.11 and $29.69 respectively.
None of these options were exercised during 1999, and are included in the
summary of stock option activity presented on the following page.

     In 1998, the Board of Directors granted 27,984 options at an exercise price
of $33.91 per share and 15,157 options at an exercise price of $31.00 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.

     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.
<PAGE>

                                       74

     The weighted average contractual remaining life for all options issued is
7.3 years and exercise prices range from $19.06 to $33.91 at December 31, 2000.

     Compensation expense associated with the options granted is reflected in
2000, 1999 and 1998 net income.  The compensation expense associated with the
options granted was $1.1 million in 2000, $.5 million in 1999 and $.2 million in
1998.  The compensation expense was calculated using the shorter of the
anticipated or actual vesting period.  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 from 6.19% to
6.86% for 2000, 4.61% to 5.16% for 1999 and 5.54% to 5.65% for 1998, expected
dividend yield of 8.78% for 2000, 6.03% for 1999 and 9.44% for 1998 and expected
stock volatility of 18% for 2000, 19% for 1999 and 17% for 1998.  The fair value
estimate also includes an amount for the value of dividend rights associated
with each option.

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

<TABLE>
<CAPTION>
                                                        Weighted
                                                         Average
                                            Options   Exercise Price
                                          ----------  --------------
<S>                                       <C>         <C>

Options granted 1998                         43,141           $32.89
Options exercised                           (23,466)          $19.06
                                          ---------
Outstanding at 12/31/98                     563,651           $20.63
Vested at 12/31/98                          369,256           $19.45
Available for future grant at 12/31/98    1,402,000

Options granted 1999                        177,322           $29.69
Options forfeited                           (10,884)          $19.06
                                          ---------
Outstanding at 12/31/99                     730,089           $22.85
Vested at 12/31/99                          369,256           $19.45
Available for future grant at 12/31/99    1,224,678

Options granted 2000                        267,576           $20.50
Options exercised                           (70,913)          $19.06
                                          ---------
Outstanding at 12/31/00                     926,752           $21.77
Vested at 12/31/00                          298,343           $19.51
Available for future grant at 12/31/00      957,102

</TABLE>

<PAGE>

                                       75



Note 9.    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.

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

<TABLE>
<CAPTION>
                                                     2000     1999     1998
                                                   -------  -------  -------
<S>                                                <C>      <C>      <C>
(thousands of dollars except per share amounts)

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

Net Income Available to
     Common Shareholders                           $91,859  $89,497  $89,296

Average Shares                                      35,178   36,665   38,462

Per-Share Amount                                   $  2.61  $  2.44  $  2.32
                                                   =======  =======  =======

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

Effect of Dilutive Securities
     Stock Option Plan                                 103       92      138
                                                   -------  -------  -------

Net Income Available to
     Common Shareholders                           $91,859  $89,497  $89,296

Average Shares                                      35,281   36,757   38,600

Per-Share Amount                                   $  2.60  $  2.44  $  2.31
                                                   =======  =======  =======
</TABLE>

RGS had 202,402, 177,322 and 0 of antidilutive stock options at December 31,
2000, 1999 and 1998 respectively.
<PAGE>

                                       76


Note 10.  SHORT-TERM DEBT

     On December 31, 2000, RGS had total short-term debt outstanding of $122.4
million, comprised of RG&E short-term debt of $98.0 million and Energetix short-
term debt of $24.4 million. At December 31, 1999, RGS had total short-term debt
outstanding of $10.5 million, comprised entirely of Energetix short-term debt.
The weighted average interest rate on short-term debt outstanding at year-end
2000 was 6.94% for RG&E and 8.43% for Energetix.  The weighted average interest
rates for borrowings during 2000 and 1999 were 6.94% and 5.44% for RG&E and
7.47% and 5.95% for Energetix, respectively.

     RG&E has a $90 million revolving credit agreement which terminates on
December 31, 2001.  In order to be able to use this credit facility, RG&E
created a subordinate mortgage which secures borrowings under the revolving
credit agreement that might otherwise be restricted by this provision of its
Charter.  Outstandings under this facility were $65 million at December 31,
2000.  In addition to the $90 million credit facility, RG&E has two $25 million
unsecured revolving credit agreements which expire December 13, 2001 and January
18, 2002 respectively.  At December 31, 2000, there were no borrowings under
either unsecured facility.

     Griffith, a subsidiary of Energetix, has a $33 million revolving credit
agreement that terminates July 31, 2003.  Borrowings under this agreement are
secured by personal property of Griffith. In addition, RGS executed a credit
support agreement on behalf of Griffith that requires RGS to make principal and
interest payments on certain Griffith long-term debt obligations, should
Griffith not meet minimum financial covenants as required under its revolving
credit agreement.  Energetix has also made a financial guarantee on behalf of
Griffith that obligates Energetix in the event of a Griffith default.

     RG&E 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
RG&E's accounts receivable and totaled $23.0 million at December 31, 2000.  In
addition, RG&E has unsecured lines of credit totaling $27 million available from
several banks, at their discretion.  RG&E had $10.0 million outstanding on its
uncommitted facilities as of December 31, 2000.

     RG&E's Charter provides that it may not issue unsecured debt if immediately
after such issuance the total amount of unsecured debt outstanding would exceed
15 percent of its 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, 2000, RG&E would be able to incur approximately $116.9
million of additional unsecured debt under this provision.
<PAGE>

                                       77

Note 11.  INCOME TAXES

     The provision for income taxes is distributed between operating income 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 RGS Energy Group. Amounts for Rochester Gas & Electric are not materially
different.

<TABLE>
<CAPTION>
                                                         (Thousands of Dollars)
                                                       2000        1999       1998
<S>                                                  <C>        <C>        <C>
      OPERATING INCOME
Current:
   Federal                                            $51,038    $72,137    $70,541
   State                                               11,513          0          0
                                                      -------    -------    -------
     Total current expense                             62,551     72,137     70,541
Deferred:
  Federal                                              (1,213)    (7,884)    (9,156)
  State                                                (1,506)         0          0
                                                      -------    -------    -------
     Total deferred expense                            (2,719)    (7,884)    (9,156)

Income taxes attributable to operating income         $59,832    $64,253    $61,385

<CAPTION>
     OTHER INCOME                                        2000       1999       1998
<S>                                                  <C>          <C>        <C>
Current:
  Federal                                               8,392     (2,614)    (1,614)
  State                                                   207          0          0
                                                      -------    -------    -------
     Total current expense                              8,599     (2,614)    (1,614)
Deferred:
  Federal                                              (5,167)     5,703      4,562
  State                                                  (146)         0          0
  Deferred investment tax credit                       (2,141)    (4,223)    (2,432)
                                                      -------    -------    -------
     Total deferred expense                            (7,454)     1,480      2,130

Income taxes attributable to non-operating income     $ 1,145    $(1,134)   $   516

Total income tax expense                              $60,977    $63,119    $61,901
</TABLE>

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

<TABLE>
<CAPTION>
                                                                      (Thousands of Dollars)
                                                                    2000       1999       1998
<S>                                                              <C>        <C>        <C>
Net Income                                                        $ 95,559   $ 93,580   $ 94,138
Add: income tax expense                                             60,977     63,119     61,901
                                                                  --------   --------   --------

Income before income taxes                                        $156,536   $156,699   $156,039

Computed tax expense at statutory tax rate                        $ 54,788   $ 54,845   $ 54,614
Increases (decreases) in tax resulting from:
   State income tax expense, net of federal benefit                  6,544          0          0
   Difference between tax depreciation
     and amount deferred                                             3,503      7,103      9,366
   Deferred investment tax credit                                   (2,141)    (4,223)    (2,432)
   Miscellaneous items, net                                         (1,717)     5,394        353

Total income tax expense                                          $ 60,977   $ 63,119   $ 61,901

</TABLE>
<PAGE>

                                       78

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

<TABLE>
<CAPTION>
                                                                                     (Thousands of Dollars)
                                                                                    2000       1999       1998
<S>                                                                            <C>        <C>        <C>
FEDERAL & STATE
Nuclear decommissioning                                                         $(37,982)  $(28,811)  $(24,849)
Accelerated depreciation                                                         214,798    218,001    214,521
Deferred investment tax credit                                                    21,631     23,023     25,768
Depreciation previously flowed through                                           120,750    127,448    146,953
Pension                                                                          (12,306)   (21,503)   (20,161)
Deferred NYS deduction                                                           (12,594)         0          0
Other                                                                            (16,510)       536    (15,260)
                                                                                --------   --------   --------

Total                                                                           $277,787   $318,694   $326,972
</TABLE>

SFAS-109 "Accounting for Income Taxes" requires that a deferred tax liability 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 of Rochester
Gas & Electric and will be amortized consistent with the depreciation of these
accounts.  The net amount of the additional liability at December 31, 2000 and
1999 was $102 million and $129 million, respectively.  In conjunction with the
recognition of this liability, a corresponding regulatory asset was also
recognized.


Note 12.  COMMITMENTS AND OTHER MATTERS

CAPITAL EXPENDITURES

     The Company's 2001 construction expenditures program is currently estimated
at $164 million for RGS of which $161 million is for RG&E. The Company has
entered into certain commitments for purchase of materials and equipment in
connection with that program.

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 monitors
its activities in order to determine the impact of its activities on the
environment and to ensure compliance with various environmental requirements.
RGS has recorded a total liability of approximately $24.4 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.  RG&E 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.

     RG&E-OWNED ELECTRIC AND GAS WASTE SITE ACTIVITIES.  RG&E is conducting
proactive SIR efforts at eight RG&E-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 RG&E is conducting a program to
restore the other two sites. RG&E has recorded a liability of approximately
$21.9 million for SIR efforts at the eight RG&E-owned sites in the Rochester,
New York area.
<PAGE>

                                       79

     SUPERFUND AND NON-OWNED OTHER SITES.  RG&E has been or may be associated as
a potentially responsible party at nine sites not owned by it and has recorded
estimated liabilities of approximately $.5 million in connection with SIR
efforts at these sites.   RG&E has signed orders on consent for five of these
sites.

     GRIFFITH FACILITIES.  RGS's subsidiary, Energetix, acquired Griffith in
1998.   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 this review 35 sites were identified which
are currently undergoing evaluation and/or remediation. Using historical New
York State Department of Environmental Conservation (NYSDEC) remedial actions as
a guide, Energetix estimates the accrual of aggregate cleanup costs discounted
at 6.8 percent over the future five-year period for all active sites
approximates $1.3 million.

     In November 2000, Griffith acquired both Burnwell(R) Gas and the New York
Fuels Division of AllEnergy Marketing Company, L.L.C.  Energetix performed Phase
I and Phase II environmental investigations on all ten properties in the
Burnwell acquisition and identified ten items requiring some type of remedial
measures.  With regard to the AllEnergy acquisition, Energetix reviewed Phase I
and Phase II environmental reports provided by AllEnergy together with the
investigative reports prepared by independent consulting firms during the prior
two years.  As a result of certain identified environmental conditions a $1.5
million accrual has been established for AllEnergy.

     NEW YORK INITIATIVES. By letter dated May 25, 2000, the NYSDEC issued a
Notice of Violation ("NOV") to RG&E, asserting that certain "modifications" to
Russell and Beebee Stations during 1983-1987 resulted in a "significant increase
in the capacity to emit sulfur dioxide."  The NOV alleges that, as a result,
permits required by the federal Clean Air Act and the State Environmental
Conservation Law should have been obtained by RG&E prior to beginning the
"modifications."  The NOV asserts that RG&E may be liable for civil penalties of
up to $10,000 per day, per violation, as well as subjected to unspecified
injunctive relief.  The allegations in the NOV are similar to those being made
by the United States Department of Justice, on behalf of the United States
Environmental Protection Agency, in enforcement cases relating to a number of
electric utility coal-fired power plants in the midwest and southeast.  The NOV
invited RG&E to request an informal conference with the NYSDEC.  Since July
2000, RG&E has had several such informal meetings with the NYSDEC.  On the
merits of the allegation, RG&E does not believe it has engaged in prohibited
activities at either station.

  The Governor of New York directed the NYSDEC to require electric generators to
further reduce acid rain-causing emissions.  The Governor has proposed extending
the existing NOx control program under which RG&E's Russell Station operates to
a year-round program (it is currently in effect only for the five-month ozone
season).  In addition, the Governor has proposed that there be a targeted
reduction of approximately 50% in SO2 emissions below the existing Acid Rain
Phase II limits.  The state emission reductions would be phased-in beginning
January 1, 2003 and be complete by January 1, 2007.  Since this is only a
proposed change, and subject to review, comment, and modification, no accurate
estimate of its economic impact on RG&E can be made at this time.

OTHER MATTERS

     LEASE AGREEMENTS.  RG&E and Energetix lease a total of 20 properties for
administrative offices and operating activities and lease a number of vehicles.
The total lease obligations charged to operations was $5.6 million, $5.4 million
and $4.8 million in 2000, 1999 and 1998, respectively, including $1.7 million
and $1.5 million in 2000 and 1999, respectively, for Energetix.  RG&E's
estimated annual lease obligations for the years 2001-2005 will be $5.6 million,
$4.1 million, $3.3 million, $2.9 million and $2.6 million, respectively.
Energetix estimated annual lease obligations for the years 2001-2005 will be
$1.8 million, $1.4 million, $1.2 million, $0.7 million and $0.5 million,
respectively.  Commitments under operating leases after 2005 are not
significant.

  PURCHASE COMMITMENTS.  The Company has entered into electric and natural gas
purchase commitments with numerous suppliers.  Certain of these commitments
support fixed price offerings to retail electric and gas customers.
<PAGE>

                                       80

     GAS SUPPLY, STORAGE AND PIPELINE COMMITMENTS.  In connection with its
regulated gas business, RG&E has long-term commitments with a number of
interstate natural gas pipeline companies to provide transportation and storage-
related services.  The table below sets forth RG&E's estimated commitments at
December 31, 2000 for the next eight years based on current contractual volumes
and represent demand charges priced at current pipeline tariff rates:


Interstate Pipeline and Storage Commitments

<TABLE>
<CAPTION>
                 Year  $ in Thousands
-------------------------------------
<S>                    <C>
                 2001  $      59,670
                 2002  $      59,083
                 2003  $      59,083
                 2004  $      50,111
Thereafter until 2012  $     117,918
</TABLE>

With respect to firm gas supply commitments, RG&E currently contracts for gas
supply on a seasonal basis, so therefore, has no long-term gas supply
obligations.

     LONG TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER. As of January 1,
2001, RG&E had long-term contracts to purchase electric power from the New York
Power Authority:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
Facility                                                Expiration date of             Purchased capacity in    Estimated annual
                                                        contract                       MW                       capacity cost
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>                              <C>                   <C>
FitzPatrick nuclear facility                            one year's notice by             50                     $3,384,000
                                                        either party
--------------------------------------------------------------------------------------------------------------------------
Niagara - hydroelectric                                 2007                            100                     $1,200,000
 project
--------------------------------------------------------------------------------------------------------------------------
St. Lawrence - hydroelectric                            2007                             55                     $  660,000
 project
--------------------------------------------------------------------------------------------------------------------------
Blenheim - Gilboa - pumped                              2002                            150                     $4,140,000
 storage generating station
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

The purchased capacities shown above are based on the contracts currently in
effect.  The estimated annual capacity costs are subject to price escalation and
are exclusive of applicable energy charges.  The total cost of purchases under
these contracts, was approximately, in millions, $13.9, $12.1, and $11.5 for the
years 2000, 1999, and 1998 respectively.  RG&E continues to have a contract with
NYPA to purchase for resale power for NYPA's Power for Jobs customers.
<PAGE>

                                       81

INTERIM FINANCIAL DATA

In the opinion of RGS and RG&E, 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
RGS and RG&E's business and the availability of surplus electricity.  The sum of
the quarterly earnings per share may not equal the annual 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>

RGS
---
December 31, 2000            $437,259      $32,842      $23,827        $22,902      $ .66      $ .66
September 30, 2000            314,304       26,962       14,095         13,170        .38        .38
June 30, 2000                 310,705       35,481       18,295         17,369        .49        .49
March 31, 2000                385,851       53,689       39,342         38,418       1.07       1.07

December 31, 1999/1/         $325,788      $33,982      $24,605        $23,681      $ .65      $ .65
September 30, 1999/1/         279,853       29,528       16,891         15,964        .44        .44
June 30, 1999/1/              275,805       27,219       14,822         13,706        .37        .37
March 31, 1999/1/             326,091       50,189       37,262         36,146        .97        .97

RG&E
----
December 31, 2000            $303,047      $31,535      $23,111        $22,186          -          -
September 30, 2000            223,686       27,139       14,796         13,871          -          -
June 30, 2000                 226,566       36,097       19,279         18,354          -          -
March 31, 2000                290,850       52,179       38,343         37,418          -          -

December 31, 1999            $249,204      $33,737      $24,696        $23,394          -          -
September 30, 1999            239,348       29,990       17,708         17,159          -          -
June 30, 1999                 275,805       27,219       14,822         13,706          -          -
March 31, 1999                326,091       50,189       37,262         36,146          -          -

December 31, 1998            $286,507      $22,173      $15,015        $14,088      $ .37      $ .37
September 30, 1998            253,750       35,128       25,213         23,908        .62        .62
June 30, 1998                 210,724       22,620       15,655         14,350        .37        .37
March 31, 1998                282,510       48,145       38,255         36,950        .95        .95
</TABLE>

/1/    Reclassified for comparative purposes.

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

     None
<PAGE>

                                       82

                                    PART III

Information required by Items 10-14 with respect to RG&E has been omitted
pursuant to General Instruction I(2)(c).  Information required by Items 10-14
with respect to RGS is described below.


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 RGS's Annual Meeting of Shareholders
to be held on April 25, 2001, 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 RGS's
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 for RGS 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 RGS'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 heading "Security Ownership of Management" in RGS'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 RGS'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,
RGS will file with the Commission a definitive proxy statement pursuant to
Regulation 14A which involves the election of directors.  RGS's definitive proxy
statement dated March 12, 2001 will be filed with the Securities and Exchange
Commission prior to April 30, 2001. 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
25, 2001 is not deemed to be filed as part of this Report.
<PAGE>

                                       83

                                    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.

          RGS Consolidated Statement of Income for each of the three years ended
          December 31, 2000, 1999 and 1998.

          RGS Consolidated Statement of Retained Earnings for each of the three
          years ended December 31, 2000, 1999 and 1998.

          RGS Consolidated Balance sheet at December 31, 2000 and 1999.

          RGS Consolidated Statement of Cash Flows for each of the three years
          ended December 31, 2000, 1999 and 1998.

          RG&E Consolidated Statement of Income for each of the three years
          ended December 31, 2000, 1999 and 1998.

          RG&E Consolidated Statement of Retained Earnings for each of the three
          years ended December 31, 2000, 1999 and 1998.

          RG&E Consolidated Balance sheet at December 31, 2000 and 1999.

          RG&E Consolidated Statement of Cash Flows for each of the three years
          ended December 31, 2000, 1999 and 1998.

          RGS and RG&E Notes to Consolidated Financial Statements.



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

          For each of the three years ended December 31, 2000, 1999 and 1998.

          Schedule II - Valuation and Qualifying Accounts of RGS and RG&E.



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

 (b)      Reports on Form 8-K

          RGS and RG&E:

          A report was filed on December 14, 2000 in connection with RG&E
          selling its interest in Nine Mile Point 2 Nuclear Plant to
          Constellation Nuclear, a wholly owned subsidiary of Constellation
          Energy
<PAGE>

                                       84

                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

                              (Thousands of Dollars)

<TABLE>
<CAPTION>

FOR THE YEAR ENDED DECEMBER 31, 1998 - RG&E


                                                    Additions   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
Nuclear refueling outage accruals              914     12,384                            13,298

<CAPTION>
FOR THE YEAR ENDED DECEMBER 31, 1999

                                                     Additions  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>
RG&E Reserves for:
Uncollectible accounts                     $26,554    $ 7,080                $   269    $33,365
Materials & supplies obsolescence            2,190                               636      1,554
Nuclear refueling outage accruals           13,298     10,388                 17,022      6,664

RGS Reserves for:
Uncollectible accounts                     $26,554    $ 7,080       $406     $    14    $34,026
Materials and supplies obsolescence          2,190                               636      1,554
Nuclear refueling outage accruals           13,298     10,388                 17,022      6,664

<CAPTION>
FOR THE YEAR ENDED DECEMBER 31, 2000

                                                     Additions   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>
RG&E Reserves for:
Uncollectible accounts                     $33,365    $   117                           $33,482
Materials and supplies obsolescence          1,554      1,100                    390      2,264
Nuclear refueling outage accruals            6,664      7,558                 11,324      2,898

RGS Reserves for:
Uncollectible accounts                     $34,026    $   524                           $34,550
Materials and supplies obsolescence          1,554      1,100                    390      2,264
Nuclear refueling outage accruals            6,664      7,558                 11,324      2,898
</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 1998
was $11.8 million in 1999 was $11.9 million and in 2000 was $9.2 million.  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. In 1999, the amount charged to
other accounts reflects consolidation of Energetix/Griffith reserve for
uncollectibles.

The Company levelizes estimated incremental non-fuel expenses due to planned
refueling outages at its two nuclear power plants.  Such costs are levelized
between refueling outages.
<PAGE>

                                       85


LIST OF EXHIBITS


Exhibit 2-1    Asset Purchase Agreement regarding the sale of RG&E's interest in
               Nine Mile Point 2 Nuclear Plant to Constellation Nuclear dated as
               of December 11, 2000

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 RG&E, 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 3-4*   Certificate of Incorporation of RGS Energy Group, Inc. filed with
               the Secretary of State of the State of New York on November 5,
               1998.  (Filed as Exhibit 3-1 in Registration Statement No. 333-
               67427)

Exhibit 3-5*   By-Laws of RGS Energy Group, Inc. (Filed as Exhibit 3-2 in
               Registration Statement No. 333-67427)

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 RG&E, 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*   Certificate of Incorporation of RGS Energy Group, Inc. filed with
               the Secretary of State of the State of New York on November 5,
               1998.  (Filed as Exhibit 3-1 in Registration Statement No. 333-
               67427)

Exhibit 4-5*   By-Laws of RGS Energy Group, Inc. (Filed as Exhibit 3-2 in
               Registration Statement No. 333-67427)

Exhibit 4-6*   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 4-7*   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 RG&E,
               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 RG&E, Central Hudson Gas & Electric Corporation,
               Orange and Rockland Utilities,
<PAGE>

                                       86


               Inc. and Niagara Mohawk Power Corporation. (Filed in Registration
               No. 2-56351, as Exhibit 5-R in June 1976)

Exhibit 10-3*  Agreement dated February 5, 1980 between RG&E and the Power
               Authority of the State of New York.  (Filed as Exhibit 10-10 in
               February 1990 on Form 10-K for the year ended December 31, 1989,
               SEC File No. 1-672)

Exhibit 10-4*  Agreement dated March 9, 1990 between RG&E 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 10-5*  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 10-6*  (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 10-7*  (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 10-8*  (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 10-9*  (A)  RGS Energy Group, Inc. Executive Incentive Plan, Restatement
                    of January 1, 1999. (Filed as Exhibit 10 in November 1999 on
                    Form 10-Q for the quarter ended September 30, 1999, SEC File
                    No. 0-30338)

Exhibit 10-10* (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 10-11* (A)  Agreement, effective April 26, 2000, between RGS, RG&E and
                    Thomas S. Richards. (Filed as Exhibit 10-2 in August 2000 on
                    Form 10-Q for the quarter ended June 30, 2000, SEC File No.
                    0-30338)

Exhibit 10-12* (A)  Agreement, effective April 26, 2000, between RGS, RG&E and
                    Paul C. Wilkins. (Filed as Exhibit 10-5 in August 2000 on
                    Form 10-Q for the quarter ended June 30, 2000, SEC File No.
                    0-30338)

Exhibit 10-13* (A)  Agreement, effective April 26, 2000, between RGS, RG&E and
                    J. Burt Stokes. (Filed as Exhibit 10-3 in August 2000 on
                    Form 10-Q for the quarter ended June 30, 2000, SEC File No.
                    0-30338)

Exhibit 10-14* (A)  Agreement, effective April 26, 2000, between RGS, Energetix
                    and Michael J. Bovalino. (Filed as Exhibit 10-1 in August
                    2000 on Form 10-Q for the quarter ended June 30, 2000, SEC
                    File No. 0-30338)

Exhibit 10-15* (A)  Agreement, effective April 26, 2000, between RGS, RG&E and
                    Michael T. Tomaino. (Filed as Exhibit 10-4 in August 2000 on
                    Form 10-Q for the quarter ended June 30, 2000, SEC File No.
                    0-30338)

Exhibit 10-16*      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)
<PAGE>

                                       87


Exhibit 10-17* (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 10-18*      Global Settlement Agreement as amended October 29, 1998
                    between RG&E, General Electric Capital Corporation and
                    Kamine/Besicorp Allegany L.P. and other Kamine affiliates.
                    (Filed as Exhibit 10-21 in February 1999 on Form 10-K for
                    the year ended December 31, 1998, SEC File No. 1-672)

Exhibit 10-19* (A)  RG&E Supplemental Executive Retirement Program effective
                    January 1, 1999. (Filed as Exhibit 10-1 in March 2000 on
                    Form 10-Q for the quarter ended March 31, 2000, SEC File No.
                    1-672)

Exhibit 10-20* (A)  RG&E Supplemental Retirement Benefit Program effective July
                    1, 1999. (Filed as Exhibit 10-2 in March 2000 on Form 10-Q
                    for the quarter ended March 31, 2000, SEC File No. 1-672)

Exhibit 10-21       Revenue Sharing Agreement regarding the sale of RG&E's
                    interest in Nine Mile Point 2 Nuclear Plant to Constellation
                    Nuclear dated as of December 11, 2000

Exhibit 10-22       Power Purchase Agreement regarding the sale of RG&E's
                    interest in Nine Mile Point 2 Nuclear Plant to Constellation
                    Nuclear dated as of December 11, 2000

Exhibit 21          Subsidiaries of RGS

Exhibit 23          Consent of PricewaterhouseCoopers LLP, independent
                    accountants


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

     RG&E 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>

                                       88

                                  SIGNATURES


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


                                    RGS ENERGY GROUP, INC.

                                    ROCHESTER GAS AND ELECTRIC CORPORATION

                                         /s/ Thomas S. Richards
                                    By: _______________________________
                                            (Thomas S. Richards)
                                            Chairman, President and
                                            Chief Executive Officer

DATE:  February  , 2000


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


SIGNATURE                     TITLE (RGS and RG&E         DATE
---------                     -----                       ----
                              unless otherwise noted)

Principal Executive Officer:


 /S/ THOMAS S. RICHARDS        Chairman, President and    February 14, 2001
-----------------------        Chief Executive Officer
 (Thomas S. Richards)


Principal Financial Officer:


 /S/ MARK KEOGH               Treasurer of RGS;           February 14, 2001
----------------------        Vice President and
   (Mark Keogh)               Treasurer of RG&E



Principal Accounting Officer:


 /S/ WILLIAM J. REDDY         Controller of RGS;          February 14, 2001
--------------------------    Vice President and
   (William J. Reddy)         Controller of RG&E


<PAGE>

                                       89


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


Directors of RGS and RG&E:


/S/   ANGELO J. CHIARELLA     Director                February 14, 2001
---------------------------
     (Angelo J. Chiarella)


/S/   ALLAN E. DUGAN          Director                February 14, 2001
---------------------------
     (Allan E. Dugan)


/S/    MARK B. GRIER          Director                February 14, 2001
----------------------------
     (Mark B. Grier)


/S/   SUSAN R. HOLLIDAY       Director                February 14, 2001
---------------------------
     (Susan R. Holliday)


/S/   JAY T. HOLMES           Director                February 14, 2001
---------------------------
     (Jay T. Holmes)


/S/    G. JEAN HOWARD         Director                February 14, 2001
----------------------------
     (G. Jean Howard)


/S/   SAMUEL T. HUBBARD, JR   Director                February 14, 2001
---------------------------
     (Samuel T. Hubbard, Jr.)


/S/CLEVE L. KILLINGSWORTH,JR. Director                February 14, 2001
-----------------------------
(Cleve L. Killingsworth, Jr.)


/S/   ROGER W. KOBER          Director                February 14, 2001
---------------------------
     (Roger W. Kober)


/S/   CORNELIUS J. MURPHY     Director                February 14, 2001
---------------------------
     (Cornelius J. Murphy)


/S/   CHARLES I. PLOSSER      Director                February 14, 2001
---------------------------
     (Charles I. Plosser)


/S/   THOMAS S. RICHARDS      Director                February 14, 2001
---------------------------
     (Thomas S. Richards)