<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, 2001
                               ----------------------
                                      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:

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

RGS Energy Group, Inc.
Common stock, $0.01 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, 2002 the aggregate market value of the voting stock of RGS
Energy Group, Inc. ("RGS") held by nonaffiliates was approximately:
$1,303,349,179

  On January 1, 2002 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, 2002, (i) RGS had outstanding
34,663,542 shares of Common Stock ($.01 par value), and (ii) RG&E had
outstanding 34,506,513 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 Instruction (I)(2) of Form 10-K.
<PAGE>

                          Abbreviations and Glossary

<TABLE>
<S>                               <C>
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.

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 RGS

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

ESCO                               Energy Service Company

FERC                               Federal Energy Regulatory Commission

Gas Rates and Restructuring        The gas rates and restructuring settlement approved by the PSC on February 28, 2001 based on a
Settlement                         settlement agreement between RG&E, the PSC Staff and other parties

Ginna Plant                        R. E. Ginna Nuclear Power Plant which is wholly owned by RG&E

Griffith                           Griffith Oil Co. Inc. - 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

Nine Mile Two                      Nine Mile Point Nuclear Plant Unit No. 2 of which RG&E owned a 14% share until November 7, 2001

NYISO                              New York Independent System Operator

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 RGS

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
</TABLE>
<PAGE>

                            RGS ENERGY GROUP, INC.
                    ROCHESTER GAS AND ELECTRIC CORPORATION

                               Table of Contents

<TABLE>
<CAPTION>
                                                                     Page
                                                                     ----
<S>                                                                 <C>
FILING FORMAT                                                             1

FORWARD-LOOKING STATEMENTS                                                1

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




Part I
------

Item 1         Business                                                   1
Item 2         Properties                                                22
Item 3         Legal Proceedings                                         24
Item 4         Submission of Matters to a Vote of Security Holders       25
Item 4A        Executive Officers of the Registrant                      26



Part II
-------

Item 5         Market for the Registrant's Common Equity and
                  Related Stockholder Matters                            28
Item 6         Selected Financial Data                                   30
Item 7         Management's Discussion and Analysis of Financial
                  Condition and Results of Operations                    33
Item 7A        Quantitative and Qualitative Disclosures about
                  Market Risk                                            51
Item 8         Financial Statements and Supplementary Data               53
Item 9         Changes in and Disagreements with Accountants on
                  Accounting and Financial Disclosure                    86


Part III
--------

Item 10        Directors and Executive Officers of the Registrant        87
Item 11        Executive Compensation                                    89
Item 12        Security Ownership of Certain Beneficial Owners and
                  Management                                             93
Item 13        Certain Relationships and Related Transactions            93

Part IV
-------

Item 14        Exhibits, Financial Statement Schedules and Reports
                  on Form 8-K                                            95


               Signatures                                               100
</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.



     CAPTION                                            PAGE
     -------                                            ----

     Corporate Structure                                    1
     Electric Operations                                    3
     Gas Operations                                         5
     Unregulated Operations                                 6
     Regulatory Matters                                     6
     Environmental Quality Control                         15
     Financing and Capital Requirements Program            17
     Research and Development                              19
     Operating Statistics                                  20


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.

     On February 20, 2001, RGS announced that it had entered into an Agreement
and Plan of Merger, dated as of February 16, 2001, with Energy East Corporation.
RGS anticipates that the Merger will be consummated in the second quarter of
2002. For more information see "Merger Agreement" presented under Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
<PAGE>

                                       2

     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, 2001 RG&E had 1,993
employees.

     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, and Bausch & Lomb Incorporated.

     Energetix, Inc.  Energetix was formed in 1998 to market electricity and
natural gas services throughout upstate and central New York.  In August 1998,
Energetix expanded into the liquid fuels business by acquiring Griffith, the
second largest distributor of liquid fuels in New York State.  Since it was
acquired by Energetix, Griffith has expanded through the acquisition of ten
liquid-fuel companies.

     RGS Development Corporation.  In 1998, the Company formed RGS Development
to pursue unregulated business opportunities in the energy marketplace.  Through
December 31, 2001, 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, RG&E, and Energetix
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>

                                        2001                                2000                                1999
                               -----------------------------------------------------------------------------------------------------
                                  RGS              RG&E               RGS              RG&E               RGS              RG&E
                              ------------   ---------------   ---------------   ---------------   ---------------   ---------------
<S>                           <C>            <C>               <C>               <C>               <C>               <C>
Electric                         47.6%             70.0%             49.8%             69.1%             57.9%             64.1%
Gas                              20.3              30.0              22.3              30.9              23.1              25.5
Unregulated                      32.1           -------              27.9            ------              19.0              10.4
                                -----           -------             -----            ------             -----             -----

                                100.0%            100.0%            100.0%            100.0%            100.0%            100.0%
</TABLE>

<PAGE>

                                       3

REGULATED ELECTRIC OPERATIONS

     Overview.  RG&E is a regulated public utility engaged in the generation,
purchase, transmission and distribution of electricity in parts of nine counties
including and surrounding the City of Rochester, New York.  RG&E satisfies its
customers electricity needs through its nuclear, coal-fired, gas-fired and
hydroelectric generation facilities and electricity purchased from the New York
Power Authority ("NYPA"), Constellation Nuclear and the wholesale energy market.

     Electric System.  The total net generating capacity of RG&E's electric
system is 875,000 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, 44,000 Kw of firm power from NYPA's contractual
share of the 821,000 Kw FitzPatrick Nuclear Power Plant near Oswego, New York,
and approximately 144,000 Kw of unit contingent power from Constellation's
1,143,000 Kw Nine Mile Two Nuclear Power Plant near Oswego, New York.  RG&E's
all time net peak load of 1,544,000 Kw occurred on August 9, 2001.

     The percentages of electricity actually generated and purchased by RG&E,
net of the energy generated and used at the pumped storage facility for the
years 1998-2001 are as follows:

<TABLE>
                                            2001            2000            1999
                                      ------------------------------------------------------
                                        RGS     RG&E    RGS     RG&E    RGS     RG&E     1998
                                        -----   -----   -----   -----   -----   -----   -----
<S>                                     <C>     <C>     <C>     <C>     <C>     <C>     <C>
Sources of Generated Energy:
Nuclear                                   53.9%   54.2%   53.2%   54.1 % 52.2%   54.9%   59.5%
Fossil                                    18.7    18.8    16.7    17.0    18.7    19.6    22.0
Hydro and Other                            1.3     1.4     2.2     2.3     1.5     1.6     2.1
                                        ------  ------  ------  ------  ------  ------  ------

Total Generated                           74.0    74.4    72.1    73.4    72.4    76.1    83.6
Purchased                                 26.0    25.6    27.9    26.6    27.6    23.9    16.4
                                        ------  ------  ------  ------  ------  ------  ------

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

     Generating Facilities.  At December 31, 2001, RG&E's primary generating
facilities are its Ginna nuclear power plant and two fossil fuel generating
stations - the Russell and Allegany Stations.  In terms of capacity these
comprise 55%, 29% and 7%, respectively, of the Company's current electric
generating system.  The remaining 9% of the Company's generating capacity comes
from several smaller hydro and peaking generating units. On November 7, 2001,
RG&E sold its interest in the Nine Mile Two nuclear generating facility as
discussed below under the heading "Sale of Interest in Nine Mile Two".

     RG&E has three licensed hydroelectric generating stations with an aggregate
generating capacity of 47 megawatts.

     Fuel Supply

     Nuclear.  Generally, the nuclear fuel cycle consists of the following: (a)
the procurement of uranium concentrate (yellowcake), (b) the conversion of
uranium concentrate to uranium hexafluoride, (c) the enrichment of the uranium
hexafluoride, (d) the fabrication of fuel assemblies, (e) the utilization of the
fabricated nuclear fuel assemblies in generating station reactors and (f) the
appropriate storage or disposition of spent fuel and radioactive wastes.

     The current Ginna Plant license expires in 2009.  Permission to operate
beyond that date could possibly be obtained.  The following arrangements for
nuclear fuel materials and services for the Ginna Plant have been made to permit
operation of the plant through the years indicated:

     Uranium Concentrate A contract is in place, which supplies 838,699 pounds
     -------------------
     of uranium concentrate between 2002 and 2004. The remaining material is
     scheduled for delivery in 2002 - 2004 and covers all of RG&E's uranium
     requirements through 2005.
<PAGE>

                                       4

     Conversion A contract is in place covering all of the Ginna Plant's
     ----------
     conversion requirements for 2002. Additional requirements are expected to
     be filled from market purchases or a new long-term contract.

     Enrichment and Fabrication  RG&E has long-term contracts for nuclear fuel
     --------------------------
     enrichment services and fuel fabrication services which assure provision of
     all of the Ginna Plant's requirements through the end of the plant's
     current operating license in 2009.

     See Note 2 of the Notes to Financial Statements under Item 8 for additional
information regarding nuclear fuel disposal costs, nuclear plant decommissioning
and Department of Energy ("DOE") uranium enrichment facility decontamination and
decommissioning.

     Coal. RG&E's 2002 coal requirements are expected to be approximately
580,000 tons.  RG&E's coal supply portfolio contains both spot and term
agreements with multiple suppliers. In 2001, 52% of its requirements were
purchased under contract and 48% 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 is in compliance with New York State regulations.

     Sale of Interest in Nine Mile Two.  On November 7, 2001, RG&E sold its
ownership interest in Nine Mile Two to Constellation Nuclear.  The purchase
price for RG&E's interest was $101.0 million, $50.5 million of which was paid in
cash at the closing and $50.5 million of which will be paid in five equal annual
principal installments plus interest at a rate of 11 percent pursuant to a five
year promissory note.  Principal and interest payments under the promissory note
will total approximately $67.1 million unless the note is pre-paid.  In
addition, RG&E received approximately $1.9 million cash for the sale of its
share of certain transmission assets related to the Nine Mile Two facility.

     At November 7, 2001, the net book value of RG&E's 14 percent interest in
the Nine Mile Two generating facility was approximately $348.8 million.  RG&E
also had investments in fuel of approximately $6.0 million, transmission and
distribution facilities of $3.3 million, materials and supplies inventory of
$6.9 million, and construction work in progress of $7.6 million.

     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 completion of the term 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 allocated 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 the closing, RG&E's pre-existing decommissioning funds were transferred
to Constellation Nuclear and Constellation Nuclear assumed RG&E's obligation to
decommission Nine Mile Two.

     Nuclear Liability Insurance.  The Price-Anderson Amendments to the Atomic
Energy Act establish a federal program insuring against public liability in the
event of a nuclear incident at a licensed U. S. reactor.  Under the program,
claims would first be met by insurance which licensees are required to
<PAGE>

                                       5

carry in the maximum amount available (currently $200.0 million). If claims
exceed that amount, licensees are subject to a retrospective assessment up to
$88.1 million per licensed facility for each nuclear incident, payable at a rate
not to exceed $10.0 million per incident per year. Currently, 106 licensed
reactors are included in the Secondary Financial Protection plan. At this level,
the statutory limit of liability is $9.5 billion. These assessments are subject
to periodic inflation indexing and a surcharge for New York State premium taxes.

     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. Effective January 1, 1998, an industry-wide policy was
issued that applies to claims reported after that date. This policy has a limit
of $200.0 million (reinstated annually if certain conditions are met) for
radiation injury claims against RG&E, or against other licensees who are insured
by this policy. If these claims exceed the $200.0 million limit of primary
coverage, the provisions of the Price-Anderson Amendments would apply. Since
reserves for outstanding claims under former policies may 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 of the assessments could be up to $3.1 million in
any one year.

     Nuclear Property Insurance.  RG&E purchases nuclear property insurance from
Nuclear Electric Insurance Limited ("NEIL").  Total limits for property
insurance are $2.3 billion.  NEIL also provides extra expense insurance for the
cost of replacement power during certain prolonged accidental outages of nuclear
generating units. The limit of indemnity at the Ginna Plant after a 12 week
period from the initial incident is $2.7 million for each of the first 52 weeks
and $2.2 million for each of the next 110 weeks, for total replacement power
insurance of $378.0 million.  The NEIL policies include a retrospective premium
adjustment.  In the event an insuring program's losses exceeded its other
resources available to pay claims, RG&E could be subject to maximum assessments
for any one policy year of approximately $3.3 million and $13.3 million in the
event of losses under the replacement power and property damage coverages,
respectively.

REGULATED GAS OPERATIONS

     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.

     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 "Regulatory Matters -
Regulation of Gas Operations - PSC Regulation".

     As of December 31, 2001 RG&E's peak day contracted transportation capacity
to serve retail load is 3,905,000 therms (where one therm is equivalent to
100,000 BTUs). RG&E experienced its maximum daily throughput of approximately
4,740,000 therms (approximately 3,910,000 therms sold to retail customers and
approximately 830,000 therms delivered for transportation customers) on January
19, 1994.

     RG&E purchases its gas supply from numerous energy marketers under
contracts that provide for delivery of gas during the winter and summer seasons,
including monthly and daily deliveries as needed to meet our customer's gas
requirements.  RG&E seeks to acquire and deliver the most cost efficient
reliable gas supply and optimize 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 2001,
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
<PAGE>

                                       6

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").

     During 2001, 40.4% 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, renegotiating or not
renewing gas supply and transportation contracts.

UNREGULATED OPERATIONS

     Energetix was formed in 1998 to market electricity and natural gas services
throughout upstate New York.  In August 1998, Energetix acquired Griffith, a
reseller of liquid-fuel products including fuel oil, diesel, kerosene, propane
and gasoline in the upstate New York market.  Since its acquisition by
Energetix, Griffith has completed ten acquisitions, the most significant of
which were its acquisitions in November 2000 of Burnwell Gas and certain assets
of AllEnergy - New York Fuels Division.  As of December 31, 2001, Energetix and
its subsidiaries had approximately 207,000 customers.  Of these customers,
approximately 123,000 were acquired in the Griffith and subsequent acquisitions
and approximately 84,000 were customers for natural gas and electricity service.
Approximately 100,000 of Energetix' customers reside outside RG&E's regulated
franchise territory.  As of December 31, 2001, Energetix and its subsidiaries
had approximately 602 employees and operated 29 customer service centers.

     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 Revenues" for
information on products, revenues and sales.

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.

  Regulation of Electric Operations

     Overview.  RG&E's electric operations are regulated primarily by the PSC,
FERC and NRC under various state and federal regulations.

     PSC Regulation

     PSC Electric Settlement.  During 1996 and 1997, RG&E, the staff of the PSC
and several other parties negotiated the Electric Settlement which was approved
by the PSC in November 1997.  The Electric Settlement sets the framework for the
introduction and development of open competition in the electric energy
marketplace in RG&E's territory and lasts through June 30, 2002.  In phases,
RG&E has allowed customers to purchase electricity, and later capacity
commitments, from ESCOs through its retail access program, Energy Choice.  These
ESCOs compete to package and sell energy and related services to customers. The
competing ESCOs purchase distribution services from RG&E who remains the sole
provider of distribution services and is responsible for maintaining the
distribution system and 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 are 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.
<PAGE>

                                       7

     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 will be used to
write down accumulated deferrals or investment in electric plant or regulatory
assets. The other 50 percent of such excess will be used to write down deferred
costs accumulated during the term of the Electric Settlement and the remainder
if any, will be retained as earnings by RG&E. There is currently a dispute
between RG&E and the staff of the PSC regarding the calculation of excess
regulatory earnings under the Electric Settlement. (see Item 7 - Management's
Discussion and Analysis under the heading "Results of Operations", "2001
Compared to 2000 - Regulated Electric Expenses") 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 the 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. The non-nuclear
operational costs are subject to recovery based on market conditions and plant
performance.

     RG&E's electric 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. In accordance with a
Joint Proposal filed with the PSC on March 13, 2001 and approved on March 29,
2001, RG&E implemented a market-based backout credit for ESCOs serving customers
on its system who choose not to continue with the full requirements option,
effective May 1, 2001.  The majority of ESCOs have chosen to remain on full
requirements.

     Certain provisions of the Electric Settlement terminate as of June 30,
2002, principally those provisions that deal with the effective period for
tariff rates.  Under New York State law, tariff rates do not change unless a PSC
order is issued.  Orders are generally issued by the PSC either in a rate case
proceeding filed by the regulated utility or as a result of settlement
negotiations among the regulated utility, the staff of the PSC, and other
interested parties.  The Company has filed a new electric and gas rate case with
the PSC as discussed below.  This action may or may not result in a PSC order
prior to June 30, 2002.  If not, the Company's current base tariff rates for
electric and gas service will likely remain in effect beyond that date until a
new order is issued by the PSC.  Under certain circumstances, however, new rates
could be implemented in such a way as to make their impact effective as of July
1, 2002.

     Energy Choice Program.  Historically, all the basic components of the sale
of energy have been bundled together by RG&E and sold by it at a fixed rate
approved by the PSC.  The basic components of the sale of energy are 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
<PAGE>

                                       8

     (5)  retail services such as billing and metering.

     The implementation of Energy Choice included a four year phase-in process
beginning July 1, 1998, to allow RG&E and other parties to manage the transition
to electric competition in an orderly fashion. The Energy Choice program began
on July 1, 1998 with an "Energy-Only" stage, during which ESCOs were responsible
only for providing the energy requirements of the customers they acquired.  The
Energy Choice program moved to an "Energy and Capacity" stage on November 1,
1999.  Since that date, ESCOs have been required to provide for the energy and
installed capacity requirements of their customers.

     Beginning July 1, 2001, all retail customers became eligible to purchase
energy, capacity and retailing services from competitive energy service
companies. As of December 31, 2001, approximately 24 percent of total RG&E sales
had shifted to competitive energy service companies, including the Company's
unregulated subsidiary, Energetix. Throughout the remaining term of the Electric
Settlement, through June 30, 2002, 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 ESCOs, and retail (end-use)
customers.  In this model, retail customers have the opportunity for choice as
to their ESCO 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 the customer's
chosen ESCO.

     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 ESCO defaults by requiring security
during the qualification process, as permitted by PSC Electric Distribution
Customer tariffs.  In addition, RG&E monitors on an on-going basis any changes
to its financial exposure from each ESCO and may require additional security or
a different form of security as necessary.

     As of December 31, 2001, five ESCOs, including Energetix, were qualified by
RG&E to serve retail customers under Energy Choice.

     ESCOs have had and continue to have the option to serve a portion or all of
their load by buying power directly from RG&E, at a price equal to the backout
credit for energy and capacity.  This is the "full requirements" option.  To the
extent that ESCOs choose not to take advantage of the full requirements option,
they must acquire power from the competitive wholesale market.  ESCOs may make
this choice on a service point by service point basis. Once they elect to
acquire power from the market for a particular service point, they are not
allowed to return that service point to full requirements service. To the extent
that ESCOs choose to procure power from the market, RG&E will experience a
revenue decrease. This will be offset by decreased costs resulting from reduced
requirements to purchase energy and capacity for sale to the energy service
companies and by increased revenues from the sale in the wholesale market of
energy produced by RG&E. Throughout the remaining term of the Electric
Settlement, through June 30, 2002, the full requirements option will continue to
be available to ESCOs.

     From the beginning of the Energy and Capacity stage through the
implementation of the market-based backout credit (described below), RG&E's
distribution rates were set to be equal to rates for standard retail service
less two separate credits.  The first was a fixed "backout" credit for energy
and capacity. The second was a fixed "retailing" credit to represent the avoided
costs of retailing services assumed by ESCOs.  From November 1, 1998 through
June 30, 2000, the energy and capacity backout credit was set at 2.67 cents per
kilowatt-hour (an estimate of the wholesale market price of electric energy and
capacity, adjusted for gross receipts taxes).  The retailing credit was set at
0.40 cents per kilowatt-hour. Beginning July 1, 2000, the energy and capacity
backout credit was updated to 2.68 cents per
<PAGE>

                                       9

kilowatt-hour to reflect the implementation of reduced gross receipts taxes. The
retailing credit was unchanged.

     On March 29, 2001 the PSC approved a joint proposal among RG&E and several
other parties, including the staff of the PSC, which replaces the fixed energy
and capacity backout credit with one that varies based on the market price of
energy, installed capacity, ancillary services, and the NYPA Transmission
Adjustment Charge ("NTAC").  This new "market-based" backout credit became
effective May 1, 2001.  The market-based credit is initially based on projected
prices for energy, capacity, ancillary services and the NTAC and is trued-up to
actual prices after they are known.  The joint proposal called for the retailing
credit to remain at a level of 0.40 cents per kilowatt-hour.

     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 eligibility to participate in the electric retail access program was
subject to increasing caps 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.  In the opinion
of RG&E, the adoption of the market-based backout credit, described above, and
the elimination of the cap on eligibility to participate in the electric retail
access program on July 1, 2001, as provided by the Electric Settlement,
effectively moots most aspects of these petitions.  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 ESCOs 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 potential changes on its operations as retail
access continues to evolve.

     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 the
practice of negotiating discounted rates, the difference between the discounted
rates paid under these individual contracts and the rates that would otherwise
apply.  Approximately 25.8 percent of all regulated electric sales to customers
are made under long-term contracts with negotiated rates, primarily to large
industrial customers.  These contracts represent approximately 42.8 percent of
RG&E's revenues from its commercial and industrial customers.

     PSC Nuclear Initiative.  Prior to the sale of Nine Mile Two 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 have now been sold, except for RG&E's Ginna
Plant, the PSC could regard the proceeding as moot.
<PAGE>

                                      10

     FERC Regulation

     New York Independent System Operator.  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 November 1999 following
FERC approval, the NYISO began 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 as the New York Power Pool was
restructured in response to FERC Order 888.

     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 filed a complaint with FERC against the NYISO.
RG&E sought corrective re-calculation of operating reserve prices for prior
periods and prospective relief from harm 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. 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. On
November 8, 2001, FERC denied the request for rehearing. FERC denied the request
for refunds as the earlier order did not find the NYISO in violation of its
tariff. Further, FERC directed the NYISO to recalculate operating reserves
charges based on the rates that were in effect prior to March 28, 2000. RG&E has
paid the recalculated charges.

     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. 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. On March 28, 2001, FERC issued an order permitting
the NYISO to implement its locational pricing system as filed. In the November
8, 2001 order, FERC reiterated its continuing support of the existing bid cap.

     Despite the current activity related to the potential creation of a
Northeast RTO as discussed below under the heading "FERC Electric Restructuring
Order No. 2000", the NYISO will continue as the system operator until it is
replaced either by a Northeast RTO or by another regional transmission system
operator. As such, the NYISO will continue to make regulatory filings and RG&E
and the other member systems will continue to monitor, intervene, comment and
protest as necessary to protect their respective interests.

     FERC Electric Restructuring Order No. 2000. On December 15, 1999, FERC
adopted Order No. 2000, 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.

     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 submitted that the NYISO met the general
requirements of an RTO, and the NYISO agreed to make certain enhancements to its
structure and programs to benefit the market.  Minor modifications were proposed
to the governance structure and transmission planning, and the NYISO agreed to
coordinate more closely with other RTOs. On February 22, 2001, RG&E made a joint
filing with NYSEG supporting the January 16/th/ filing, but asking FERC to
explore the functional and structural integration of the three existing
Northeastern ISOs.
<PAGE>

                                      11

     On July 12, 2001, FERC issued a series of orders addressing the compliance
of the NYISO with the policies embodied in the Rule.  FERC also issued an order
calling for the formation of a single RTO for the northeast rather than three as
proposed by the market participants in each region. FERC ordered that the
Pennsylvania-New Jersey-Maryland ISO was to be the platform upon which the
northeastern RTO would be based, but that best practice rules from the other
ISOs would be used to develop the final design for the consolidated RTO. Under
the supervision of an Administrative Law Judge, parties from New England, New
York, the Mid-Atlantic States and Canada met from July 24, 2001 through
September 7, 2001. The Judge issued his report to FERC on September 17, 2001.
Comments on the report were filed with FERC on October 9, 2001.  FERC action on
the report, which seeks specific FERC guidance, was expected in the fourth
quarter, but will not be acted upon until later in 2002.  Public workshops
related to RTO formation were held between October 15 and October 19, 2001. FERC
is currently soliciting comments from the various northeastern governmental and
regulatory bodies.  Furthermore, FERC has launched a series of new initiatives
relating to market structures.  There is currently a Notice of Proposed
Rulemaking ("NOPR") regarding standard generator interconnection procedures and
standards excluding pricing issues.  FERC will issue a NOPR on those pricing
issues in the second quarter of 2002.  FERC is also preparing to issue a NOPR
related to standard market design for the wholesale electric market. RG&E cannot
predict what effect the ultimate action by FERC with respect to the Rule will
have on its future operations or financial condition.

     Nuclear Regulation

     Because of RG&E's ownership and operation of the Ginna Plant, it is subject
to extensive regulation and the satisfaction of numerous requirements. The Ginna
Plant operates under a license from the NRC which is scheduled to expire in
2009.  Permission to operate beyond that date could possibly be obtained. The
gross and net book costs of the Ginna Plant as of December 31, 2001 were $581
million and $196 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 $7.8 million, $12.6 million and $6.2
million for the years 2002, 2003 and 2004, 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.  See Note 2 to the
Financial Statements for a discussion of certain other nuclear-related
regulatory matters.

  Regulation of Gas Operations

     Overview.  RG&E's gas operations are regulated primarily by the PSC under
various state regulations.  RG&E's gas operations are also significantly
affected by FERC actions affecting the natural gas market.

     PSC Regulation

     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 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 such negotiations and, in January
2001, RG&E reached agreement with the PSC Staff and other parties on a
comprehensive rate and restructuring proposal for its natural gas business as
contemplated in the Gas Policy Statement (see discussion below under "Gas Retail
Access Settlements").
<PAGE>

                                      12

     Gas Retail Access Settlements.   On January 25, 2001, RG&E reached
agreement with PSC Staff and other parties on a comprehensive rate and
restructuring Settlement for its natural gas business (the "Gas Rates and
Restructuring Settlement"), as contemplated in the PSC's Restructuring Policy
Statement issued November 3, 1998.  The Gas Rates and Restructuring Settlement
was approved by the PSC, with some modifications, on February 28, 2001 and
became effective on March 1, 2001.

     The Gas Rates and Restructuring Settlement 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 Term which applies to most other provisions and extends
from March 1, 2001 through March 31, 2004. The significant features of the
Settlement, as modified and approved by the PSC, are as follows:

     (1)  For the purpose of setting base, or local delivery, rates for the
          period beginning July 1, 2000 natural gas revenues are decreased a
          total of approximately $3.0 million from the levels in effect on June
          30, 2000. This rate level is based on an agreed-upon return on equity
          of 11.00%.

     (2)  Base rates are adjusted effective March 1, 2001 to reflect the revenue
          requirements decrease. Because the base rates that were in effect
          through February 28, 2001 were higher than those agreed to by the
          parties, RG&E, in March 2001, passed 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)  In the event that RG&E achieves a return on equity in excess of 12.5%
          in any rate year covered by the Gas Rates and Restructuring
          Settlement, 90% of the excess over that level will be deferred for the
          benefit of customers.

     (4)  RG&E is allowed to defer certain prudent and verifiable costs,
          expenditures for certain competition implementation costs and certain
          costs associated with mandates and catastrophic events for recovery
          after the Rate Term of the Gas Rates and Restructuring Settlement,
          subject to PSC approval.

     (5)  RG&E is authorized to implement a Retail Access Capacity Program,
          beginning November 1, 2001, 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.

     (6)  RG&E will implement a Capacity Incentive Program ("CIP"), 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. The imputed level of
          savings will be $1.1 million per year for the period beginning April
          1, 2001 and extending through June 30, 2002. The level will then be
          $0.5 million per year for the period beginning July 1, 2002 and
          extending through March 31, 2004.

     (7)  RG&E will implement a Service Quality Performance Program to be
          effective as of January 1, 2001 through at least June 30, 2002. If
          RG&E fails to satisfy certain performance targets, it can be subject
          to penalties of up to approximately $0.6 million.

     The PSC also directed RG&E to work with PSC Staff and others on three
elements of the Gas Rates and Restructuring Settlement: a weatherization program
for low-income customers, a customer education plan, and an aggregation program
for customers who receive assistance from the Monroe
<PAGE>

                                      13

County Department of Social Services. Discussions have been held, and work is in
process, on all three of the measures.

     Pursuant to the CIP established by the Gas Rates and Restructuring
Settlement, RG&E, as of April 1, 2001, released all of its ANR Pipeline Company
and Great Lakes Gas Transmission Limited Partnership transportation and storage
capacity through March 31, 2004.  To maintain the necessary level of service
that had been provided by the ANR and Great Lakes facilities, RG&E entered into
an agreement with Union Gas Limited for storage service at facilities in
southern Ontario, Canada.  Recovery by RG&E of the costs resulting from the new
storage contract with Union, as well as the recovery of the difference between
the cost to the gas marketers of the released service and the amount received
from the replacement shipper, is subject to the CIP.

     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 a June 2000 gas settlement, 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 June 2000 gas settlement (generally through June 30, 2002), subject to
possible further negotiations in the event of a particularly rapid migration of
customers.

     On April 1, 2001, RG&E also implemented the single-retailer model program
for large-volume gas customers.  With this transition completed, all small- and
large-volume retail customers are now eligible to participate under the single-
retailer model.

     As of December 31, 2001, eighteen energy service companies, including
Energetix, were 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 the PSC.

     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.
<PAGE>

                                      14

     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.

     On March 30, 2001 Dominion Transmission, Inc. ("DTI") became the first
pipeline upon which RG&E holds capacity to file a FERC Order No. 637 settlement
with the FERC. On May 31, 2001 FERC issued an order accepting DTI's settlement,
as filed. There are continuing negotiations with the other pipelines upon which
RG&E holds capacity.  In light of the continuing emphasis at FERC on issues
facing the electric industry, RG&E cannot predict when the balance of the Order
637 issues will be addressed or what effects, if any, FERC's initiatives and the
related pipeline tariff changes will have on future operations or the financial
condition of RG&E.

  2002 Electric and Gas Rate Proposal

  On February 15, 2002, RG&E filed a request with the PSC for new electric and
gas rate tariffs to go into effect in January, 2003.  The filing is comprised of
two components.  The first is a traditional, single-year rate case filing in the
form required by New York State law.  The second is a multi-year settlement
proposal.  RG&E anticipates that the filing will initiate negotiations with the
staff of the PSC and other interested parties regarding long-term rate plans,
electric rate unbundling, electric pricing options and other related programs,
all as described below.

  The traditional single-year filing provides a basis to increase electric rates
by $59.0 million per year (8.2%) and gas rates by $18.7 million per year (6.6%).
However, in the multi-year proposal RG&E proposes to freeze rates through the
end of 2002 and to set new unbundled rates for electric and gas delivery service
in January 2003.  Increases in the new rates for electric distribution would be
substantially mitigated by merger synergies and benefits flowing from RG&E's
owned generation and would be held constant for a period of approximately five
years.  The exact rate levels would be subject to negotiation.  RG&E made
certain other proposals as part of the multi-year proposal, notably the
following:

     (1)  RG&E proposed to use existing assets and liabilities to fund a rate
          freeze between July 1, 2002 (when RG&E's current gas and electric rate
          settlements terminate) and December 31, 2002. RG&E would use an
          existing reserve established for regulatory earnings as provided by
          the current electric rate settlement; it would suspend or reduce
          amortization for certain regulatory assets during that period; and it
          would pass back certain amounts due customers during that period.

     (2)  RG&E proposed to offer electric customers a choice of pricing options
          for supply service. One choice would be a fixed price offering, which
          would provide a fixed price for a one-year period. Each year, the
          price would be updated to reflect changes in wholesale market prices
          for the electric commodity, installed capacity and other services
          required by the NYISO. The second option would be a variable price
          offering. Under this option, electric prices would be adjusted each
          month for wholesale market changes. Customers also would continue to
          have the option of purchasing the electric commodity from a
          competitive supplier.

     (3)  RG&E proposed to "unbundle" electric rates in accordance with PSC
          policy. This would result in charges for electric service being broken
          down into three categories: wholesale market costs of electric
          commodity supply, other supply-related costs and delivery costs. The
          first category would reflect the cost of supplying customers' energy
          needs directly from the wholesale market. The second category reflects
          the difference between the wholesale market cost of supplying
          customers and RG&E's actual costs. RG&E's actual costs differ from
          wholesale market costs because it owns generating plants and holds
          long-term power contracts. These assets provide the bulk of the power
          needed to satisfy customer requirements, and the related costs do not
          fluctuate directly with wholesale market prices for energy. This rate
          element could be positive or negative depending on wholesale price
          levels
<PAGE>

                                      15

          and RG&E's costs. The third category reflects RG&E's cost of owning,
          operating and maintaining the system of lines, substations and other
          equipment necessary to deliver power to customers.

     (4)  RG&E committed to continue to invest in its gas and electric
          distribution systems in order to provide safe and reliable service. In
          addition, it committed to continue economic development, low income
          customer assistance and customer education programs.

     RG&E believes a multi-year negotiated settlement of these issues would be
in the best interest of all parties.  RG&E, however, is unable to predict
whether any settlement will be achieved or the effect any ultimate PSC decision
in this proceeding will have on RG&E's operating results or financial position.
Likewise, if one or more settlements are achieved and submitted to the PSC for
its approval, RG&E cannot predict how the PSC might rule on any particular
aspect of such settlements.  If a negotiated agreement resolving the issues
involved in the case cannot be achieved, New York State law requires the PSC to
act on RG&E's proposal within eleven months after the initial filing.  Thus, a
PSC decision is expected no later than January, 2003.

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"), the Comprehensive
Environmental Response, Compensation and Liability Act and the federal Clean Air
Act, as amended (the "Clean Air Act").

     As a result of RG&E's ownership of the Ginna Plant it must dispose of the
low-level radioactive waste generated at the station 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 regarding 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 disposing of its low-level radioactive waste at appropriate disposal
facilities.  One of the facilities, located in Barnwell, South Carolina is
planning to terminate its operation in 2010.  For low level radioactive waste
disposal after 2010, whether from continued Ginna operation or decommissioning
activities, RG&E will need to make arrangements with other operating sites if
the Barnwell facility is not then available.

     As permitted by its license to operate the Ginna Plant, RG&E currently
stores the spent nuclear fuel generated by the Ginna Plant at the plant.  The
DOE is currently targeting the opening of a Federal high-level radioactive waste
repository in 2010, one year after RG&E's current license to operate the Ginna
Plant is scheduled to expire.  Whether or not the Ginna Plant license is
extended, RG&E anticipates that spent fuel will be stored at the Ginna Plant for
some time beyond 2009 pending final disposal by the DOE.

     RG&E has wastewater discharge permits from NYSDEC for each of its steam
electric generating stations.  The Ginna Plant 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.
Consistent with the Ginna Plant permit, no significant changes to the wastewater
discharge treatment systems are currently required, nor anticipated.  Beebee
Station's coal fired unit was retired in June 1999; however, the wastewater
treatment plant on that site continues to operate in a batch mode but at a
significantly reduced frequency.
<PAGE>

                                      16

     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 will require capital
expenditures of approximately $4.1 million and $0.7 million in 2002 and 2003,
respectively. No additional operating and maintenance costs for emissions
control will be incurred during 2002 as a result of these expenditures since the
pollution control systems being installed will not go into service until 2003.
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 costs of these allowances for 2002
are estimated to be $3.8 million. 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.

     The Governor of New York has directed the NYSDEC to require electric
generating units to further reduce emissions of substances contributing to acid
rain. The Governor's objective is to establish reduction targets for sulfur
dioxide ("SO2") that are 50% below the current federal Acid Rain Phase II limits
and for oxides of nitrogen ("NOX") approximately 40% below existing federal
standards. Draft regulations submitted to the NYS Office of Regulatory Reform
for comment provided for a phased-in implementation beginning in 2003 and
concluding in 2007. The NYSDEC has not published a final regulatory proposal for
purposes of beginning the rule-making process.

     Separately, the NYSDEC and the New York Attorney General have served RG&E
with a notice of violation ("NOV") of provisions of the Clean Air Act. The
notice alleges that between 1983 and 1987 RG&E made certain repairs, maintenance
and parts replacement at Russell Station which constituted major modifications
resulting in a significant increase in the capacity to emit SO2 without the
appropriate permits and installation of the best available emissions control
technology. RG&E denies these allegations.

     Despite RG&E's inability to definitively predict the outcome of these
separate matters, it is investigating a number of options, which would resolve
the NOV and satisfy the anticipated regulatory requirements.

     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 remediation and operating
costs.  RG&E believes that expenditures and costs made necessary by mandated
environmental protection programs will generally be allowable for ratemaking
purposes. However, under the terms of the Electric Settlement, which sets a
threshold of $2.5 million for recoverability of expenditures and costs resulting
from mandates, to the extent that the costs resulting from individual mandates
do not meet the $2.5 million threshold, 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.

COMPETITION

     Through its subsidiaries, particularly RG&E and Energetix, the Company
faces increasing competition.  The opening of electricity and gas markets to
competition at both the wholesale and retail levels has had multiple impacts on
both regulated and unregulated operations.  This evolution of the markets is on-
going, as is the associated risk.  While the electric and gas markets continue
to develop, RG&E (unlike Energetix and other ESCOs) remains subject to an
obligation to provide electric and gas service upon request by a prospective
customer.

     To the extent that its own generation and power purchased under long-term
contracts are not sufficient to supply the requirements of its own customers,
RG&E must purchase electric capacity and energy in the open market and is
therefore exposed to market pricing for its wholesale purchases.
<PAGE>

                                      17

Because RG&E does not have an electric fuel cost adjustment clause under the
current Electric Settlement, changes in the cost of electricity cannot be
routinely flowed through to its customers. The resulting risk, however, is
reduced to a significant degree by the use of hedging transactions for periods
when prices are likely to be most volatile, the purchase of generation insurance
for forced outages, the use of proceeds from energy and capacity sales RG&E is
able to make at other times, and the provisions of the Nine Mile Two sale
whereby RG&E has the obligation and right for a multi-year period to purchase up
to 90 percent of the output of the plant corresponding to RG&E's original
ownership interest and has the opportunity to share in the proceeds of sales
above certain thresholds.

     On the retail side of its electricity business, RG&E is exposed to the
impact of losing load to competitive suppliers of electricity. To the extent
that retail customers, taking advantage of RG&E's Energy Choice program, no
longer take their electric requirements from RG&E, the native load served by
RG&E could decline to a point where the capacity of RG&E-owned generation
exceeds load levels much of the time. In that event, RG&E is at risk to the
extent that the costs of its generation exceed market prices. Although the
migration of customers to competing suppliers has slowed recently, thereby
reducing this risk, an increase in migration rates could readily lead to
intensified risk. Also mitigating this risk is the "full requirements" option
that provides competing suppliers with the option to purchase energy and
capacity directly from RG&E for the purpose of supplying load in the Company's
service territory. Pricing for this program is such that RG&E is effectively
indifferent as to whether the energy is sold directly to a retail customer or to
a competitive supplier. To date, practically all of the competitive suppliers
have chosen this option for most of the load that they serve.

     RG&E's gas business is also exposed to risks resulting from the emerging
competitive market. Although RG&E's current gas settlements with the PSC
contains a gas cost adjustment clause which permits the pass-through of most
changes in gas costs to its customers, those settlements place RG&E at risk to
the extent that certain costs, particularly pipeline capacity costs, exceed
particular thresholds. The migration of customers to other suppliers of gas
under RG&E's retail access program also has an impact on risk. Although the
retail access program for gas is intended to permit RG&E to match its resources
to the needs of the customers it must serve, the practical difficulties
associated with attempting to predict migration levels and to assign pipeline
and storage capacity to correspond with those levels can result in the risk of
under-recovery of costs incurred.

     Energetix, as an unregulated competitor in the electric and gas retail
access programs of RG&E and other upstate New York utilities, faces primarily
the risk of competition from other ESCOs. Energetix must compete for customers
with other ESCOs and, therefore, must price its electric and gas service
accordingly. In addition, as a marketer without its own generation, Energetix
must purchase all of its electric requirements (for resale to its customers) in
the market. Currently, Energetix is able to purchase the full energy and
capacity requirements for most of its customers, who are in RG&E's service
territory, from RG&E at fixed rates. On the gas side, Energetix is more exposed
to the wholesale market where gas prices have been particularly volatile.
Energetix, however, has been able to reduce this price risk to a significant
degree through hedging transactions. Energetix also competes with other liquid
fuel companies in its liquid fuels business.

     As the electric and gas markets evolve, it is likely that competitive
pressures, such as those described above, will increase rather than decrease.

FINANCING AND CAPITAL REQUIREMENTS PROGRAM

     A discussion of RGS's and RG&E'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. As of December 31, 2001, Common Stock has been the only security
issued by RGS. As discussed under the heading "Merger Agreement", all shares of
RGS Common Stock are expected to be converted into a number of shares of Energy
East common stock and cash upon completion of the Merger. 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 certificate of incorporation.
<PAGE>

                                      18

     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 $400.0 million of long-term debt not
later than December 31, 2002. Through December 31, 2001, RG&E had issued $200.0
million of long-term debt (Series TT First Mortgage Bonds) pursuant to this PSC
authorization.

     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-one supplemental indentures.
The General Mortgage requires the following financial requirements to be
satisfied before additional First Mortgage Bonds are issued:

(a)  Earnings (as defined in the General Mortgage) 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
     issued. The ratio under this test for the twelve months ended December 31,
     2001 was 5.13.

(b)  If additional First Mortgage Bonds are being issued on the basis of
     property additions (as defined in the General Mortgage), the principal
     amount of the bonds may not exceed 60% of available property additions. As
     of December 31, 2001, the amount of additional First Mortgage Bonds which
     could be issued on that basis was approximately $240.0 million. 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 RG&E. As of December 31, 2001, RG&E could issue $157,169,000 of First
     Mortgage Bonds against First Mortgage Bonds that have matured or been
     redeemed.

     The certificate of incorporation of RGS does not contain any financial
tests for the issuance of common or preferred stock. The certificate of
incorporation of RG&E does not contain any financial tests for the issuance of
common stock; however, it does have financial tests for the issuance of
preferred stock. RG&E's certificate of incorporation 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, 2001, the coverage ratio under
(b) above (the more restrictive provision) was 1.89.

     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 RGS corporate credit rating from the Standard and Poor's
Corporation was A- at December 31, 2001. RG&E's securities ratings at December
31, 2001 were:

                                       First
                                      Mortgage  Preferred
                                       Bonds      Stock
                                      --------  ---------

     Standard & Poor's Corporation       A-        BBB
     Moody's Investors Service           A3        Baa3
     Fitch                               A-        BBB

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

                                      19

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 2001, 2000 and 1999 were $2.6 million,
$2.6 million and $2.9 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>

                                      20

RGS Electric Department Statistics
----------------------------------

<TABLE>
<CAPTION>
Year Ended December 31                                            2001        2000         1999         1998         1997
---------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>         <C>          <C>          <C>          <C>
Electric Revenue (000's)
Residential                                                   $  231,225  $  247,954   $  273,238   $  250,073   $  252,464
Commercial                                                       157,186     161,023      171,097      203,338      210,643
Industrial                                                        97,753     103,902      115,542      130,778      144,305
Municipal and other                                               42,088      45,023       52,419       58,889       72,061
---------------------------------------------------------------------------------------------------------------------------
Electric revenue - retail customers                           $  528,252  $  557,902   $  612,296   $  643,078   $  679,473
Energy marketers (including Energetix)                           126,023      99,492       65,204       15,086        -----
Other electric utilities                                          80,011      73,612       25,251       29,958       20,856
---------------------------------------------------------------------------------------------------------------------------
      Total electric revenues                                 $  734,285  $  731,006   $  702,751   $  688,122   $  700,329
---------------------------------------------------------------------------------------------------------------------------

Electric Sales - MWH
Residential                                                    2,044,601   2,153,567    2,269,922    2,111,739    2,139,064
Commercial                                                     1,702,176   1,680,022    1,783,904    2,007,282    2,118,991
Industrial                                                     1,471,716   1,557,478    1,760,629    1,929,268    2,010,613
Municipal and other                                              428,181     552,497      504,757      514,243      537,051
---------------------------------------------------------------------------------------------------------------------------

      Total retail sales                                       5,646,674   5,943,564    6,319,259    6,562,532    6,805,719
Energy marketers (including Energetix)                         1,383,437   1,134,263      762,999      175,020        -----
Other electric utilities                                       2,218,565   1,636,255    1,111,928    1,498,325    1,218,794
---------------------------------------------------------------------------------------------------------------------------
Total electric sales                                           9,248,676   8,714,082    8,194,186    8,235,877    8,024,513
---------------------------------------------------------------------------------------------------------------------------

Electricity Generated - MWH
Fossil                                                         1,847,158   1,547,727    1,692,605    1,962,889    1,664,914
Nuclear                                                        5,333,319   4,925,999    4,734,703    5,323,639    5,119,544
Hydro                                                            132,872     207,538      133,317      189,512      227,867
Pumped storage                                                    ------      67,523      233,279      232,927      238,900
   Less energy for pumping                                        ------    (101,272)    (349,836)    (348,438)    (358,350)
Other                                                             ------      ------        1,334          195          890
---------------------------------------------------------------------------------------------------------------------------
Total generated - net                                          7,313,349   6,647,515    6,445,402    7,360,724    6,893,765
---------------------------------------------------------------------------------------------------------------------------

System Net Capability MW at December 31
Total system net capability                                        1,368       1,382        1,382        1,588        1,614
Net peak load - MW                                                 1,544       1,367        1,433        1,388        1,421

Cooling Degree Days (Calendar Year)
For the period                                                       591         434          657          559          345
Percent warmer (colder) than normal                                 39.1         2.1         54.6         31.5        (18.8)

Electric Distribution Customers at December 31                   352,510     351,058      344,389      344,052      343,973
</TABLE>
<PAGE>

                                      21

RGS Gas Statistics
------------------

<TABLE>
<CAPTION>
Year Ended December 31                                              2001       2000       1999       1998       1997
----------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>        <C>        <C>        <C>        <C>
Gas Revenue (000's)
Residential                                                       $  6,524   $  6,680   $  5,658   $  2,944   $  5,852
Residential spaceheating                                           225,935    249,527    212,786    201,686    249,101
Commercial                                                          32,756     36,241     31,134     40,196     51,893
Industrial                                                           3,576      3,378      3,016      4,222      5,800
Municipal and other                                                  7,704     (5,577)     4,852     10,017      8,682
----------------------------------------------------------------------------------------------------------------------

Gas revenue - retail customers                                    $276,495   $290,249   $257,446   $259,065   $321,328
Marketers and transportation of customer-owned gas                  34,881     32,164     21,225     15,475     14,981
Other unregulated gas revenues                                      46,491     17,601      5,805      -----      -----
----------------------------------------------------------------------------------------------------------------------
 Total gas revenues                                               $357,867   $340,014   $284,476   $274,540   $336,309
----------------------------------------------------------------------------------------------------------------------

Gas Sales - Therms (000's)
Residential                                                          5,295      6,021      5,887      3,599      5,773
Residential spaceheating                                           217,588    261,818    264,047    239,740    285,395
Commercial                                                          34,677     41,319     43,179     53,552     65,675
Industrial                                                           4,091      4,197      4,541      6,079      7,828
Municipal                                                            3,088      4,580      5,749      6,388      7,331
----------------------------------------------------------------------------------------------------------------------

 Total retail sales                                                264,739    317,935    323,403    309,358    372,002
Transportation of customer-owned gas                               234,294    239,640    199,997    163,575    166,060
Other unregulated sales                                             80,750     41,645     12,450      -----      -----
----------------------------------------------------------------------------------------------------------------------
 Total gas sold and transported                                    579,783    599,220    535,850    472,933    538,062
----------------------------------------------------------------------------------------------------------------------

Gas - Therms (000's)
Purchased for resale                                               187,618    230,680    200,036    203,677    274,430
Gas from storage                                                    85,994     94,986    126,158    111,164    104,317
Other                                                                1,794      1,763      2,151      1,496      1,410
----------------------------------------------------------------------------------------------------------------------
 Total gas available                                               275,406    327,429    328,345    316,337    380,157
----------------------------------------------------------------------------------------------------------------------

Heating Degree Days (Calendar Year)
For the period                                                       6,038      6,643      6,289      5,666      6,916
Percent colder (warmer) than normal                                  (10.3)      (1.9)      (6.6)     (15.9)       2.8

Gas Distribution Customers at December 31                          289,038    287,490    285,100    288,904    281,429
</TABLE>
<PAGE>

                                      22

Item 2.   PROPERTIES

ELECTRIC PROPERTIES

     The net capability of RG&E's electric generating plants in operation as of
December 31, 2001 and the net generation of each plant for the year ended
December 31, 2001, and the year each plant was placed in service are as set
forth below:

Electric Generating Plants

<TABLE>
<CAPTION>
                                                          Net
                                          Year Unit    (Nameplate)      Net
                                          Placed in    Capability    Generation
                          Type of Fuel     Service        (Mw)          (MwH)
                          ------------    ---------    -----------   ----------
<S>                       <C>             <C>          <C>           <C>
Allegany Station
 (Combustion Turbine)         Gas              1998         63          252,248

Beebee Station
 (Combustion Turbine)         Oil              1969         14            1,059

Russell Station
 (Steam)                      Coal        1949-1957        257        1,592,076

Ginna Plant
 (Steam)                      Nuclear          1970        480        4,286,280

Station No. 9
 (Combustion Turbine)         Gas              1969         14            1,775

Station 5
 (Hydro)                      Water            1917         39          107,063

Other Stations
 (Hydro)                      Water       1906-1960          8           25,810
                                                       -------       ----------
                                                           875        6,266,311
                                                       =======       ==========
</TABLE>

Electric Distribution Facilities

     RG&E owns 158 distribution substations having an aggregate rated
transformer capacity of 2,403,596 Kva, of which 149, having an aggregate rated
capacity of 2,200,963 Kva, were located on lands owned in fee, and nine of
which, having an aggregate rated capacity of 202,633 Kva, were located on land
under easements, leases or license agreements. RG&E also has 71,660 line
transformers with a capacity of 2,732,789 Kva. RG&E also owns 14 transmission
substations having an aggregate rated transformer capacity of 3,410,617 Kva of
which 13, having an aggregate rated capacity of 3,335,950 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 737
circuit miles of overhead lines and approximately 423 circuit miles of
underground lines. The distribution system consists of approximately 16,349
circuit miles of overhead lines, approximately 4,395 circuit miles of
underground lines and 361,320 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.
<PAGE>

                                      23

GAS PROPERTIES

     RG&E's gas distribution systems consist of 4,529 miles of gas mains and
301,258 installed meters (see Item 1 - Business, "Regulated Gas Operations" and
"Gas Department Statistics").

UNREGULATED PROPERTIES

     Griffith, including its subsidiaries, owns or leases 69 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.

     -    (26) 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 dealers who
          provide various services at retail to the general public.

     -    (26) 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 518,700 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 RG&E. 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 General Mortgage securing RG&E's outstanding First
Mortgage 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 General Mortgage. RG&E has credit agreements with
a domestic bank under which short-term borrowings are secured by RG&E's accounts
receivable.
<PAGE>

                                      24

Item 3.   LEGAL PROCEEDINGS

     RG&E-OWNED WASTE SITE ACTIVITIES. RG&E is conducting proactive Site
Investigation and/or Remediation ("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
investigating the other three sites. RG&E has recorded a total liability of
approximately $21.7million which it anticipates spending on SIR efforts at the
eight RG&E-owned sites. Through December 31, 2001, RG&E has incurred aggregate
costs of $8.1 million for these sites.

     MANUFACTURED GAS PLANTS. RG&E and its predecessors formerly owned and
operated five manufactured gas plants ("MGPs") and acquired (following cessation
of MGP operations) two others for which SIR costs are estimated to be
approximately $20.0 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 investigation and remediation and, in some instances, RG&E is
coordinating its activities with the NYSDEC.

     SUPERFUND AND NON-OWNED OTHER SITES. RG&E has been or may be associated as
a potentially responsible party for SIR efforts at nine sites not owned by it.
RG&E has signed orders of 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 potentially
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 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 defending the legal action but cannot predict its eventual
outcome. There is insufficient information available at this time to predict the
economic impact of the claim on RG&E.

     GRIFFITH OWNED SITES. Griffith is involved in several proceedings in
connection with a petroleum discharge that occurred at its Big Flats, New York
terminal prior to its acquisition by Energetix. The EPA has issued a Unilateral
Administrative Order in connection with such discharge. Pursuant to a cost-
sharing agreement, Sun Pipe Line Company and Griffith have each assumed one-half
of the costs necessary to comply with the order, reserving their respective
rights against each other, and compliance with the order has been proceeding on
this basis. To date Griffith has spent $1.8 million in connection with
remediation of the site and compliance with the EPA's Order.

     In addition to the EPA's order, a legal proceeding relating to the
discharge Big Flats has been ongoing in New York State Supreme Court for Steuben
County since 1996. 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 the discharge. Griffith is asserting cross-claims for
contribution and/or indemnification from Sun Pipe Line for damages suffered by
the plaintiff as well as Griffith's own damages in connection with the
discharge. In April 2001, the Appellate Division for the Fourth Department of
Supreme Court determined that both Griffith Oil and Sun Pipe Line were
dischargers within the meaning of the New York State Navigation Law and are
responsible for the property damages which may be proved by Steuben Contracting.
The plaintiff's damages, as well as the respective claims among Griffith, Sun
Pipe Line and Chevron for contribution and indemnification, have yet to be
tried. With the exception of amounts for which Griffith has assumed
responsibility under the cost-sharing agreement with Sun Pipe Line, an estimate
of the possible cost to Griffith cannot be made at this time.

     The State of New York has separately commenced an action against Griffith
for statutory penalties in connection with the discharge at Big Flats. Griffith
has answered the complaint and denied the allegations, asserting that it was not
responsible for the discharge. Griffith is unable to estimate at this time the
amount of penalties, if any, that might be imposed if the state is successful.

     In June 2000, Griffith received notification that it is considered a
responsible party in connection with petroleum contamination at its Phelps, New
York facility. Griffith leased an office and garage at this
<PAGE>

                                      25

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. Early in 2000, 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 vigorously defend any action brought
against it by New York State for reimbursement of costs associated with this
discharge.

     EXIT AGREEMENT RELATING TO NINE MILE TWO. In connection with the sale by
RG&E of its interest in Nine Mile Two, RG&E informed Niagara Mohawk that RG&E's
rights and obligations under a June 8, 1998 Exit Agreement will cease as it
pertains to payments for certain transmission facilities relating to RG&E's
ownership of a portion of Nine Mile Two. Niagara Mohawk disputed RG&E's
position, asserting instead that RG&E must continue making payments that decline
from approximately $7.0 million per year currently to approximately $4.0 million
per year in 2007 and continue at that level until 2043 (or until the plant is
retired, if sooner). After attempting to resolve that matter informally, RG&E,
on August 13, 2001, commenced an action in New York State Supreme Court, Monroe
County, seeking a judgment declaring that, as a result of the sale of its
interest in Nine Mile Two, RG&E has no further obligation to make payments under
the Exit Agreement and that the Transmission Congestion Contracts or TCCs to
which RG&E was entitled under the Exit Agreement, should be returned to and
accepted by Niagara Mohawk. Niagara Mohawk answered RG&E's complaint, asserting
various affirmative defenses and counterclaims. On October 16, 2001, RG&E moved
for summary judgment. The ultimate outcome of that motion or of the declaratory
judgment action itself cannot be predicted.

     On December 6, 2001, Niagara Mohawk filed a complaint with FERC seeking to
have FERC assert jurisdiction of the Exit Agreement dispute, declare that RG&E
is in breach of the Exit Agreement, and order RG&E to fulfill the payment
obligations set forth in the Exit Agreement. RG&E has filed a Motion to
Intervene, Answer and Motion to Dismiss in response to the Niagara Mohawk
complaint asking FERC to defer to the jurisdiction of the New York State Supreme
Court because the matter is one of contract interpretation. The Nine Mile Two
Settlement provides that the Nine Mile Two regulatory asset would be adjusted
for any amount RG&E is found responsible for in the resolution of the Exit
Agreement dispute. RG&E cannot predict the outcome of this proceeding.

     OTHER LAWSUITS AND CLAIMS. RG&E and Griffith are involved in other lawsuits
and claims relating to their operations, including lawsuits and claims relating
to the condition of real property which they own, lease or have 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 11 to the Financial Statements - 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 of RGS or
RG&E during the fourth quarter of the fiscal year ended December 31, 2001.
<PAGE>

                                      26

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, 2002. Unless otherwise indicated all positions and
offices listed are with RG&E.


                    Age, as of       Positions, Offices and Business Experience
Name                  1/1/02                        1997 to date
----                 --------        ------------------------------------------

Thomas S. Richards      58           Chairman, President and Chief Executive
                                     Officer of RGS - August 1999 to date.

                                     Chairman, President and Chief Executive
                                     Officer of RG&E - January 1998 to date.

                                     President and Chief Operating Officer of
                                     RG&E -January 1997 to December 1997.

Michael J. Bovalino     46           Senior Vice President of RGS - August 1999
                                     to date.

                                     President, Griffith - August 1998 to date.

                                     President and Chief Executive Officer,
                                     Energetix, Inc. January 1998 to date.

                                     Senior Vice President, Energy Services of
                                     RG&E January 1997 to December 1997.

Michael T. Tomaino      64           Senior Vice President and General Counsel
                                     of RGS - August 1999 to date.

                                     Senior Vice President and General Counsel
                                     of RG&E - 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         54           Senior Vice President of RGS - August 1999
                                     to date.

                                     Senior Vice President of RG&E - March 1998
                                     to date.

                                     Director, Gas Services of RG&E - January
                                     1997 to March 1998.
<PAGE>

                                      27

                   Age, as of       Positions, Offices and Business Experience
Name                 1/1/02                        1997 to date
----                 ------         ------------------------------------------

Mark Keogh             56           Treasurer of RGS - August 1999 to date.

                                    Vice President and Treasurer of RG&E -
                                    August 1999 to date.

                                    Treasurer of RG&E - January 1997 to August
                                    1999.


William J. Reddy       54           Controller of RGS - August 1999 to date.

                                    Vice President and Controller of RG&E -
                                    August 1999 to date.

                                    Controller of RG&E - April 1997 to August
                                    1999.

                                    Group Manager, Public Affairs Services of
                                    RG&E - January 1997  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>

                                      28

                                    PART II

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

COMMON STOCK AND DIVIDENDS

<TABLE>
<CAPTION>
                                        RGS/                                                   RGS/
                           RGS    RGS    RGE                                 RGS       RGS      RGE
Earnings/Dividends        2001   2000   1999      Shares/Shareholders        2001     2000     1999
------------------        ----   ----   ----   ------------------------      ----     ----     ----
<S>                      <C>    <C>    <C>     <C>                           <C>      <C>      <C>
Earnings per share                             Number of shares (000's)
       basic             $2.00  $2.61  $2.44       Weighted average
                                                         basic             34,601   35,178   36,665
      diluted            $1.98  $2.60  $2.44            diluted            34,921   35,281   36,757
  Dividends paid                                   Actual number at
     per share           $1.80  $1.80  $1.80          December 31          34,664   34,577   35,943
                                                  Common share price
                                                    at December 31        $ 37.60  $ 32.44  $ 20.56
                                                 Number of  registered
                                                     shareholders
                                                    at December 31         23,422   25,518   27,258
</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.

     On February 20, 2001, RGS announced that it had entered into an Agreement
and Plan of Merger ("Merger Agreement"), dated as of February 16, 2001, with
Energy East Corporation ("Energy East"), a New York corporation, and Eagle
Merger Corp., a New York corporation that will be a wholly owned subsidiary of
Energy East ("Merger Sub") at the effective time of the merger (as defined
below), pursuant to which RGS will be merged with and into Merger Sub ("the
Merger") and RGS will become a wholly owned subsidiary of Energy East. As a
result of the Merger, all of the outstanding common stock of RGS will be
exchanged for a combination of cash and Energy East common stock valued at
approximately $1.4 billion in the aggregate. RGS anticipates that the Merger
will be consummated in the second quarter of 2002.

TAX STATUS OF CASH DIVIDENDS

     Cash dividends paid in 2001, 2000 and 1999 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. RG&E is the largest of RGS's
subsidiaries; therefore, it is expected that for the foreseeable future the
funds required by RGS to enable it to pay dividends will
<PAGE>

                                      29

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 $100.0 million authorization for
unregulated operations (about $8.3 million at December 31, 2001).

     Quarterly dividends on Common Stock are generally paid on the twenty-fifth
day of January, April, July and October. In January 2002, RGS paid a cash
dividend of $0.45 per share on its Common Stock. The January 2002 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 $39.28 on February 5, 2002.

Common Stock - Price Range (dollars)     2001   2000   1999
------------------------------------     ----   ----   ----
  High
     1st quarter                        37.48  21.88  31.56
     2nd quarter                        38.50  24.50  28.44
     3rd quarter                        39.24  28.38  27.31
     4th quarter                        39.35  33.31  25.50
  Low
     1st quarter                        27.75  18.69  25.44
     2nd quarter                        36.05  20.50  25.25
     3rd quarter                        37.34  22.25  24.06
     4th quarter                        37.60  27.38  20.00

<PAGE>

                                      30

ITEM 6 -  SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
CONSOLIDATED SUMMARY OF OPERATIONS                            RGS                  RGS                  RGS
                                                         Consolidated   RG&E  Consolidated   RG&E  Consolidated   RG&E
(Millions of Dollars)           Year Ended December 31,      2001       2001      2000       2000     1999        1999   1998  1997
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>            <C>   <C>            <C>   <C>            <C>    <C>   <C>
Operating Revenues
   Electric                                                 $  734    $  728    $  731     $  722   $  703    $  700  $  688  $ 700
   Gas                                                         358       312       340        322      285       282     275    337
   Liquid fuels and other                                      438         -       377          -      220       109      71      -
                                                            ------    ------    ------      -----   ------    ------  ------  -----

       Total Operating Revenues                              1,530      1,040    1,448      1,044    1,208      1,091  1,034  1,037

Operating Expenses
   Fuel Expenses
     Fuel for electric generation                               58        58        49         49       49        49      54     48
     Purchased electricity                                      93        91        86         81       54        53      27     28
     Gas purchased for resale                                  231       185       209        192      152       149     156    197
     Unregulated fuel expenses                                 384         -       340          -      190        92      59      -
                                                            ------    ------    ------      -----   ------    ------  ------  -----

      Total Fuel Expenses                                      766       334       684        322      445       343     296    273

Operating Revenues Less Fuel Expenses                          764       706       764        722      763       748     738    764

Other Operating Expenses
   Operations and maintenance excluding fuel                   315       315       314        314      298       298     302    315
   Unregulated operating and maintenance
    expenses excluding fuel                                     45         -        31          -       26        14      14      -
   Depreciation and amortization                               121       113       116        112      119       117     116    117
   Taxes - state, local and other                               91        88        95         90      115       113     118    122
   Income taxes                                                 55        55        60         59       64        65      60     65
                                                            ------    ------    ------      -----   ------    ------  ------  -----

      Total Other Operating Expenses                           627       571       616        575      622       607     610    619

Operating Income                                               137       135       148        147      141       141     128    145

Other (Income) and Deductions
   Allowance for other funds used during construction           (1)       (1)       (1)        (1)      (1)       (1)      -      -
   Income taxes                                                (26)      (26)        -          -       (1)       (1)      1     (4)
   RGS/Energy East Merger Expenses                              14        14         -          -        -         -       -      -
   Accelerated Amortization (Nine Mile Two)                     20        20         -          -        -         -       -      -
   Other - net                                                  (8)       (8)       (9)        (9)      (8)       (8)    (13)     3
                                                            ------    ------    ------      -----   ------    ------  ------  -----

      Total Other (Income) and Deductions                       (1)       (1)      (10)       (10)     (10)      (10)    (12)    (1)

Interest Charges
   Long term debt                                               60        59        58         57       54        53      43     45
   Other - net                                                   7         5         5          5        4         5       4      7
   Allowance for borrowed funds used during construction        (2)       (2)       (1)        (1)      (1)       (1)     (1)    (1)
                                                            ------    ------    ------      -----   ------    ------  ------  -----

      Total Interest Charges                                    65        62        62         61       57        57      46     51
                                                            ------    ------    ------      -----   ------    ------  ------  -----

Net Income                                                      73        74        96         96        0         0       0      0
                                                            ------    ------    ------      -----   ------    ------  ------  -----

Preferred Stock Dividend Requirements                            4         4         4          4        4         4       5      6
                                                            ------    ------    ------      -----   ------    ------  ------  -----

Net Income Applicable to Common Stock                       $   69    $   70    $   93      $  92   $   90    $   90  $   89  $  89
                                                            ======    ======    ======      =====   ======    ======  ======  =====

Earnings per Common Share - Basic                           $ 2.00              $ 2.61              $ 2.44            $ 2.32  $2.30

Earnings per Common Share - Diluted                         $ 1.98              $ 2.60              $ 2.44            $ 2.31  $2.30

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

                                      31

Condensed Consolidated Balance Sheet

<TABLE>
<CAPTION>
                                                                   RGS                            RGS
                                                               Consolidated      RG&E         Consolidated       RG&E
(Millions of Dollars)                       At December 31,       2001           2001             2000           2000
----------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>              <C>           <C>               <C>
Assets
Utility Plant                                                    $2,548         $2,493           $3,396         $3,349
Less: Accumulated depreciation and
  amortization                                                    1,464          1,454            2,005          1,990
                                                                 ------         ------           ------         ------
                                                                  1,084          1,039            1,391          1,359
Construction work in progress                                       142            141              111            111
                                                                 ------         ------           ------         ------
Net utility plant                                                 1,226          1,180            1,502          1,470
Current Assets                                                      299            321              307            277
Intangible Assets                                                    34              -               51              -
Deferred Debits and Other Assets                                    952            952              707            706
                                                                 ------         ------           ------         ------
     Total Assets                                                $2,511         $2,453           $2,567         $2,453
============================================================     ======         ======           ======         ======
Capitalization and Liabilities
Capitalization
Long term debt                                                   $  787         $  787           $  792         $  792
Preferred stock redeemable at option
  of RG&E                                                            47             47               47             47
Preferred stock subject to mandatory
  redemption                                                         25             25               25             25
Common shareholders' equity:
  Common stock                                                      708            700              703            700
  Retained earnings                                                 188            174              181            166
  Less: Treasury stock at cost                                      117            117              117            117
                                                                 ------         ------           ------         ------
Total common shareholders' equity                                   779            757              767            749
                                                                 ------         ------           ------         ------
  Total Capitalization                                           $1,638         $1,616           $1,631         $1,613
                                                                 ------         ------           ------         ------
Long Term Liabilities                                               156            132              163            129
Current Liabilities                                                 299            292              317            259
Deferred Credits and Other Liabilities                              418            413              456            452
                                                                 ------         ------           ------         ------
     Total Capitalization and Liabilities                        $2,511         $2,453           $2,567         $2,453
============================================================     ======         ======           ======         ======

<CAPTION>
                                                                   RGS
                                                               Consolidated      RG&E
(Millions of Dollars)                       At December 31,       1999           1999          1998          1997
------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>              <C>           <C>           <C>
Assets
Utility Plant                                                    $3,254         $3,231        $3,327        $3,234
Less:  Accumulated depreciation and
  amortization                                                    1,876          1,874         1,863         1,714
                                                                 ------         ------        ------        ------
                                                                  1,378          1,357         1,464         1,520
Construction work in progress                                        95             96            98            74
                                                                 ------         ------        ------        ------
Net utility plant                                                 1,473          1,453         1,562         1,594
Current Assets                                                      220            203           203           242
Intangible Assets                                                    21              -            21             -
Deferred Debits and Other Assets                                    749            747           667           432
                                                                 ------         ------        ------        ------
     Total Assets                                                $2,463         $2,403        $2,453        $2,268
==========================================================       ======         ======        ======        ======
Capitalization and Liabilities
Capitalization
Long term debt                                                   $  816         $  796        $  758        $  587
Preferred stock redeemable at option
  of RG&E                                                            47             47            47            47
Preferred stock subject to mandatory
  redemption                                                         25             25            25            35
Common shareholders' equity:
  Common stock                                                      700            700           700           699
  Retained earnings                                                 153            138           129           109
  Less: Treasury stock at cost                                       83             83            46             -
                                                                 ------         ------        ------        ------
Total common shareholders' equity                                   770            755           783           808
                                                                 ------         ------        ------        ------
  Total Capitalization                                           $1,658         $1,623        $1,613        $1,477
                                                                 ------         ------        ------        ------
Long Term Liabilities                                               126            125           124           110
Current Liabilities                                                 169            150           183           176
Deferred Credits and Other Liabilities                              510            505           533           505
                                                                 ------         ------        ------        ------
     Total Capitalization and Liabilities                        $2,463         $2,403        $2,453        $2,268
==========================================================       ======         ======        ======        ======
</TABLE>
<PAGE>

                                      32

FINANCIAL DATA

<TABLE>
<CAPTION>
                                                                              December 31
                                                           -------------------------------------------------
RGS
                                                           2001         2000        1999       1998     1997
                                                           ----         ----        ----       ----     ----
<S>                                                       <C>         <C>         <C>          <C>      <C>
      Capitalization ratios
      Long-term debt (1)                                    51.7%       52.3%       51.9%      ----     ----
      Preferred stock                                        4.1         4.1         4.1       ----     ----
      Common shareholders' equity                           44.2        43.6        44.0       ----     ----
                                                          ------      ------      ------
           Total                                           100.0%      100.0%      100.0%      ----     ----
                                                          ======      ======      ======

      Book value per common share - year end              $22.46      $22.19      $21.43       ----     ----
      Rate of return on average common equity (2)           8.76%      11.82%      11.53%      ----     ----

      Embedded cost of senior capital
      Long-term debt                                        6.89%       7.31%       7.20%      ----     ----
      Preferred stock                                       5.24%       5.24%       5.24%      ----     ----
      Interest coverages
      Before federal income taxes (incld. AFUDC)            2.52x       3.39x       3.68x      ----     ----
      Before federal income taxes (excld. AFUDC)            2.49x       3.36x       3.65x      ----     ----
      Interest coverages excluding non-recurring
              Items (3)
      Before federal income taxes (incld. AFUDC)            3.04x       3.39x       3.68x      ----     ----
      Before federal income taxes (excld. AFUDC)            3.00x       3.36x       3.65x      ----     ----

<CAPTION>
                                                                              December 31
                                                           -------------------------------------------------
RG&E
                                                           2001         2000        1999       1998     1997
                                                           ----         ----        ----       ----     ----
<S>                                                       <C>          <C>        <C>         <C>     <C>
      Capitalization ratios
      Long-term debt (1)                                    51.7%       52.0%       51.8%      49.8%    43.0%
      Preferred stock                                        4.2         4.2         4.2        4.2      5.2
      Common shareholder's equity                           44.1        43.8        44.0       46.0     51.8
                                                          ------      ------      ------     ------    -----
            Total                                          100.0%      100.0%      100.0%     100.0%   100.0%
                                                          ======      ======      ======     ======    =====

      Book value per common share - year end              $21.94      $21.71      $21.00     $20.94   $20.80
      Rate of return on average common equity (2)           9.07%      12.12%      11.76%     11.22%   11.00%

      Embedded cost of senior capital
      Long-term debt                                        6.91%       7.29%       7.21%      7.20%    7.32%
      Preferred stock                                       5.24%       5.24%       5.24%      5.56%    5.80%
      Interest coverages
      Before federal income taxes (incld. AFUDC)            2.60x       3.49x       3.74x      4.41x    4.06x
                                  (excld. AFUDC)            2.57x       3.46x       3.71x      4.38x    4.04x

      Interest coverages Excluding Non-Recurring
              Items (3)
      Before federal income taxes (incld. AFUDC)            3.13x       3.49x       3.74x      4.41x    4.06x
      Before federal income taxes (excld. AFUDC)            3.10x       3.46x       3.71x      4.38x    4.04x
</TABLE>

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

(2)  The return on average common equity for 2001 excluding the effects of the
     RGS/Energy East merger expenses and Nine Mile Two accelerated amortization
     for RGS and RG&E is 9.86% and 10.16%, respectively.

(3)  Coverages in 2001 exclude the effect of merger costs and accelerated
     amortization of Nine Mile Two during the year.
<PAGE>

                                      33

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 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, 2001, 47.6 percent of the Company's operating revenues were derived
from regulated electric service, 20.3 percent from regulated natural gas
service, and 32.1 percent from unregulated businesses.

FORWARD LOOKING STATEMENTS

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

  .uncertainties related to the regulatory treatment of RG&E's nuclear
   generation;

  .  any state or federal legislative or regulatory initiatives (including the
     results of negotiations between RG&E and other parties including the PSC
     Staff) 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;

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

  .  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;

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

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

  .  the development of any new technologies, as well as regulatory policies,
     which allow customers to generate their own energy or produce lower cost
     energy;

  .  any unusual or extreme weather or other natural phenomena;

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

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

  .  certain unknowable risks involved in operating unregulated businesses in
     new territories and new industries;
<PAGE>

                                      34

  .  risks associated with the proposed merger of RGS with and into Merger Sub,
     a wholly owned subsidiary of Energy East, at the effective time of the
     Merger, and if the Merger is completed, the integration of RGS and Energy
     East; and

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


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 outstanding preferred stock of RG&E.

     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 and RGS Development.

     RG&E offers regulated electric and natural gas utility service in its
franchise territory.  Energetix provides energy products and services throughout
upstate New York.  RGS Development offers energy systems development and
management services.

     Merger Agreement

     On February 20, 2001, RGS announced that it had entered into an Agreement
and Plan of Merger ("Merger Agreement"), dated as of February 16, 2001, with
Energy East Corporation ("Energy East"), a New York corporation, and Eagle
Merger Corp., a New York corporation that will be a wholly owned subsidiary of
Energy East ("Merger Sub") at the effective time of the merger (as defined
below), pursuant to which RGS will be merged with and into Merger Sub ("the
Merger") and RGS will become a wholly owned subsidiary of Energy East.  As a
result of the Merger, all of the outstanding common stock of RGS will be
exchanged for a combination of cash and Energy East common stock valued at
approximately $1.4 billion in the aggregate.  Energy East also agreed to assume
approximately $1.0 billion of RGS debt.

     Under the Merger Agreement, subject to possible adjustments for tax
reasons, 45% of the RGS common stock will be converted into a number of shares
of Energy East common stock with a value of $39.50 per RGS share, subject to
restrictions on the maximum and minimum number of shares of Energy East common
stock to be issued, and 55% of the RGS common stock will be converted into
$39.50 in cash per RGS share.  RGS shareholders will be able to specify the
percentage of the consideration they wish to receive in shares of Energy East
common stock and in cash, subject to proration.

     At the 2001 Annual Meetings of RGS and Energy East, the shareholders of RGS
approved the Merger Agreement and the shareholders of Energy East approved the
issuance of Energy East shares in connection with the merger.  All regulatory
applications required in connection with the Merger have been filed and all
related regulatory approvals have been received, other than the approvals of the
SEC and PSC.

     On January 15, 2002, RGS and Energy East filed with the PSC a joint
proposal recommending approval of the Merger. The proposal was negotiated among
RGS, RG&E, Energetix, Energy East, and certain of its subsidiaries, the staff of
the PSC, the New York State Consumer Protection Board, the Attorney General of
the State of New York, a group representing large customers of RGS and Energy
East, and certain other interested parties. In addition to recommending approval
of the Merger, the proposal identifies expected savings from Merger synergies,
along with the costs that will be incurred to achieve such savings, for a period
of five years following the closing, specifies an allocation of those savings
between operating companies, and calls for 50% of the savings to be used to
reduce customer
<PAGE>

                                      35

rates with the remainder being retained by the companies. The proposal also
contains provisions to deal with relationships among affiliates and between
affiliates and third parties after the Merger is consummated. In order to become
effective, the proposal must be approved by the PSC. It is currently expected
that the proposal will be acted upon at the PSC's February 27, 2002 meeting.
Assuming the proposal is approved by the PSC at that meeting and that SEC
approval is obtained shortly thereafter, RGS anticipates that the Merger will be
consummated in the second quarter of 2002.


ROCHESTER GAS AND ELECTRIC CORPORATION

     RGS's regulated energy business is conducted through RG&E. RG&E was
incorporated in 1904 in the State of New York and is engaged 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 natural gas in parts of nine counties
including and surrounding the City of Rochester.

     RG&E supplies regulated electric and gas service within a 2,700-square-mile
service territory with a population of approximately one million people.  The
service territory 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.

     PSC Electric Settlement

     During 1996 and 1997, RG&E, the staff of the PSC and several other parties
negotiated the Electric Settlement which was approved by the PSC in November
1997.  The Electric Settlement set the framework for the introduction and
development of open competition in the electric energy marketplace in RG&E's
territory and lasts through June 30, 2002.

     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 are 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 (the "Return on Equity Test"),
50 percent will be used to write down accumulated deferrals or investment in
electric plant or regulatory assets. The other 50 percent of such excess will be
used to write down deferred costs accumulated during the term of the Electric
Settlement and the remainder, if any, will be retained as earnings by RG&E.
There is currently a dispute between RG&E and the staff of the PSC regarding the
calculation of excess earnings under the Electric Settlement (see the discussion
below under "Results of Operations", "2001 Compared to 2000 - Regulated Electric
Expenses").  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.

     Certain provisions of the Electric Settlement terminate as of June 30,
2002, principally those provisions that deal with the effective period for
tariff rates.  Under New York State law, tariff rates do not change unless a PSC
order is issued.  Orders are generally issued by the PSC either in a rate case
proceeding filed by the regulated utility or as a result of settlement
negotiations among the regulated utility, the staff of the PSC, and other
interested parties.  RG&E has filed a new electric and gas rate case with the
PSC as discussed below under the heading "2002 Electric and Gas Rate Proposal".
This action may or may not result in a PSC order prior to June 30, 2002.  If
not, the Company's current base tariff rates for
<PAGE>

                                      36

electric and gas service will likely remain in effect beyond that date until a
new order is issued by the PSC. Under certain circumstances, however, new rates
could be implemented in such a way as to make their impact effective as of July
1, 2002.

     2002 Electric and Gas Rate Proposal

     On February 15, 2002, RG&E filed a request with the PSC for new electric
and gas rate tariffs to go into effect in January 2003.  The filing is comprised
of two components.  The first is a traditional, single-year rate case filing in
the form required by New York State law.  The second is a multi-year settlement
proposal.  RG&E anticipates that the filing will initiate negotiations with the
staff of the PSC and other interested parties regarding long-term rate plans,
electric rate unbundling, electric pricing options and other related programs.

     The traditional single-year filing provides a basis to increase electric
rates by $59.0 million per year (8.2%) and gas rates by $18.7 million per year
(6.6%).  However, in the multi-year proposal RG&E proposes to freeze rates
through the end of 2002 and to set new unbundled rates for electric and gas
delivery service in January 2003.  Increases in the new rates for electric
distribution would be substantially mitigated by merger synergies and benefits
flowing from RG&E's owned generation and would be held constant for a period of
approximately five years.  A summary of this filing is presented under the
heading "2002 Electric and Gas Rate Proposal" in Item 1, Business, of RG&E's SEC
Form 10-K for the fiscal year ended December 31, 2001.

     RG&E believes a multi-year negotiated settlement of these issues would be
in the best interest of all parties.  RG&E, however, is unable to predict
whether any settlement will be achieved or the effect any ultimate PSC decision
in this proceeding will have on RG&E's operating results or financial position.
Likewise, if one or more settlements are achieved and submitted to the PSC for
its approval, RG&E cannot predict how the PSC might rule on any particular
aspect of such settlements.  If a negotiated agreement resolving the issues
involved in the case cannot be achieved, New York State law requires the PSC to
act on RG&E's proposal within eleven months after the initial filing.  Thus, a
PSC decision is expected no later than January 2003.

     Sale of Interest in Nine Mile Two

     On November 7, 2001, RG&E sold its ownership interest in Nine Mile Two to
Constellation Nuclear.  The purchase price for RG&E's interest was $101.0
million, $50.5 million of which was paid in cash at the closing and $50.5
million of which will be paid in five equal annual principal installments plus
interest at a rate of 11 percent pursuant to a five year promissory note.
Principal and interest payments under the promissory note will total
approximately $67.1 million unless the note is pre-paid.  In addition, RG&E
received approximately $1.9 million cash for the sale of its share of certain
transmission assets related to the Nine Mile Two facility.

     At November 7, 2001, the net book value of RG&E's 14 percent interest in
the Nine Mile Two generating facility was approximately $348.8 million.  RG&E
also had investments in fuel of approximately $6.0 million, transmission and
distribution facilities of $3.3 million, materials and supplies inventory of
$6.9 million, and construction work in progress of $7.6 million.

     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 completion of the term 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
<PAGE>

                                      37

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 allocated
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 the closing, RG&E's pre-existing decommissioning funds relating to Nine
Mile Two were transferred to Constellation Nuclear and Constellation Nuclear
assumed RG&E's obligation to decommission Nine Mile Two.

     RG&E and the staff of the PSC entered into a settlement dated August 7,
2001 (the "Nine Mile Two Settlement") that addresses the rate-making treatment
associated with RG&E's recovery of its remaining investment in Nine Mile Two and
related costs.  The settlement was approved by the PSC in an order issued on
October 26, 2001.  Under the settlement, RG&E is authorized to establish a
regulatory asset calculated in accordance with the provisions of the settlement
that, as of November 7, 2001, was estimated to be approximately $325.6 million.
RG&E agreed to a one-time pre-tax accelerated amortization of $20.0 million of
this regulatory asset.  In addition, RG&E accelerated its recognition of
previously deferred investment tax credits that amounted to $12.9 million.  RG&E
has also agreed to amortize, during the period from the closing of the sale of
Nine Mile Two until RG&E's base electric rates are re-set, an additional amount
of this regulatory asset to reflect the projected reduction in RG&E's expenses
of owning and operating Nine Mile Two prior to the sale compared to the
estimated expenses that it will incur in purchasing the amount of electricity
after the sale that is equivalent to RG&E's pre-sale share of the output.  The
amortization during this period will be calculated using an amortization rate of
$30.0 million per year. The terms associated with the recovery of the remaining
regulatory asset will be established in future RG&E rate proceedings.  The
settlement further provides that it constitutes a final and irrevocable
resolution of all RG&E rate-making issues associated with the sale of Nine Mile
Two and RG&E's ability to recover costs associated with its investment in Nine
Mile Two through its rates.

     In connection with the sale of Nine Mile Two, RG&E informed Niagara Mohawk
that RG&E's rights and obligations under a June 8, 1998 Exit Agreement will
cease as it pertains to payments for certain transmission facilities relating to
RG&E's ownership of a portion of Nine Mile Two.  Niagara Mohawk is disputing
RG&E's position as discussed further under the heading "Exit Agreement Relating
to Nine Mile Two" in Item 3, Legal Proceedings, of RG&E's SEC Form 10-K for the
fiscal year ended December 31, 2001.  The Nine Mile Two Settlement provides that
the Nine Mile Two regulatory asset would be adjusted for any amount RG&E is
found responsible for in the resolution of the Exit Agreement dispute.

     PSC Nuclear Initiative

     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
have now been sold, except for RG&E's Ginna Plant, the PSC could regard the
proceeding as moot.

     PSC Gas Settlement

     On January 25, 2001, RG&E reached agreement with PSC staff and other
parties on a comprehensive rate and restructuring settlement for its natural gas
business (the "PSC Gas Settlement"). The PSC Gas Settlement was approved by the
PSC, with some modifications, on February 28, 2001 and became effective on March
1, 2001. Rate-related provisions of the Gas Settlement extend from July 1, 2000
through June 30, 2002.
<PAGE>

                                      38

     For the purpose of setting base, or local delivery, rates for the period
beginning July 1, 2000, natural gas revenues were decreased a total of
approximately $3.0 million from the levels in effect on June 30, 2000.  This
rate level is based on an agreed-upon return on equity of 11.00%.  Base rates
were adjusted effective March 1, 2001 to reflect the revenue requirements
decrease.  Because the base rates that were in effect through February 28, 2001
were higher than those agreed to by the parties, RG&E, in March 2001, passed
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.  In the event that RG&E achieves a
return on equity in excess of 12.5% in any rate year covered by the Gas
Settlement, 90% of the excess over that level will be deferred for the benefit
of customers.

        Competition and RG&E's Prospective Financial Position

     To the extent that its own generation and power purchased under long-term
contracts are not sufficient to supply the requirements of its own customers,
RG&E must purchase electric capacity and energy in the open market and is
therefore exposed to market pricing for its wholesale purchases.  Because RG&E
does not have an electric fuel cost adjustment clause under the current Electric
Settlement, changes in the cost of electricity cannot be routinely flowed
through to its customers.  The resulting risk, however, is reduced to a
significant degree by the use of hedging transactions for periods when prices
are likely to be most volatile, the purchase of generation insurance for forced
outages, the use of proceeds from energy and capacity sales RG&E is able to make
at other times, and the provisions of the Nine Mile Two sale whereby RG&E has
the right and obligation for a multi-year period to purchase up to 90 percent of
the output of the plant corresponding to RG&E's original ownership interest and
has the opportunity to share in the proceeds of sales above certain thresholds.

     On the retail side of its electricity business, RG&E is exposed to the
impact of losing load to competitive suppliers of electricity.  To the extent
that retail customers, taking advantage of RG&E's Energy Choice program, no
longer take their electric requirements from RG&E, the native load served by
RG&E could decline to a point where the capacity of RG&E-owned generation
exceeds load levels much of the time.  In that event, RG&E is at risk to the
extent that the costs of its generation exceed market prices.  Although the
migration of customers to competing suppliers has slowed recently, thereby
reducing this risk, an increase in migration rates could readily lead to
intensified risk. Also mitigating this risk is the "full requirements" option
that provides competing suppliers with the option to purchase energy and
capacity directly from RG&E for the purpose of supplying load in the Company's
service territory.  Pricing for this program is such that RG&E is effectively
indifferent as to whether the energy is sold directly to a retail customer or to
a competitive supplier.  To date, practically all of the competitive suppliers
have chosen this option for most of the load that they serve.

     RG&E's gas business is also exposed to significant risks resulting from the
emerging competitive market.  Although RG&E's current gas settlement with the
PSC contains a gas cost adjustment clause which permits the pass-through of most
changes in gas costs to its customers, those settlements place RG&E at risk to
the extent that certain costs, particularly pipeline capacity costs, exceed
particular thresholds.  The migration of customers to other suppliers of gas
under RG&E's retail access program also has an impact on risk.  Although the
retail access program for gas is intended to permit RG&E to match its resources
to the needs of the customers it must serve, the practical difficulties
associated with attempting to predict migration levels and to assign pipeline
and storage capacity to correspond with those levels can result in the risk of
under-recovery of costs incurred.

     With PSC approval, RG&E has deferred certain costs rather than recognizing
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 of
the Notes to Financial Statements.
<PAGE>

                                      39

     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.  For a discussion of strandable assets, see
Note 3 of the Notes to Financial Statements under the heading "Regulatory
Assets".

     At December 31, 2001, RG&E believes that its regulatory assets are probable
of recovery.  None of the Electric Settlement, the Nine Mile Two Settlement, or
any gas settlements RG&E has entered into impair the opportunity of RG&E to
recover its investment in these assets at December 31, 2001.  However, the PSC
initiated a proceeding in 1998 to address issues surrounding nuclear generation
(see  "PSC Nuclear Initiative").  The ultimate determination in this proceeding
could have an impact on strandable assets and the recovery of nuclear costs.

UNREGULATED SUBSIDIARIES OF RGS

     RGS has two unregulated subsidiaries, Energetix and RGS Development.  As of
December 31, 2001, RGS had invested $90.1 million (including loans and loan
guarantees) in Energetix and $1.6 million in RGS Development against an
aggregate maximum of $100.0 million for unregulated operations as allowed by the
Electric Settlement.

     Energetix

     Energetix, formed in January 1998, markets electricity, natural gas, oil,
gasoline, and propane fuel energy services throughout upstate and central New
York.  In August 1998, Energetix acquired Griffith, the second largest
distributor of liquid fuels in New York State.  In November 2000, Griffith
acquired Burnwell Gas ("Burnwell"), a full-service propane gas retailer and
distributor, and certain assets of the New York Fuels Division of AllEnergy
Marketing Company, L.L.C., related to its petroleum distribution business.

     Energetix, as an unregulated competitor in the electric and gas retail
access programs of RG&E and other upstate New York utilities, faces primarily
the risk of competition from other ESCOs.  Energetix must compete for customers
with other ESCOs and, therefore, must price its electric and gas service
accordingly.  In addition, as a marketer without its own generation, Energetix
must purchase all of its electric requirements (for resale to its customers) in
the market.  Currently, Energetix is able to purchase the full energy and
capacity requirements for most of its customers, who are in RG&E's service
territory, from RG&E at fixed rates.  On the gas side, Energetix is more exposed
to the wholesale market where gas prices have been particularly volatile.
Energetix, however, has been able to reduce this price risk to a significant
degree through hedging transactions.  Energetix also competes with other liquid
fuel companies in its liquid fuels business.

     Additional information on Energetix's operations (including Griffith) is
presented under the headings "Earnings Summary - Unregulated Revenues" and
"Unregulated Expenses" and in Note 4 of the Notes to Financial Statements.

     RGS Development Corporation

     In 1998, the Company formed RGS Development to pursue unregulated business
opportunities in the energy marketplace.  Through December 31, 2001, RGS
Development's operations have not been material to RGS's results of operations
or its financial condition.

LIQUIDITY AND CAPITAL RESOURCES

     During 1999, 2000 and 2001, RGS's and RG&E's cash flow from operations,
short-term credit arrangements, and long-term financings (see Statements of Cash
Flows) provided the funds for utility
<PAGE>

                                      40

plant construction expenditures, unregulated business acquisitions, payment of
dividends, purchase of treasury stock, and retirement of short-term and long-
term debt. In addition, during 2001 cash proceeds from the sale of Nine Mile Two
and related facilities was also available to meet capital requirements. Capital
requirements of the Company during 2002 are anticipated to be satisfied from a
combination of funds from operations, short-term credit arrangements, proceeds
from the Nine Mile Two Promissory Note, and the issuance of long-term debt. RG&E
may also refinance long-term securities obligations during 2002 depending on
prevailing financial market conditions.

     Investing Activities

     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.  In 2001, proceeds from the sale of Nine Mile Two (see "Sale of
Interest in Nine Mile Two") and no additional business acquisitions by Griffith
during the year resulted in a net reduction to cash used for investing
activities.  Net additions to utility plant for RGS and RG&E increased slightly
in 2001 compared to a year earlier.

     RGS's and RG&E's construction requirements over the past three years have
related primarily to expenditures for electric production facilities, nuclear
fuel, and energy delivery, including electric transmission and distribution
facilities and gas mains and services.  RG&E has no current plans to install
additional baseload generation.

     Capital requirements for the Company over the three-year period 1999 to
2001 and the current estimate of capital requirements through 2004 are
summarized in the Capital Requirements table.  RG&E's portion of total
construction requirements as presented in the Capital Requirements table for
2002, 2003, and 2004 are $148 million, $165 million, and $127 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.

<TABLE>
<CAPTION>
Capital Requirements - RGS
----------------------------------------------------------------------------------------
                                                  Actual                   Projected
                                          1999       2000    2001      2002   2003  2004
Type of Facilities                                    (Millions of Dollars)
----------------------------------------------------------------------------------------
<S>                                      <C>        <C>     <C>       <C>    <C>    <C>
Electric Property
    Production                           $  14      $  12   $  15     $  18  $  21  $ 10
    Energy Delivery                         42         63      62        65     70    58
                                         -----      -----   -----     -----  -----  ----
        Subtotal                            56         75      77        83     91    68
    Nuclear Fuel                            14         22       1        12     15    15
                                         -----      -----   -----     -----  -----  ----
        Total Electric                      70         97      78        95    106    83
Gas Property                                19         23      31        26     30    29
Common Property                             20         23      40        28     31    18
                                         -----      -----   -----     -----  -----  ----
        Total                              109        143     149       149    167   130
Carrying Costs
    Allowance for Funds Used During
        Construction                         2          2       3         3      3     2
                                         -----      -----   -----     -----  -----  ----

    Total Construction Requirements        111        145     152       152    170   132
Acquisitions, Net of Cash                    3         49    ----      ----   ----  ---
Securities Redemptions, Maturities
    and Sinking Fund Obligations*           19         37     112       114     94    15
                                         -----      -----   -----     -----  -----  ----
        Total Capital Requirements       $ 133      $ 231   $ 264     $ 266  $ 264  $147
                                         -----      -----   -----     -----  -----  ----
</TABLE>

    *   Excludes prospective refinancings.
<PAGE>

                                      41

     Financing Activities

     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.

     On April 6, 2001, RG&E utilized its shelf registration and issued $200
million principal amount of 6.95% First Mortgage Bonds, Series TT, due 2011.
The net proceeds from this financing were used to redeem RG&E's Series PP First
Mortgage Bonds, as described below, and to repay $39 million of outstanding
short-term debt.

     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 9 of the Notes to Financial
Statements.  As financial market conditions warrant, RG&E may also, from time to
time, redeem higher-cost long-term securities.

     The number of outstanding shares of common stock of RGS increased by 70,913
shares in 2000 and 86,116 shares in 2001 as a result of options that were
exercised under the Company's Performance Stock Option Plan.  These were the
only shares of common stock issued in 2000 and 2001.  RGS did not issue any
additional shares of common stock in 1999.

     In addition to first mortgage bond maturities and mandatory sinking fund
obligations of $40.0 million over the past three years, discretionary early
redemption of long-term securities totaled  $100.0 million in 2001. On May 10,
2001, RG&E, at its option, redeemed prior to maturity $100.0 million principal
amount of its 9 3/8% First Mortgage Bonds, Series PP at a price of 104.47%.
There were no discretionary redemptions of long-term securities in 1999 or 2000.

     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 were repurchased for
approximately $117.2 million.  The Company completed its share repurchase
program in the fourth quarter of 2000.

     Credit Ratings

     The RGS corporate credit rating from Standard and Poor's Corporation
("S&P") was "A-" at December 31, 2001. RGS has not issued any mortgage bonds or
preferred stock.

     RG&E's securities ratings at December 31, 2001 were:

                                        First
                                      Mortgage  Preferred
                                        Bonds     Stock
                                      --------  ---------

     Standard & Poor's Corporation    A-        BBB
     Moody's Investors Service        A3        Baa3
     Fitch                            A-        BBB

     The securities ratings stated above are subject to revision and/or
withdrawal at any time by the respective rating organizations.
<PAGE>

                                      42

     RG&E has made a financial guarantee on behalf of Energetix which obligates
RG&E in the event of a default by Energetix in payments under a Promissory Note
issued in connection with the acquisition of Griffith by Energetix (see Note 6
of the Notes to Financial Statements).  Under this guarantee, if RG&E's First
Mortgage Bond rating from two rating agencies falls below investment grade,
defined as BBB for S&P and Baa3 for Moody's, then an event of default has
occurred and the entire principal of the Note then outstanding, together with
accrued interest, becomes due immediately.  RG&E currently believes it could
obtain the necessary funds, if necessary, to meet its obligation under this
provision of the Note.

     None of RG&E, Griffith, or Energetix have entered into any other debt
agreements, guarantees, leases, or other agreements whereby the loss of
investment grade credit of senior secured debt would trigger early payments,
require additional collateral, or impair the ability of these entities to
continue critical business transactions.

     Financial Tests

     Under the provisions of its General Mortgage dated September 1, 1918, as
amended and supplemented, RG&E must meet certain financial requirements before
additional First Mortgage Bonds  may be issued.  Under the most restrictive of
these provisions, RG&E could issue $240.0 million of additional First Mortgage
Bonds at December 31, 2001.  RG&E does not currently expect this provision to
limit any prospective issuances of First Mortgage Bonds.

     Under provisions of Griffith's $33.0 million revolving credit agreement, if
certain financial coverage ratios are not maintained, the lenders under the
credit agreement may terminate commitments and/or declare any outstanding loan
amounts due and payable in full. Griffith currently anticipates meeting all
ratio coverage provisions under this credit agreement.  Energetix guarantees
payments under this agreement on behalf of Griffith.  Neither RG&E nor Energetix
has entered into any short term credit arrangements that contain financial tests
that would limit borrowings under such agreements.

     The certificate of incorporation of RGS does not contain any financial
tests for the issuance of common stock or preferred stock.  The certificate of
incorporation of RG&E does not contain any financial tests for the issuance of
common stock; however, it does have financial tests for the issuance of
preferred stock.  Under the most restrictive of these provisions, RG&E could
issue approximately $294.0 million of additional preferred stock at December 31,
2001.  This provision is not expected to limit the issuance of any additional
preferred stock which may be required to fund RG&E's capital requirements as
currently anticipated.

     Commercial Relationships

     RG&E enters into relationships for electric and gas supply and ESCO-related
services that subject the Company to credit risk.  The Company manages this risk
through the qualification of counter-parties with whom it engages in such
transactions.  Counter-parties not meeting minimum financial requirements, as
specified in the Company's credit policy and based on the counterparty's senior
unsecured debt ratings, must provide credit enhancement to transact with the
Company.  In addition, the Company assigns all such counter-parties a credit
limit.  The Company monitors the credit quality of its counter-parties and its
exposure to all counter-parties against their respective credit limits on an on-
going basis.

     At December 31, 2001, RGS was providing credit support of $54.1 million to
Energetix in the form parent guarantees.

     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,
<PAGE>

                                      43

recycling and waste minimization, and training of employees in hazardous waste
management) to reduce the potential for adverse environmental effects from
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 their 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 11 of the Notes 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 purchased 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. RG&E has filed a request with the PSC for new electric tariffs
commencing in January 2003. The rate request proposes offering electric
customers a choice between one-year fixed price and monthly variable price
offerings. Both pricing options will further reduce RG&E's exposure to market
price fluctuations in the electric wholesale market. However, RG&E will continue
to bear the risk of operating performance at the generating plants it owns, as
well as Nine Mile Two, for which RG&E holds a unit-contingent power purchase
agreement.

     While owned generation provides RG&E with a natural hedge against electric
price risk, it also subjects it 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 reduces RG&E'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.

     Recently Issued Accounting Pronouncements

     Information regarding recently issued accounting pronouncements by the FASB
can be found in Note 1 to Financial Statements.

     Application of Critical Accounting Policies

     The Company follows generally accepted accounting principles in recording
and reporting its financial information. Because RG&E is a regulated company,
SFAS-71, Accounting for the Effects of Certain Types of Regulation, is a
critical standard which allows RG&E to record certain expenditures as deferrals
for amortization over the period RG&E is recovering those costs in the rates
charged to its customers, rather than as current expenses. Other key accounting
policies followed by the Company are identified and described in Note 1 of the
Notes to Financial Statements.
<PAGE>

                                      44

EARNINGS SUMMARY

     RGS

     RGS reported consolidated earnings of $2.00 per common share in 2001
compared to $2.61 per common share in 2000. Having a negative effect on earnings
in 2001 were non-recurring expenses of $14.3 million related to the pending
merger with Energy East, electric base rate reductions, lower electric and gas
sales to industrial customers resulting, in part, from a general economic
decline compared with a year ago, and recognition of expenses in connection with
the 2002 refueling of the Ginna Plant. Increased sales of electricity into the
wholesale market, due to the increased availability of RG&E's generating
facilities and warmer summer weather which enhanced electric air conditioning
load sales, and a decrease in the Company's uncollectible expense reserves
positively affected 2001 results. Earnings results for 2001 resulted in RG&E
increasing its reserves for earnings in accordance with the Return on Equity
Test pursuant to the Electric Settlement (see "Results of Operations - 2001
Compared to 2000 - Operating Expenses").

     RGS continues to grow its unregulated business through its subsidiary
Energetix. Energetix's unconsolidated operating revenues were $619.9 million in
2001, of which sales from Griffith and its subsidiaries contributed
approximately $437.8 million. Griffith revenues are included under "Liquid Fuels
and Other Revenues" on RGS's and, prior to August 1999, in RG&E's Income
Statements. Higher revenues in 2001 reflect an increase due to customer growth
and business acquisitions by Griffith in November 2000.

     RG&E

     Earnings for RG&E in 2001 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 Corporation 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. RG&E's electric revenues include $107.2 million in 2001, $78.2 million in
2000, and $44.5 million in 1999 related to energy sales to Energetix (see Note 4
of the Notes to Financial Statements for additional information regarding
intersegment sales between RG&E and Energetix). RG&E's gas revenues also include
$21.7 million in 2001, $1.9 million in 2000, and $0.4 million in 1999 related to
therm sales to Energetix.

RESULTS OF OPERATIONS

     The following financial review identifies the factors having a significant
impact on the amounts of revenues and expenses for the Company's operating
segments, comparing 2001 to 2000 and 2000 to 1999. The Notes to Financial
Statements contain additional information. 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.

     2001 COMPARED TO 2000
     ---------------------

     Operating Revenues and Sales

     Regulated Electric Revenues

     RG&E's electric revenues were $6.4 million higher in 2001 driven by
increased revenues from the sale of energy to other electric utilities. Revenues
from sales to other utilities were up $6.4 million resulting from an increase in
energy kilowatt-hour sales due to increased output from RG&E's generation
facilities. These increased revenues were partially offset by lower average
market prices for electricity.
<PAGE>

                                      45

RG&E's ability to generate revenues from electric sales to other utilities is
affected by a combination of factors including RG&E's customers' energy
requirements, the wholesale energy market, the availability of transmission, and
the availability of electric generation from RG&E's facilities.

     RG&E's electric operating revenues from regulated retail customers and
ESCOs were down $0.3 million. The effects of electric base rate reductions
implemented in July 2000 and July 2001 under the Electric Settlement and the
effects of a general economic decline on electric sales, in particular sales to
industrial customers, were partially offset by favorable weather conditions for
air conditioning load during the summer of 2001, which was 55% warmer than a
year ago based on cooling degree days.

     In addition to a general economic decline, the drop in 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 2001 are $126.0
million of revenues from electric sales to energy marketers, including $107.2
million of revenues from Energetix. As the electric market continues to develop,
RG&E expects its retail electricity sales to decline and its electricity sales
to ESCOs to increase.

     Regulated Gas Revenues

     Regulated gas revenues to retail customers were down $13.8 million in 2001.
These lower revenues reflect a decrease in the usage of natural gas during the
year due, in part, to warmer weather which was 9% warmer than a year ago based
on heating degree days.

     Gas revenues from therms of gas sold and transported for customers who are
able to purchase natural gas from sources other than RG&E were $34.9 million in
2001 compared with $32.2 million in 2000. RG&E's facilities are used to
distribute this gas, which in total amounted to 23.4 million dekatherms in 2001
and 24.0 million dekatherms in 2000. These purchases by eligible customers are
not included in RG&E's retail therm sales, resulting in decreases in RG&E's
retail gas customer revenues and corresponding decreases in purchased gas
expenses. These sales generally do not adversely affect RG&E's 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 to retail customers.

     Unregulated Revenues

     Unregulated unconsolidated revenues were $619.9 million in 2001, compared
to $484.0 million for 2000. The increase of approximately 28% is attributable
primarily to an aggressive expansion program that included seven business
acquisitions by Griffith during 2000 (see "Unregulated Subsidiaries of RGS -
Energetix"), as well as increased quantities of electricity and natural gas sold
to an expanding customer base. Higher unregulated sales also reflect, in part,
the migration of electric and gas customers from the regulated to the
unregulated business. For additional information regarding intersegment sales
between RG&E and Energetix, see Note 4 of the Notes to Financial Statements.

     Seventy-one percent of Energetix's total operating revenues in 2001 were
from the sale of liquid fuels by Griffith and its subsidiaries (see discussion
under "Earnings Summary"). For heating oil and propane, Griffith and its
subsidiaries experience 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.
<PAGE>

                                      46

     Operating Expenses

     Regulated Electric Expenses

     Fuel for electric generation for 2001 was up $9.3 million due to the
increased fuel consumption resulting primarily from higher availability of
RG&E's fossil-fueled generation plants and the Ginna Plant that was shutdown
during 2000 for refueling. Purchased electricity expense for RG&E increased
mainly because of higher market prices per megawatt-hour purchased, in addition
to a slight increase in units purchased. This higher expense was partially
offset by reduced expenses for hedging activities. The increase in units
purchased reflects, in part, the loss of generation from Nine Mile Two which was
sold in November 2001. The sale of Nine Mile Two will have the effect of
increasing RG&E's purchased units (kilowatt-hours) in 2002 because the energy it
receives from Nine Mile Two will be purchased under an agreement entered into in
connection with the sale of the plant, as discussed under the heading "Sale of
Interest in Nine Mile Two". The cost of purchased power may fluctuate depending
on the availability of electric generation from RG&E's facilities, the wholesale
energy market, 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 RG&E's 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 increase in 2001 non-fuel regulated electric operating expenses
includes $4.5 million of expense associated with the amortization of the Nine
Mile Two regulatory asset beginning November 2001. In addition, $2.7 million of
electric competitive implementation costs were expensed and are no longer being
deferred pursuant to certain provisions of the Electric Settlement. Additional
expense of $4.3 million was recognized in 2001 in connection with the scheduled
2002 Ginna Plant refueling outage. Also, there was a $3.0 million increase in
expenses in 2001 due to a Nine Mile Two inventory credit adjustment that was
recognized in the third quarter of 2000. These higher expenses were partially
offset by a $8.5 million drop in expense compared with a year earlier in
connection with the establishment of earnings and tax reserves as discussed in
the following paragraph and a decrease of $2.2 million (electric operating
expense only) associated with a drop in RG&E's uncollectible expense reserves
due to improved collection techniques.

     The financial results for 2001 resulted in a $9.8 million increase in the
earnings reserve established during 2000 in accordance with the provisions of
the Return on Equity Test as previously discussed under the heading, "PSC
Electric Settlement." The earnings and tax reserves established pursuant to the
Electric Settlement totaled $28.1 million at December 31, 2001 compared with
$18.3 million at year-end 2000, and are reflected in the fluctuation of non-fuel
operating expenses for the comparison period. RG&E has been notified by the PSC
staff that their measurement of electric regulatory earnings over 11.50% is
approximately three times the $26.1 million that RG&E has reserved for such
excess earnings. RG&E's estimate is based on the full five-year term of the
Electric Settlement while the PSC staff's estimate is based on only the first
four years and does not take into account the last six months of 2001 nor the
first six months of 2002. In addition, there are differences in the methodology
being considered to calculate such regulatory earnings. Management has reviewed
the differences and believes a reserve of $26.1 million adequately considers the
items of disagreement at this time. Calculation of the regulatory earnings will
be subject to future negotiation with the PSC staff and will be subject to final
approval by the PSC. Final regulatory earnings as determined by RG&E for the
five-year period will not be known until the final year under the Electric
Settlement is concluded on June 30, 2002 and a filing is made by RG&E with the
PSC about September 2002. RG&E is unable to predict what the PSC's ultimate
determination of excess regulatory earnings under the Electric Settlement will
be.

     Local, state and other electric operating taxes were $2.7 million lower
during 2001 reflecting lower state revenue taxes due to a decrease in taxable
revenues and a greater power-for-jobs tax credit in 2001 compared to a year ago.
<PAGE>

                                      47

     Regulated Gas Expenses

     The cost of gas purchased for resale decreased by $7.3 million in 2001,
driven mainly by a decrease in the volume of gas purchased which was partially
offset by a higher average commodity cost of gas for the year. RG&E's regulated
gas tariffs include a monthly gas adjustment clause that 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. As stated above, RG&E does not earn a return on the gas capacity and
commodity it acquires for distribution to its customers.

     The decrease in non-fuel regulated gas operating expenses includes lower
expenses totaling $1.8 million (gas operating expense only) in connection with a
drop in RG&E's uncollectible expense reserves as discussed under the heading
above, "Regulated Electric Expense".

     Local, State and other gas operating taxes were $0.4 million higher during
2001 reflecting mainly higher property taxes due to higher property assessments
and higher school tax rates.

     Unregulated Expenses

     Unregulated unconsolidated fuel expenses increased $119.4 million in 2001
over 2000 to $561.2 million. This increase of 27% is primarily attributable to
operations acquired by Griffith in November 2000. Also contributing to the
higher fuel expense is an increase in the volumes of natural gas and electricity
sold, and a year-to-date charge of approximately $2.4 million for the "mark to
market" of call options associated with Energetix's risk management initiatives,
as required under SFAS 133 (see Note 1 of the Notes to Financial Statements).

     The increase in unregulated non-fuel operating expenses reflects primarily
the operations acquired by Griffith in November 2000.

     Depreciation and amortization expense for unregulated operations increased
$3.8 million in 2001 to $7.9 million due primarily to the operations acquired by
Griffith in November 2000.

     Income Taxes

     The difference in income tax operating expense for RGS and RG&E is
attributable mainly to lower 2001 pretax earnings.

     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, in 2001, the tax
benefit of a one-time recognition of unamortized investment tax credits of $12.9
million associated with the sale of Nine Mile Two in November 2001.

     One-time merger expenses of $14.3 million were recorded by RGS during 2001
in connection with the pending merger with Energy East (see "Merger Agreement"
heading above). Management believes that substantially all of the anticipated
merger-related expenses have been recorded as of December 31, 2001.

     As a result of the October 26, 2001 PSC approval of the sale of RG&E's
interest in Nine Mile Two, RG&E recognized a one-time pretax accelerated
amortization of $20.0 million associated with the Nine Mile Two regulatory
asset. Concurrently with this charge, the PSC allowed RG&E to recognize $12.9
million of investment tax credits as discussed above.
<PAGE>

                                      48

     The change between 2001 and 2000 in RGS's and RG&E's Other Income and
Deductions, Other-net reflects mainly additional expense in the current period
compared to a year ago when in November 2000 RG&E recognized a $3.0 million
credit adjustment associated with RG&E management performance awards. This
increased expense was partially offset by additional income in 2001 from
temporary cash investments and interest income on a Promissory Note in
connection with the sale of Nine Mile Two.

     The increase in interest expense for both RGS and RG&E was driven by the
$200 million bond financing in April 2001, which was partially offset by the
$100 million redemption of bonds in May 2001 as discussed in "Financing
Activities" above. With respect to RGS, interest payments on a promissory note
issued in November 2000 in connection with the acquisition by Griffith of
Burnwell Gas also increased interest expense in 2001.

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

     Operating Revenues and Sales

     Regulated Electric Revenues

     RG&E's electric revenues were $23.0 million higher in 2000 which reflects
higher revenues from the sale of energy to other electric utilities. Revenues
from these sales were up $48.3 million due to a combination of higher market
prices and an increase in energy kilowatt-hour sales.

     Partially offsetting the favorable results of energy sales to other
utilities was a decrease in electric revenues from regulated retail customers
and electric revenues from ESCOs of $25.2 million in 2000. These lower revenues
reflect a one-time June 1999 unbilled electric revenue adjustment of $7.1
million, unfavorable weather conditions for air conditioning load during the
summer of 2000 which was nearly 40% colder than 1999 based on cooling degree
days, and electric base rate reductions that became effective July 1, 1999 and
July 1, 2000 under terms of the Electric Settlement.

     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. As stated above, however, RG&E 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, including $78.2 million of revenues
from Energetix.

     Regulated Gas Revenues

     Regulated gas revenues to retail customers were up $32.8 million in 2000
compared with 1999. This increase reflects higher commodity prices for natural
gas during 2000 and 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. Partially offsetting these results was the effect of a one-
time June 1999 unbilled gas revenue adjustment of $6.1 million and rate
reductions in 2000 totaling $1.4 million. Gas revenues from therms of gas sold
and transported for customers who are able to purchase natural gas from sources
other than RG&E were $32.2 million in 2000 compared with $21.2 million in 1999,
reflecting the cooler weather and increased sales to aggregations of low-usage
gas customers.

     Unregulated Revenues

     Seventy-eight percent of Energetix's total operating revenues in 2000 were
from the sale of liquid fuels by Griffith (see discussion under "Earnings
Summary"). Energetix's total operating revenues were $484.0 million in 2000,
compared to $275.1 million for 1999. The increase of approximately 75% is
attributable primarily to an aggressive expansion program that included a total
of seven businesses
<PAGE>

                                      49

acquired by Griffith during 2000, and two acquisitions in 1999, as well as
increased quantities of electricity and natural gas sold to an expanding
customer base. Higher unregulated sales also reflect, in part, the migration of
electric and gas customers from the regulated to the unregulated business. For
additional information regarding intersegment sales between RG&E and Energetix,
see Note 4 of the Notes to Financial Statements.

     Operating Expenses

     Regulated Electric Expenses

     Total regulated electric fuel expenses were $27.4 million higher during
2000, reflecting increased purchased electricity costs resulting from 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 increase in non-fuel electric operating expenses in 2000 for RG&E
includes an increase of $18.4 million for electric transmission and wheeling
charges related to the implementation of the NYISO, increased regulatory
amortization associated with the closing of the Oswego Generation Facility ($5.2
million), and an accrual for site remediation costs ($1.5 million). These
increases were offset by a $7.7 million drop in RG&E welfare expense associated
with the performance of pension assets (see Note 5 of the Notes to Financial
Statements), lower expenses in 2000 due to an increase in June 1999 of the RG&E
reserve for uncollectible accounts ($4.3 million), the absence of Y2K expenses
($2.9 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 a Nine Mile Two
inventory losses due to the then-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.
At December 31, 2000, these reserves were comprised of a $16.3 million reserve
based on the provisions of the Return on Equity Test (as previously discussed
under the heading "PSC Electric Settlement") and a $2.0 million reserve for
estimated property tax savings. These reserves are reflected in non-fuel
operating expenses.

     A decrease in regulated depreciation expense for 2000 is due mainly to an
incremental one-time charge in the second quarter of 1999 of approximately $2.1
million associated with the closing of RG&E's Beebee Generating Station in April
1999.

     Local, state and other electric operating taxes declined mainly as a result
of lower regulated electric revenue taxes, 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 above.

     Regulated Gas Expense

     The cost of gas purchased for resale increased in 2000 driven mainly by the
rise in the commodity cost of gas.

     The decrease in non-fuel gas operating expenses includes lower expenses of
$2.8 million in connection with lower pension expense, lower expense of 2.8
million compared to 1999 when in June 1999 RG&E increased its reserve for
uncollectible accounts, and the absence of Y2K expenses ($1.9 million) (see
"Regulated Electric Expense" above for a further discussion of these items).

     Local, state and other gas operating taxes declined mainly as a result of
lower regulated gas revenue taxes, a lower gross receipts tax, elimination of
the excess dividends tax effective January 1,
<PAGE>

                                      50

2000, and lower property taxes resulting from the retirement of RG&E generating
facilities in 1999 as mentioned above.

     Unregulated Expenses

     Unregulated fuel expenses reflect mainly the cost of purchased fuel for
Griffith's operations due to the addition of operations acquired by Griffith
during 2000.

     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 and amortization expense for unregulated operation increased
$0.9 million in 2000 to $4.1 million due primarily to Griffith acquisitions
during 2000.

     Income Tax

     The difference in income tax operating 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 10 of the Notes 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).

     The increase in interest expense for both RGS and RG&E reflects 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.

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. RG&E is the largest of RGS's
subsidiaries, therefore 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 $8.3 million
at December 31, 2001).
<PAGE>

                                      51

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     RG&E is exposed to interest rate and commodity price risks.

     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, 2001 or December 31, 2000.

     Commodity price risk relates to market fluctuations in the price of natural
gas, electricity, and other petroleum-related products purchased 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, futures, swap and purchased call
option 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, 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. RG&E manages operating risk through a combination of strict operating and
maintenance procedures and the use of financial instruments. In the event RG&E's
generation assets fail to perform as planned, generation insurance reduces the
Company's exposure to electric price spikes in the summer months.

     RG&E has filed a request with the PSC for new electric rate tariffs
commencing in January 2003. The rate request proposes offering electric
customers a choice between one-year fixed price and monthly variable price
offerings. Both pricing options will further reduce the Company's exposure to
market price fluctuations in the electric wholesale market. However, the Company
will continue to bear the risk of operating performance at the generating plants
it owns, as well Nine Mile Two Plant, for which the Company holds a unit-
contingent power purchase agreement.

     As of December 31, 2001, RG&E was party to several natural gas and electric
derivative contracts with Enron Power Marketing Corporation and its subsidiary,
Enron on Line. The contracts hedged the Company's risk to fluctuations in market
price and extended through August 2003 with laddered expirations. The contracts
received hedge accounting treatment under SFAS133. As a result of Enron Inc.'s
Chapter 11 Bankruptcy filing on December 2, 2001, the Company's derivative
contracts with Enron were deemed ineffective. In compliance with FAS 133, the
company determined the market value of the contracts to be ($ 4.9 million) as of
the ineffectiveness date, and ($ 3.8 million) at December 31, 2001. The latter
amount is reflected as a liability on the Company's balance sheet at December
31, 2001. The value of the contracts will be marked to market monthly until the
contracts expire or the Company executes its right to early termination of these
contracts. The Company values the Enron contracts and all derivative contracts
by market price quotes. For thinly traded contracts with potentially wide bid-
ask spreads, the average of quoted prices is used to determine market value.
<PAGE>

                                      52

     Energetix has entered into natural gas purchase commitments with numerous
suppliers. These commitments support fixed price offerings to retail gas
customers. During 2001, Energetix purchased exchange-traded call options to
manage the price risk associated with the future purchase of natural gas. These
option contracts were deemed ineffective hedges under SFAS 133 and have been
marked to market over the life of the contracts. For the year ended December 31,
2001, $1.5 million of call-option premium was charged to expense for these
contracts.

     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. During 2001, Griffith
purchased exchange-traded call options to manage the price risk associated with
the future purchase of heating oil. These option contracts were deemed
ineffective hedges under SFAS 133 and were marked to market. For the year ended
December 31, 2001, $0.9 million of call-option premium was charged to expense
for these contracts. Through December 31, 2001, 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. . At December 31, 2001, Griffith's net deferred losses on
open hedge contracts was $0.5 million. At December 31, 2000 and 1999 Griffith's
net deferred gains on open hedge contracts were not significant.

     All derivative contracts for Energetix and Griffith are closely monitored
on a daily basis to manage the price risk associated with inventory and future
sales commitments.
<PAGE>

                                      53

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, 2001.
     RGS Consolidated Statement of Retained Earnings for each of the three
         years ended December 31, 2001.
     RGS Consolidated Balance sheet at December 31, 2001 and 2000.
     RGS Consolidated Statement of Cash Flows for each of the three years ended
         December 31, 2001.

     RG&E Statement of Income for each of the three years ended December 31,
         2001.
     RG&E Statement of Retained Earnings for each of the three years ended
         December 31, 2001.
     RG&E Balance sheet at December 31, 2001 and 2000.
     RG&E Statement of Cash Flows for each of the three years ended December 31,
         2001.

     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>

                                      54
                       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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 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, 2001 and 2000, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 2001
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.


/s/ PricewaterhouseCoopers LLP

January 24, 2002
<PAGE>

                                      55

RGS Energy Group, Inc.
CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>
(Thousands of Dollars)                          Year Ended December 31,            2001              2000             1999
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>               <C>               <C>
Operating Revenues
   Electric                                                                    $  734,285        $  731,006        $  702,751
   Gas                                                                            357,867           340,014           284,476
   Liquid fuels and other                                                         438,340           377,099           220,310
                                                                               ----------        ----------        ----------

      Total Operating Revenues                                                  1,530,492         1,448,119         1,207,537

Operating Expenses
   Fuel Expenses
     Fuel for electric generation                                                  58,137            48,851            49,297
     Purchased electricity                                                         93,209            85,858            54,337
     Gas purchased for resale                                                     230,507           208,588           151,458
     Unregulated fuel expenses                                                    384,320           340,306           189,465
                                                                               ----------        ----------        ----------

      Total Fuel Expenses                                                         766,173           683,603           444,557

Operating Revenues Less Fuel Expenses                                             764,319           764,516           762,980

Other Operating Expenses
   Operations and maintenance excluding fuel                                      315,499           313,721           297,890
   Unregulated operating and maintenance expenses excluding fuel                   44,670            31,125            26,463
   Depreciation and amortization                                                  120,547           116,184           118,695
   Taxes - state, local and other                                                  90,885            94,576           114,639
   Income taxes                                                                    55,390            60,481            64,453
                                                                               ----------        ----------        ----------

      Total Other Operating Expenses                                              626,991           616,087           622,140

Operating Income                                                                  137,328           148,429           140,840

Other (Income) and Deductions
Allowance for other funds used during construction                                   (946)             (825)             (657)
Income taxes                                                                      (26,213)              496            (1,334)
RGS/Energy East Merger Expenses                                                    14,303                 -                 -
Accelerated Amortization (Nine Mile Two)                                           20,000                 -                 -
Other - net                                                                        (8,397)           (9,392)           (7,959)
                                                                               ----------        ----------        ----------

      Total Other (Income) and Deductions                                          (1,253)           (9,721)           (9,950)

Interest Charges
   Long term debt                                                                  60,079            58,044            53,679
   Other- net                                                                       6,978             5,866             4,582
   Allowance for borrowed funds used during construction                           (1,516)           (1,319)           (1,051)
                                                                               ----------        ----------        ----------

      Total Interest Charges                                                       65,541            62,591            57,210
                                                                               ----------        ----------        ----------

Net Income                                                                         73,040            95,559            93,580

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

Net Income Applicable  to Common Stock                                         $   69,340        $   91,859        $   89,497
                                                                               ----------        ----------        ----------

Average Number of Common Shares (000's)
    Common Stock                                                                   34,601            35,178            36,665
    Common Stock and Equivalents                                                   34,921            35,281            36,757

Earnings per Common Share - Basic                                              $     2.00        $     2.61        $     2.44
Earnings  per Common Share - Diluted                                           $     1.98        $     2.60        $     2.44
                                                                               ==========        ==========        ==========
</TABLE>

CONSOLIDATED STATEMENT OF RETAINED EARNINGS

<TABLE>
<CAPTION>
(Thousands of Dollars)                          Year Ended December 31,            2001              2000              1999
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                <C>                <C>
Balance at Beginning of Period                                                 $  181,546         $ 153,186          $129,484
Add
   Net Income Applicable  to Common Stock                                          69,340            91,859            89,497
                                                                               ----------        ----------        ----------
      Total                                                                       250,886           245,045           218,981
                                                                               ----------        ----------        ----------

Deduct
   Dividends declared on capital stock
     Common Stock                                                                  62,271            62,989            65,594
   Other Adjustments                                                                1,135               510               201
                                                                               ----------        ----------        ----------
      Total                                                                        63,406            63,499            65,795
                                                                               ----------        ----------        ----------

Balance at End of Period                                                       $  187,480        $  181,546        $  153,186
                                                                               ==========        ==========        ==========

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>

                                      56

                            RGS ENERGY GROUP, INC.
                          CONSOLIDATED BALANCE SHEET
                            (Thousands of Dollars)

<TABLE>
<CAPTION>
                                                                                     December 31,            December 31,
                                                                                         2001                    2000
Assets
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>                     <C>
Utility Plant
Electric                                                                             $      1,637,912        $      2,467,289
Gas                                                                                           496,594                 471,051
Common                                                                                        189,301                 164,872
Nuclear                                                                                       224,915                 292,588
                                                                                     ----------------        ----------------
                                                                                            2,548,722               3,395,800
Less:  Accumulated depreciation                                                             1,259,188               1,750,493
       Nuclear fuel amortization                                                              205,119                 254,435
                                                                                     ----------------        ----------------
                                                                                            1,084,415               1,390,872
Construction work in progress                                                                 141,564                 111,486
                                                                                     ----------------        ----------------
       Net Utility Plant                                                                    1,225,979               1,502,358
                                                                                     ----------------        ----------------

Current Assets
Cash and cash equivalents                                                                      28,270                  16,258
Accounts and notes receivable, net of allowance for doubtful accounts:
  2001 - $30,246; 2000 - $34,550                                                              104,494                 136,374
Unbilled revenue receivable                                                                    59,120                  71,120
Fuels                                                                                          61,196                  46,868
Materials and supplies                                                                          5,244                   8,187
Prepayments                                                                                    36,124                  26,268
Other current assets                                                                            4,548                   2,292
                                                                                     ----------------        ----------------
       Total Current Assets                                                                   298,996                 307,367
                                                                                     ----------------        ----------------

Intangible Assets
Goodwill, net                                                                                  13,673                  27,971
Other intangible assets, net                                                                   19,836                  22,614
                                                                                     ----------------        ----------------
       Total Intangible Assets                                                                 33,509                  50,585
                                                                                     ----------------        ----------------

Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund                                                 221,740                 244,514
Nine Mile Two deferred costs                                                                   26,104                  27,155
Unamortized debt expense                                                                       22,620                  16,602
Regulatory assets                                                                             336,765                 412,789
Regulatory asset - Nine Mile Two                                                              301,117                       -
Long term notes receivable                                                                     40,387                       -
Other                                                                                           3,938                   6,005
                                                                                     ----------------        ----------------
       Total Deferred Debits and Other Assets                                                 952,671                 707,065
                                                                                     ----------------        ----------------
       Total Assets                                                                  $      2,511,155        $      2,567,375
                                                                                     ----------------        ----------------
</TABLE>

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

                                      57

                            RGS ENERGY GROUP, INC.
                          CONSOLIDATED BALANCE SHEET
                            (Thousands of Dollars)


<TABLE>
<CAPTION>
                                                                                                        December 31,    December 31,
                                                                                                            2001            2000
Capitalization and Liabilities
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                     <C>              <C>
Capitalization
Long term debt - mortgage bonds                                                                         $   579,773      $   580,132
               - promissory notes                                                                           207,470          211,703
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; 39,042,842 shares issued at
  December 31, 2001 and 38,956,726 shares issued at December 31, 2000                                       708,364          702,807
  Retained earnings                                                                                         187,480          181,546
                                                                                                        -----------      -----------
                                                                                                            895,844          884,353
  Less: Treasury stock at cost (4,379,300 shares at December 31, 2001
              and at December 31, 2000)                                                                     117,238          117,238
                                                                                                        -----------      -----------
           Total Common Shareholders' Equity                                                                778,606          767,115
                                                                                                        -----------      -----------
           Total Capitalization                                                                           1,637,849        1,630,950
                                                                                                        -----------      -----------
Long Term Liabilities
Nuclear waste disposal                                                                                      101,269           97,291
Uranium enrichment decommissioning                                                                            8,079            9,649
Other promissory notes                                                                                       22,574           32,025
Site remediation                                                                                             24,257           24,420
                                                                                                        -----------      -----------
           Total Long Term Liabilities                                                                      156,179          163,385
                                                                                                        -----------      -----------
Current Liabilities
Long term debt due within one year                                                                          112,324           12,095
Preferred stock redeemable within one year                                                                        -                -
Short term debt                                                                                                   -          122,400
Accounts payable                                                                                             88,484          108,618
Dividends payable                                                                                            16,524           16,515
Equal payment plan                                                                                           12,838                -
Accrued interest                                                                                             12,768           13,000
Derivatives                                                                                                  18,287                -
Other                                                                                                        38,208           44,491
                                                                                                        -----------      -----------
           Total Current Liabilities                                                                        299,433          317,119
                                                                                                        -----------      -----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes                                                                           246,481          277,787
Pension costs accrued                                                                                         2,410           26,548
Kamine deferred credit                                                                                       45,393           51,920
Post employment benefits                                                                                     60,238           54,505
Electric Settlement - excess earnings reserve                                                                26,117           16,300
Other                                                                                                        37,055           28,861
                                                                                                        -----------      -----------
           Total Deferred Credits and Other Liabilities                                                     417,694          455,921
                                                                                                        -----------      -----------
           Total Capitalization and Liabilities                                                         $ 2,511,155      $ 2,567,375
                                                                                                        -----------      -----------
</TABLE>

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

                                      58

RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
(Thousands of Dollars)                           Year Ended December 31,                       2001           2000 *          1999 *
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>             <C>             <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income                                                                               $   73,040      $   95,559      $   93,580
Adjustments to reconcile net income to net cash provided
      from operating activities:
Depreciation & amortization                                                                 138,236         132,410         135,094
Deferred fuel                                                                                (1,742)         10,873           1,401
Accelerated amortization of Nine Mile Two regulatory asset                                   20,000
Deferred income taxes                                                                        18,037         (14,002)          9,901
Accelerated recognition of income tax credits                                               (12,949)
Unbilled revenue                                                                             12,000         (13,115)        (20,083)
Post employment benefit/pension costs                                                         4,856          10,900           4,100
Other                                                                                        (7,830)         (1,992)          5,764
Changes in certain current assets and liabilities; net of assets
  acquired and liabilities assumed in acquisitions and sold in dispositions:
      Accounts receivable                                                                    46,281         (37,756)         (8,420)
      Materials, supplies and fuels                                                          (1,098)        (12,903)          4,818
      Taxes accrued                                                                         (12,597)         (4,711)          4,095
      Accounts payable                                                                      (20,196)         52,615           1,767
      Other current assets and liabilities                                                  (21,322)          8,721           1,516
Other                                                                                         4,869           1,070         (13,742)
                                                                                         ----------      ----------      ----------
         Total Operating                                                                    239,585         227,669         219,791
=====================================================================================    ==========      ==========      ==========

CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant                                                             (158,584)       (142,496)       (108,339)
Nuclear generating plant decommissioning fund                                               (20,736)        (20,736)        (20,736)
Acquisitions, net of cash                                                                         -         (48,889)         (3,152)
Proceeds from sale of Oswego Six Generating Station                                                                          10,920
Proceeds from sale of Nine Mile Two                                                          52,416               -               -
Electric transmission contract termination costs                                                  -               -         (26,935)
Other, net                                                                                        -            (289)           (147)
                                                                                         ----------      ----------      ----------
         Total Investing                                                                   (126,904)       (212,410)       (148,389)
=====================================================================================    ==========      ==========      ==========

CASH FLOW FROM FINANCING ACTIVITIES
Redemption of long term debt                                                               (100,000)        (30,000)         (3,104)
Sale/Issue of common stock                                                                    2,151           1,772               -
Retirement of preferred stock                                                                     -               -         (10,000)
Issuance of long-term debt, net                                                             199,534          17,540         103,509
Repayment of promissory notes                                                               (12,436)         (7,290)         (5,958)
Short term borrowings, net                                                                 (122,400)        111,900         (46,500)
Payments of dividends on preferred stock                                                     (3,700)         (3,700)         (4,274)
Payments of dividends on common stock                                                       (62,262)        (63,552)        (66,262)
Purchase of treasury stock                                                                        -         (33,986)        (36,819)
Other, net                                                                                   (1,556)             27            (229)
                                                                                         ----------      ----------      ----------
         Total Financing                                                                   (100,669)         (7,289)        (69,637)
                                                                                         ----------      ----------      ----------
         Change in cash and cash equivalents                                             $   12,012      $    7,970      $    1,765
         Cash and cash equivalents at beginning of year                                  $   16,258      $    8,288      $    6,523
                                                                                         ----------      ----------      ----------
         Cash and cash equivalents at end of year                                        $   28,270      $   16,258      $    8,288
=====================================================================================    ==========      ==========      ==========
</TABLE>

<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars)                                    Year Ended December 31,              2001            2000 *          1999
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>             <C>             <C>
Cash Paid During the Period
      Interest paid (net of capitalized amount)                                          $   64,032      $   59,060      $   54,059
                                                                                         ----------      ----------      ----------
      Income taxes paid                                                                  $   80,654      $   60,322      $   58,750
                                                                                         ----------      ----------      ----------
Noncash investing and financing activities:
      Reduction to Goodwill                                                              $   13,212      $        -      $        -
                                                                                         ----------      ----------      ----------
      Establishment of Nine Mile Two Regulatory Asset                                    $  325,610      $        -      $        -
                                                                                         ----------      ----------      ----------
      Note Receivable from Constellation Nuclear for Nine Mile Two                       $   50,484      $        -      $        -
                                                                                         ----------      ----------      ----------
      Transfer from utility to regulatory asset, net                                     $        -      $        -      $   54,255
                                                                                         ----------      ----------      ----------
</TABLE>

* Reclassified for comparative purposes
The accompanying notes are an integral part of the financial statements.
<PAGE>

                                      59

Rochester Gas and Electric Corporation
STATEMENT OF INCOME

<TABLE>
<CAPTION>
(Thousands of Dollars)                                  Year Ended December 31,         2001            2000               1999
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>              <C>                <C>
Operating Revenues
 Electric                                                                           $   728,099      $  721,737         $  700,194
 Gas                                                                                    311,377         322,412            281,555
 Liquid fuels and other                                                                       -               -            108,699
                                                                                    -----------      ----------         ----------

   Total Operating Revenues                                                           1,039,476       1,044,149          1,090,448

Operating Expenses
 Fuel Expenses
  Fuel for electric generation                                                           58,137          48,851             49,297
  Purchased electricity                                                                  91,040          80,938             53,046
  Gas purchased for resale                                                              184,690         192,038            148,983
  Unregulated fuel expenses                                                                   -               -             91,505
                                                                                    -----------      ----------         ----------

  Total Fuel Expenses                                                                   333,867         321,827            342,831

Operating Revenues Less Fuel Expenses                                                   705,609         722,322            747,617

Other Operating Expenses
 Operations and maintenance excluding fuel                                              315,499         313,721            297,890
 Unregulated operating and maintenance expenses excluding fuel                                -               -             14,236
 Depreciation and amortization                                                          112,643         112,110            117,289
 Taxes - state, local and other                                                          87,718          90,090            112,613
 Income taxes                                                                            55,184          59,451             64,454
                                                                                    -----------      ----------         ----------

  Total Other Operating Expenses                                                        571,044         575,372            606,482

Operating Income                                                                        134,565         146,950            141,135

Other (Income) and Deductions
Allowance for other funds used during construction                                         (946)           (825)              (657)
Income taxes                                                                            (26,265)            221             (1,145)
RGS/Energy East Merger Expenses                                                          13,901               -                  -
Accelerated Amortization (Nine Mile Two)                                                 20,000               -                  -
Other- net                                                                               (8,191)         (8,897)            (8,114)
                                                                                    -----------      ----------         ----------

  Total Other (Income) and Deductions                                                    (1,501)         (9,501)            (9,916)

Interest Charges
 Long term debt                                                                          58,953          56,673             53,067
 Other - net                                                                              4,979           5,568              4,547
 Allowance for borrowed funds used during construction                                   (1,516)         (1,319)            (1,051)
                                                                                    -----------      ----------         ----------

  Total Interest Charges                                                                 62,416          60,922             56,563
                                                                                    -----------      ----------         ----------

Net Income                                                                               73,650          95,529             94,488
                                                                                    -----------      ----------         ----------

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

Net Income Applicable to Common Stock                                               $    69,950      $   91,829         $   90,405
                                                                                    -----------      ----------         ----------
</TABLE>

STATEMENT OF RETAINED EARNINGS

<TABLE>
<CAPTION>
(Thousands of Dollars)                                  Year Ended December 31,         2001            2000               1999
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>              <C>                <C>
Balance at Beginning of Period                                                      $   166,184      $  137,854         $  129,484
Add
 Net Income                                                                              73,650          95,529             94,488
                                                                                    -----------      ----------         ----------
  Total                                                                                 239,834         233,383            223,972
                                                                                    -----------      ----------         ----------

Deduct
 Dividends declared on capital stock
  Cumulative preferred stock - at required rates                                          3,700           3,700              4,083
  Common Stock                                                                           62,271          62,989             65,594
 Adjustment Associated with RGS Energy Group Formation                                        -               -             16,243
 Other Adjustments                                                                         (191)            510                198
                                                                                    -----------      ----------         ----------
  Total                                                                                  65,780          67,199             86,118
                                                                                    -----------      ----------         ----------

Balance at End of Period                                                            $   174,054      $  166,184         $  137,854
                                                                                    ===========      ==========         ==========
</TABLE>

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

                                      60

                    ROCHESTER GAS AND ELECTRIC CORPORATION
                                 BALANCE SHEET
                            (Thousands of Dollars)

<TABLE>
<CAPTION>
                                                                        December 31,  December 31,
                                                                            2001          2000
Assets
--------------------------------------------------------------------------------------------------
<S>                                                                     <C>           <C>
Utility Plant
Electric                                                                 $ 1,637,912  $ 2,467,289
Gas                                                                          496,594      471,051
Common                                                                       133,831      117,473
Nuclear                                                                      224,915      292,588
                                                                        ------------- ------------
                                                                           2,493,252    3,348,401
Less: Accumulated depreciation                                             1,249,165    1,735,752
      Nuclear fuel amortization                                              205,119      254,435
                                                                        ------------- ------------
                                                                           1,038,968    1,358,214
Construction work in progress                                                141,564      111,486
                                                                        ------------- ------------
      Net Utility Plant                                                    1,180,532    1,469,700
                                                                        ------------- ------------

Current Assets
Cash and cash equivalents                                                     20,631        4,851
Accounts and notes receivable, net of allowance for doubtful accounts:
  2001 - $29,482; 2000 - $33,482                                              82,418       93,130
Affiliate receivable                                                          78,799       51,558
Unbilled revenue receivable                                                   50,787       61,838
Fuels                                                                         44,147       33,896
Materials and supplies                                                         5,244        8,187
Prepayments                                                                   34,806       23,782
Other current assets                                                           3,731            -
                                                                        ------------- ------------
      Total Current Assets                                                   320,563      277,242
                                                                        ------------- ------------

Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund                                221,740      244,514
Nine Mile Two deferred costs                                                  26,104       27,155
Unamortized debt expense                                                      22,620       16,602
Regulatory assets                                                            336,765      412,789
Regulatory asset - Nine Mile Two                                             301,117            -
Long term notes receivable                                                    40,387            -
Other                                                                          2,930        4,673
                                                                        ------------- ------------
      Total Deferred Debits and Other Assets                                 951,663      705,733
                                                                        ------------- ------------
      Total Assets                                                       $ 2,452,758  $ 2,452,675
                                                                        ------------- ------------
</TABLE>

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

                                      61

                    ROCHESTER GAS AND ELECTRIC CORPORATION
                                 BALANCE SHEET
                            (Thousands of Dollars)

<TABLE>
<CAPTION>
                                                                       December 31,  December 31,
                                                                           2001          2000
Capitalization and Liabilities
--------------------------------------------------------------------------------------------------
<S>                                                                     <C>           <C>
Capitalization
Long term debt - mortgage bonds                                        $   579,773    $   580,132
               - promissory notes                                          207,470        211,703
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, 2001 and at December 31, 2000                               700,318        700,318
  Retained earnings                                                        174,054        166,184
                                                                       ------------  -------------
                                                                           874,372        866,502
  Less: Treasury stock at cost (4,379,300 shares at December 31, 2001
              and at December 31, 2000)                                    117,238        117,238
                                                                       ------------  -------------
      Total Common Shareholder's Equity                                    757,134        749,264
                                                                       ------------  -------------
      Total Capitalization                                               1,616,377      1,613,099
                                                                       ------------  -------------

Long Term Liabilities
Nuclear waste disposal                                                     101,269         97,291
Uranium enrichment decommissioning                                           8,079          9,649
Site remediation                                                            22,356         22,356
                                                                       ------------  -------------
      Total Long Term Liabilities                                          131,704        129,296
                                                                       ------------  -------------

Current Liabilities
Long term debt due within one year                                         104,387          4,227
Short term debt                                                                  -         98,000
Accounts payable                                                            75,885         79,356
Affiliate payable                                                           26,871         18,451
Dividends payable to parent                                                 16,524         16,515
Equal payment plan                                                          12,838              -
Accrued interest                                                            12,338         12,339
Derivatives                                                                 18,287              -
Other                                                                       24,637         29,325
                                                                       ------------  -------------
      Total Current Liabilities                                            291,767        258,213
                                                                       ------------  -------------

Deferred Credits and Other Liabilities
Accumulated deferred income taxes                                          242,398        274,299
Pension costs accrued                                                        2,410         26,548
Kamine deferred credit                                                      45,393         51,920
Post employment benefits                                                    60,238         54,505
Electric Settlement - excess earnings reserve                               26,117         16,300
Other                                                                       36,354         28,495
                                                                       ------------  -------------
      Total Deferred Credits and Other Liabilities                         412,910        452,067
                                                                       ------------  -------------

      Total Capitalization and Liabilities                             $ 2,452,758    $ 2,452,675
                                                                       ------------  -------------
</TABLE>

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

                                      62

ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
(Thousands of Dollars)                                 Year Ended December 31,          2001               2000 *           1999
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                 <C>              <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income                                                                          $   73,650          $   95,529       $   94,488
Adjustments to reconcile net income to net cash provided
      from operating activities:
Depreciation & amortization                                                            130,332             128,629          131,903
Deferred fuel                                                                           (1,742)             10,873            1,401
Accelerated amortization of Nine Mile Two regulatory asset                              20,000
Deferred income taxes                                                                   17,442             (12,820)           5,889
Accelerated recognition of income tax credits                                          (12,949)
Unbilled revenue                                                                        11,051              (6,177)         (17,739)
Post employment benefit/pension costs                                                    4,856              10,900            4,100
Other                                                                                   (7,526)             (2,027)           5,358
Changes in certain current assets and liabilities; net of assets
  and liabilities related to disposition of assets:
      Accounts receivable                                                               (2,432)            (61,220)         (10,248)
      Materials, supplies and fuels                                                      2,978              (8,705)           7,164
      Taxes accrued                                                                    (11,608)             (5,333)           2,822
      Accounts payable                                                                  16,968              42,602           (3,298)
      Other current assets and liabilities, net                                        (23,368)              2,144              663
Other                                                                                    1,295                 970          (11,876)
                                                                                    ----------          ----------       ----------
         Total Operating                                                               218,947             195,365          210,627
=================================================================================== ==========          ==========       ==========

CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant                                                        (154,053)           (140,084)        (106,359)
Nuclear generating plant decommissioning fund                                          (20,736)            (20,736)         (20,736)
Proceeds from sale of Oswego Six Generating Station                                          -                   -           10,920
Proceeds from sale of Nine Mile Two                                                     52,416                   -                -
Electric transmission contract termination costs                                             -                   -          (26,935)
Other, net                                                                                   -                 769              467
                                                                                    ----------          ----------       ----------
         Total Investing                                                              (122,373)           (160,051)        (142,643)
=================================================================================== ==========          ==========       ==========

CASH FLOW FROM FINANCING ACTIVITIES
Redemption of long term debt                                                          (100,000)            (30,000)               -
Issuance of long-term debt, net                                                        199,534                   -          100,000
Retirement of preferred stock                                                                -                   -          (10,000)
Repayment of promissory notes                                                           (4,073)             (3,781)          (2,449)
Short term borrowings, net                                                             (98,000)             98,000          (50,500)
Payments of dividends on preferred stock                                                (3,700)             (3,700)          (4,274)
Payments of dividends on common stock                                                  (62,262)            (63,552)         (66,262)
Purchase of treasury stock                                                                   -             (33,986)         (36,819)
Other, net                                                                             (12,293)                113            2,240
                                                                                    ----------          ----------       ----------
         Total Financing                                                               (80,794)            (36,906)         (68,064)
                                                                                    ----------          ----------       ----------
         Change in cash and cash equivalents                                        $   15,780          $   (1,592)      $      (80)
         Cash and cash equivalents at beginning of year                             $    4,851          $    6,443       $    6,523
                                                                                    ----------          ----------       ----------
         Cash and cash equivalents at end of year                                   $   20,631          $    4,851       $    6,443
=================================================================================== ==========          ==========       ==========
</TABLE>


<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars)                                Year Ended December 31           2001                2000 *           1999
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                 <C>              <C>
Cash Paid During the Period
      Interest paid (net of capitalized amount)                                     $   61,801          $   58,753       $   53,061
                                                                                    ----------          ----------       ----------
      Income taxes paid                                                             $   79,025          $   59,487       $   58,750
                                                                                    ----------          ----------       ----------
Noncash investing and financing activities:
      Establishment of Nine Mile Two Regulatory Asset                               $  325,610          $        -       $        -
                                                                                    ----------          ----------       ----------
      Note Receivable from Constellation Nuclear for Nine Mile Two                  $   50,484          $        -       $        -
                                                                                    ----------          ----------       ----------
      Transfer from utility to regulatory asset, net                                $        -          $        -       $   54,255
                                                                                    ----------          ----------       ----------
</TABLE>

* Reclassified for comparative purposes

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

                                      63

Note 1.   SUMMARY OF ACCOUNTING PRINCIPLES

     GENERAL.  RGS Energy Group, Inc. ("the Company" or "RGS") through its
regulated subsidiary, Rochester Gas and Electric Corporation ("RG&E"), 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.  RG&E 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 and RG&E.  The
Notes to Financial Statements apply to both RGS and RG&E.  RGS's Consolidated
Financial Statements include the accounts of RGS and its wholly owned
subsidiaries, including RG&E, and two non-utility subsidiaries, Energetix and
RGS Development Corporation ("RGS Development").  RGS'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's structure.  Prior to August 2, 1999, RG&E's financial
statements also include Energetix and RGS Development.

     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").

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.

     GOODWILL AND OTHER INTANGIBLE ASSETS.  Goodwill presented on the
consolidated balance sheet, represents the excess of cost over the net tangible
and identifiable intangible assets of acquired businesses.  It is stated at cost
and has been amortized, principally on a straight-line basis, over the estimated
future periods to be benefited (20 years).  The Company's adoption of Statement
of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other
Intangible Assets" ("SFAS 142") will discontinue the amortization of goodwill
and substitute a periodic impairment test of its goodwill.  Other intangible
assets include predominately dealer improvements, customer lists and covenants
not to compete and are being amortized over periods ranging from one to fifteen
years.  Accumulated amortization amounted to $4.4 million and $3.5 million at
December 31, 2001 and December 31, 2000 respectively.

     ACQUISITIONS.  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.  In 2001, the accounting for these acquisitions was completed, resulting
in a $13.2 million reduction to goodwill.

     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.
<PAGE>

                                      64

     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.

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

     RESEARCH AND DEVELOPMENT COSTS.  Research and development costs are charged
to expense as incurred.  Expenditures for the years 2001, 2000 and 1999 were
$2.6 million, $2.6 million and $2.9 million respectively.

     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 an
expense/(benefit) as a result of the Company's stock based compensation plans
for the years 2001, 2000 and 1999 approximates $2.6 million, $(1.9) million and
$2.2 million respectively.

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

     EARNINGS PER SHARE.  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 outstanding options were exercised or converted into common
stock that then shared in the earnings of the Company.  During the years ended
December 31, 2001, 2000 and 1999, there were 0, 202,402 and 177,322
respectively, of outstanding options that were not included in the computation
of diluted EPS, because their respective exercise prices were greater than the
average market price of the common stock for the period.

     UTILITY PLANT, DEPRECIATION AND AMORTIZATION.  The cost of additions to
utility plant and replacement of retirement units of property is capitalized.
Cost includes labor, material, and similar items, as well as indirect charges
such as engineering and supervision, and is recorded at original cost.  The
Company capitalizes an Allowance for Funds Used During Construction ("AFUDC")
approximately equivalent to the cost of capital devoted to plant under
construction that is not included in its rate base.  AFUDC is segregated into
two components and classified in the Consolidated Statement of Income as
Allowance for Borrowed Funds Used During Construction, an offset to Interest
Charges, and Allowance for Other Funds Used During Construction, a part of Other
Income.  The rate approved by the PSC for purposes of computing AFUDC was 5%
during the three-year period ended December 31, 2001.  Replacement of minor
items of property is included in maintenance expenses.  Costs of depreciable
units of plant retired are eliminated from utility plant accounts, and such
costs, plus removal expenses, less salvage, are charged to the accumulated
depreciation reserve.

     Depreciation in the financial statements is provided on a straight-line
basis at rates based on the estimated useful lives of property, which have
resulted in an annual regulated depreciation provision of 3.2% in the three-year
period ended December 31, 2001.  The annual depreciation provision of Energetix
is 9.4% in the three-year period ended December 31, 2001.

     CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of cash and
short-term commercial paper.  These investments have an original maturity not
exceeding three months.

     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
<PAGE>

                                      65

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

     INVESTMENTS IN DEBT AND EQUITY SECURITIES.  The Company's accounting
policy, as prescribed by the PSC, with respect to its nuclear decommissioning
trust is to reflect the trust assets at market value and reflect unrealized
gains and losses as a change in the corresponding accrued decommissioning
liability.  The Company has no other significant debt or equity securities.

     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.  These costs are recovered in rates as the
expense is recognized.

     FINANCIAL/COMMODITY INSTRUMENTS.  The Company enters into physical and
financial derivative contracts to manage its electric operating risk and market
fluctuations in the price of natural gas, electricity and other petroleum-
related products used for resale.  These derivative instruments generally
qualify for hedge accounting under SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"), with gains or losses resulting
from these agreements being deferred until the corresponding commodity is
delivered to the customer.

     Energetix has entered into electric and natural gas purchase commitments
with numerous suppliers. These commitments support fixed and variable 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 derivative contracts, which are
deemed effective under SFAS 133, 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.

     In June 1998, the Financial Accounting Standards Board ("FASB") issued 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 $20.9 million and $19.8 million respectively.
<PAGE>

                                      66

     COMPREHENSIVE INCOME.  There were no items of comprehensive income during
the three-year period ended December 31, 2001; therefore, net income is
equivalent to total comprehensive income.

     RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS.   In July 2001, FASB issued SFAS
No. 141, "Business Combinations", ("SFAS 141"), SFAS 142 and SFAS 143,
"Accounting for Asset Retirement Obligations" ("SFAS 143").  In August 2001, the
FASB issued SFAS 144, "Accounting for Impairment or Disposal of Long-Lived
Assets" ("SFAS 144") which is effective January 1, 2002.  SFAS 141 requires that
all business combinations initiated after June 30, 2001 be accounted for by the
purchase method.  It also requires disclosure of the primary reasons for a
business combination and the allocation of the purchase price paid to the assets
acquired and liabilities assumed by major balance sheet caption.  Additional
disclosure would be required when goodwill and intangible assets represent a
significant portion of the purchase price paid.

     SFAS 142 addresses financial accounting and reporting for acquired goodwill
and other intangible assets.  Under this standard, goodwill and intangible
assets that have indefinite useful lives will not be amortized but rather will
be tested at least annually for impairment.  Intangible assets that have finite
useful lives will continue to be amortized over their useful lives, but the
amortization period will not be a limited to a certain period of time.  SFAS 142
requires that the Company adopt this standard during 2002.  Goodwill
amortization for 2001 amounted to $0.9 million.

     SFAS 143 requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred.  When the
liability is initially recorded, the entity capitalizes a cost by increasing the
carrying amount of the related long-lived asset.  Over time, the liability is
adjusted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset.  When the liability is
settled, the entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement.  SFAS 143 requires that the Company adopt
this standard by January 1, 2003, with earlier application encouraged.
Management is currently evaluating the provisions of SFAS 143 regarding the
impact on the financial condition and results of operations of the Company.

     SFAS 144 supersedes FASB Statement No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", and the
accounting and reporting provisions relating to the disposal of a segment of a
business of Accounting Principles Board Opinion No. 30.  The company does not
expect that the adoption of SFAS 144 will have a significant impact on its
financial statements.


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


Note 2.  NUCLEAR - RELATED MATTERS

     SALE OF INTEREST IN NINE MILE TWO. On November 7, 2001, RG&E sold its
ownership interest in Nine Mile Two to Constellation Nuclear.  The purchase
price for RG&E's interest was $101.0 million, $50.5 million of which was paid in
cash at the closing and $50.5 million of which will be paid in five equal annual
principal installments plus interest at a rate of 11 percent pursuant to a five
year promissory note.  Principal and interest payments under the promissory note
will total approximately $67.1 million unless the note is pre-paid.  In
addition, RG&E received approximately $1.9 million cash for the sale of its
share of certain transmission assets related to the Nine Mile Two facility.

     At November 7, 2001, the net book value of RG&E's 14 percent interest in
the Nine Mile Two generating facility was approximately $348.8 million.  RG&E
also had investments in fuel of approximately $6.0 million, transmission and
distribution facilities of $3.3 million, materials and supplies inventory of
$6.9 million, and construction work in progress of $7.6 million.
<PAGE>

                                      67

     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 completion of the term 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 allocated 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.

     RG&E and the Staff of the PSC entered into a settlement dated August 7,
2001 (the "Nine Mile Two Settlement") that addresses the rate-making treatment
associated with RG&E's recovery of its remaining investment in Nine Mile Two and
related costs.  The settlement was approved by the PSC in an order issued on
October 26, 2001.  Under the settlement, RG&E is authorized to establish a
regulatory asset calculated in accordance with the provisions of the settlement
that, as of November 7, 2001, was estimated to be approximately $325.6 million.
RG&E agreed to a one-time pre-tax accelerated amortization of $20.0 million of
this regulatory asset.  In addition, RG&E accelerated its recognition of
previously deferred investment tax credits that amounted to $12.9 million.  RG&E
has also agreed to amortize, during the period from the closing of the sale of
Nine Mile Two until RG&E's base electric rates are re-set, an additional amount
of this regulatory asset to reflect the projected reduction in RG&E's expenses
of owning and operating Nine Mile Two prior to the sale compared to the
estimated expenses that it will incur in purchasing the amount of electricity
after the sale that is equivalent to RG&E's pre-sale share of the output.  The
amortization during this period will be calculated using an amortization rate of
$30.0 million per year. The terms associated with the recovery of the remaining
regulatory asset will be established in future RG&E rate proceedings.  The
settlement further provides that it constitutes a final and irrevocable
resolution of all RG&E rate-making issues associated with the sale of Nine Mile
Two and RG&E's ability to recover costs associated with its investment in Nine
Mile Two through its rates.

     In connection with the sale by RG&E of its interest in Nine Mile Two, RG&E
informed Niagara Mohawk that RG&E's rights and obligations under a June 8, 1998
Exit Agreement will cease as it pertains to payments for certain transmission
facilities relating to RG&E's ownership of a portion of Nine Mile Two.  Niagara
Mohawk disputes RG&E's position, asserting instead that RG&E must continue
making payments that decline from approximately $7.0 million per year currently
to approximately $4.0 million per year in 2007 and continue at that level until
2043 (or until the plant is retired, if sooner).  After attempting to resolve
that matter informally, RG&E commenced an action in New York State Supreme
Court, Monroe County, seeking a judgment declaring that, as a result of the sale
of its interest in Nine Mile Two, RG&E has no further obligation to make
payments under the Exit Agreement and that the Transmission Congestion Contracts
or TCCs to which RG&E was entitled under the Exit Agreement, should be returned
to and accepted by Niagara Mohawk.  In response to RG&E's action in New York
State Supreme Court, Niagara Mohawk filed a complaint with FERC seeking to have
FERC assert jurisdiction on the Exit Agreement dispute, declare that RG&E is in
breach of the Exit Agreement, and order RG&E to fulfill the payment obligations
set forth in the Exit Agreement.  At this time RG&E cannot predict the outcome
of either proceeding.  The Nine Mile Two Settlement provides that the Nine Mile
Two regulatory asset would be adjusted for any amount that RG&E is found
responsible for in the resolution of the Exit Agreement dispute.

     DECOMMISSIONING TRUST.  RG&E has been collecting amounts in its electric
rates for the eventual decommissioning of its Ginna Plant and for its former 14
percent share of the decommissioning of Nine Mile Two.  The operating license
for the Ginna Plant is scheduled to expire in 2009.  As a result of the sale of
Nine Mile Two to Constellation Nuclear, RG&E is no longer responsible in the
decommissioning of that facility.  As a result, RG&E transferred the entire
$35.5 million balance of its decommissioning fund that was associated with its
share of Nine Mile Two to Constellation Nuclear.
<PAGE>

                                      68

     Under accounting procedures approved by the PSC, RG&E has collected
decommissioning costs of approximately $178.5 million through December 31, 2001
and is authorized to collect approximately $17.4 million annually through June
30, 2002 for decommissioning of its Ginna Plant.  The amount allowed in rates is
based on estimated ultimate decommissioning costs of $296.3 million (1995
dollars).  This estimate is based on a site specific cost study for the plant
completed in 1995.  A site specific study of the anticipated costs of actual
decommissioning is 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 its
Ginna Plant.  Since 1990, RG&E has contributed $145.9 million to the Ginna fund,
and, including realized and unrealized investment returns, the Ginna fund has a
balance of $221.7 million as of December 31, 2001.  The amount attributed to the
allowance for removal of non-contaminated structures is being held in an
internal reserve.  The Ginna internal reserve balance as of December 31, 2001 is
$32.6 million.  NRC regulations require biennial reports on the status of
decommissioning trust funds and RG&E reported to the NRC the Ginna
decommissioning trust exceeded the NRC minimum funding amounts required as of
December 31, 2000.

     The Staff of the Financial Accounting Standards Board has studied the
recognition, measurement and classification of certain liabilities related to
the closure or removal of long-lived assets and in June 2001 issued SFAS No.
143, Accounting for Asset Retirement Obligations, which the Company will be
required to adopt in 2003.  The Company will be studying this new standard
during 2002 to determine its effect on current accounting practices associated
with the decommissioning costs of the Ginna Plant.  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. RG&E and other
similarly situated utilities have a case pending against the U.S. Department of
Energy ("DOE") in which the utilities maintain that DOE has no right to assess
them for DOE's costs incurred in decontaminating and decommissioning ("D&D")
certain uranium enrichment plants at which DOE performed enrichment services to
fulfill its contracts for such services with RG&E and others. This case is in
the discovery stage in the federal District Court for the Southern District of
New York.

     Pending the resolution of its lawsuit, RG&E has been paying the DOE
assessments and recognizing a liability on its financial statements for the
balance. To date RG&E has paid, under protest, a total of $16.5 million to DOE
to cover the DOE enrichment D&D assessment.  The remaining balance due at
December 31, 2001 for the Ginna Plant is $9.9 million, of which $8.1 million is
recognized as a long-term liability and $1.8 million is recognized as a current
liability in 2002.  RG&E is recovering these costs in its rates.

     In a separate matter, on August 23, 2001, the Court of Federal Claims ruled
that the DOE had erroneously overcharged plaintiff utilities during a certain
period in 1992 - 1993 for D&D activity by requiring them to pay an assessment
for D&D work under an applicable statute at the same time it was requiring them
to pay for the identical work through contract prices which included costs for
D&D.  RG&E has evaluated the bearing of this decision on its own claim for D&D
charges against DOE has found that RG&E had deliveries from DOE in the subject
period, and, by applying the same criteria as was used in the Court of Federal
Claims case, concluded that DOE had overcharged RG&E $0.7 million.  Other
analyses indicated other potential overcharges by DOE to RG&E during the period
1986 - 1993 which total an additional $3.8 million.  In October 2001, RG&E
initiated a lawsuit, along with other utilities in similar situations, against
DOE in the Court of Federal Claims for the recovery of these alleged
overpayments.  That lawsuit is currently in the discovery phase.
<PAGE>

                                      69

     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.  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.  RG&E estimates the fees, including accrued interest, owed to the
DOE to be $101.3 million at December 31, 2001.  RG&E is allowed by the PSC to
recover these costs in rates.  The estimated fees are classified as a long-term
liability in the attached financial statements.  The Nuclear Waste Act also
requires the DOE to provide for the disposal of nuclear fuel irradiated after
April 6, 1983, for a charge of approximately one mill ($.001) per KWH of nuclear
energy generated and sold.  This charge (approximately $4.0 million per year for
the Ginna Plant) 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 Plant spent
fuel pool.  Based on current projections, this will allow interim storage
capacity of all spent fuel discharged from the Ginna Plant through the end of
its current operating license in the year 2009.

     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 (the "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 if and when it will begin removing SNF for disposal.  As a result,
RG&E has filed a claim for damages in the US Court of Federal Claims seeking to
recover past and future costs arising from DOE's failure to meet its obligation
to begin receiving SNF.

     Although the DOE has been found to have breached its obligations, it is not
possible to predict the outcome of this case, 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 therefor,
have been promising.
<PAGE>

                                      70

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, 2001 and
2000:


                                                 Millions of Dollars

                                                      2001    2000
                                                    ------  ------

     Nine Mile Two                                  $301.1  $  0.0
     Kamine Settlement                               169.8   179.1
     Income Taxes                                     52.3   101.9
     Oswego Plant Sale                                72.3    74.4
     Deferred Environmental SIR Costs                 12.6    16.6
     Uranium Enrichment Decommissioning Deferral      11.2    12.7
     Labor Day 1998 Storm Costs                       10.1     9.3
     Other, Net                                        8.5    18.8
                                                    ------  ------

     Total - Regulatory Assets                      $637.9  $412.8
                                                    ======  ======


-    Nine Mile Two:  This amount represents the establishment of a regulatory
     asset resulting from the sale of the Nine Mile Two nuclear plant to
     Constellation Nuclear.  See Note 2 "Nuclear - Related Matters" for more
     information related to the sale.

-    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.

-    Oswego Plant Sale: This amount results from the sale of RG&E's interest in
     a generating facility in Oswego, New York, 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.
<PAGE>

                                      71

-    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 seeking deferral of these storm costs,
     consistent with the Electric Settlement.

     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 of RG&E
are highly sensitive to the competitive wholesale market price assumed in the
estimation.  The amount of RG&E's potentially strandable assets at December 31,
2001 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-144, 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, 2001, RG&E believes 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.


     PSC ELECTRIC SETTLEMENT.  During 1996 and 1997, RG&E, the staff of the PSC
and several other parties negotiated an electric settlement which was approved
by the PSC in November 1997 (the "Electric Settlement").  The Electric
Settlement set the framework for the introduction and development of open
competition in the electric energy marketplace in RG&E's territory and lasts
through June 30, 2002.

     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 are 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 will be used to
write down accumulated deferrals or investment in electric plant or regulatory
assets.  The other 50 percent of such excess will be used to write down deferred
costs accumulated during the term of the Electric Settlement and the remainder
if any, will be retained as earnings by RG&E. 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.

     PSC GAS SETTLEMENT.  On January 25, 2001, RG&E reached agreement with PSC
staff and other parties on a comprehensive rate and restructuring settlement for
its natural gas business (the "PSC Gas Settlement"). The PSC Gas Settlement was
approved by the PSC, with some modifications, on February 28, 2001 and became
effective on March 1, 2001. Rate-related provisions of the Gas Settlement extend
from July 1, 2000 through June 30, 2002.

     For the purpose of setting base, or local delivery, rates for the period
beginning July 1, 2000, natural gas revenues were decreased a total of
approximately $3.0 million from the levels in effect on June 30, 2000.  This
rate level is based on an agreed-upon return on equity of 11.0%.  Base rates
were adjusted effective March 1, 2001 to reflect the revenue requirements
decrease.  Because the base rates
<PAGE>

                                      72

that were in effect through February 28, 2001 were higher than those agreed to
by the parties, RG&E, in March 2001, passed 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.
In the event that RG&E achieves a return on equity in excess of 12.5% in any
rate year covered by the Gas Settlement, 90.0% of the excess over that level
will be deferred for the benefit of customers.

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, including
Energetix, who resell that electricity to retail customers.

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

     The Unregulated segment primarily consists of Energetix.  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 and propane.


                                                  (thousands of dollars)

Regulated Electric                               2001        2000        1999
------------------                               ----        ----        ----

Operating Income                           $  108,487  $  124,149  $  120,599
Revenues from External Customers              620,897     643,562     654,235
Revenues from Intersegment Transactions       107,202      78,175      44,510
Interest Revenue                               12,687      10,986      10,799
Depreciation and Amortization                  99,979      99,662     102,946
Regulatory Amortization                        21,787      18,219      14,287
Nuclear Fuel Amortization                      16,387      15,493      15,622
Interest Expense                               51,102      50,045      45,653
Operating Income Tax Expense                   45,193      49,614      55,752
Capital Expenditures, net                     105,321     108,758      81,199

Total Identifiable Assets                   1,843,839   1,915,002   1,925,809


Regulated Gas                                    2001        2000        1999
-------------                                    ----        ----        ----

Operating Income                           $   26,078  $   22,801  $   19,343
Revenues from External Customers              289,690     320,556     278,239
Revenues from Intersegment Transactions        21,687       1,856         420
Interest Revenue                                  659         413         315
<PAGE>

                                      73

Depreciation and Amortization                  12,664      12,448      12,548
Regulatory Amortization                           327         494         220
Interest Expense                               11,314      10,877       9,648
Operating Income Tax Expense                    9,991       9,837       8,580
Capital Expenditures, net                      48,732      31,326      25,160

Total Identifiable Assets                     485,749     464,047     438,290


Unregulated                                      2001        2000        1999
-----------                                      ----        ----        ----

Operating Income                           $    2,737  $    1,428         553
Revenues from External Customers              619,905     484,001     275,063
Interest Revenue                                  260       1,198         398
Depreciation and Amortization                   7,050       3,325       2,450
Goodwill Amortization                             854         749         751
Interest Expense                                3,635       2,571       2,171
Operating Income Tax Expense/(Benefit)            191       1,003        (387)
Capital Expenditures, net                       5,188       2,129       4,994

Total Assets                                  145,535     179,010      90,580

     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                                            2001          2000          1999
--------                                            ----          ----          ----
<S>                                           <C>           <C>           <C>
Regulated Electric                            $  728,099    $  721,737    $  698,745
Regulated Gas                                    311,377       322,412       278,659
Unregulated                                      619,905       484,001       275,063
                                              ----------    ----------    ----------

   Total                                       1,659,381     1,528,150     1,252,467

Reported on Consolidated Income Statement      1,530,492     1,448,119     1,207,537
                                              ----------    ----------    ----------

Difference to reconcile                       $  128,889    $   80,031    $   44,930
                                              ==========    ==========    ==========

Intersegment Revenues
   Regulated Electric from Unregulated           107,202        78,175        44,510
   Regulated Gas from Unregulated                 21,687         1,856           420
                                              ----------    ----------    ----------
</TABLE>


<PAGE>

                                      74

<TABLE>
<S>                                           <C>           <C>           <C>
   Total Intersegment                         $  128,889    $   80,031    $   44,930
                                              ==========    ==========    ==========

Assets                                              2001          2000          1999
------                                              ----          ----          ----

Regulated Electric                            $1,843,839    $1,915,002    $1,925,809
Regulated Gas                                    485,749       464,047       438,290
Unregulated                                      145,535       179,010        90,580
Cash and Cash Equivalents,
   Regulated Operations                           20,631         4,851         6,443
Unamortized Debt Expense                          22,620        16,602        17,984
Other                                              1,120           617           367
Intersegment eliminations                         (8,339)      (12,754)      (16,599)
                                              ----------    ----------    ----------

Total Assets                                  $2,511,155    $2,567,375    $2,462,874
                                              ==========    ==========    ==========
</TABLE>
<PAGE>

                                      75

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, 2001 and 2000:


<TABLE>
<CAPTION>
                                                                                            (Millions)
                                                                   Pension Benefits                              Other Benefits
                                                                  2001          2000                            2001         2000
                                                                  ----          ----                            ----         ----
<S>                                                             <C>           <C>                             <C>          <C>
Change in benefit obligation
Benefit obligation at beginning of year                         $ 499.3       $ 473.8                          $ 85.3       $ 80.2
Service cost                                                        6.9           6.3                             1.0          1.0
Interest cost                                                      34.6          35.2                             6.2          5.9
Plan                                                                0.0          13.8                             0.0          0.0
amendments
Actuarial loss                                                      7.4          11.5                             4.5          2.7
Benefits paid                                                     (40.0)        (41.3)                           (5.0)        (4.5)
                                                                -------       -------                          ------       ------
Benefit obligation at end of year                               $ 508.2       $ 499.3                          $ 92.0       $ 85.3
                                                                =======       =======                          ======       ======

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year                  $ 712.7       $ 768.3                          $  0.0       $  0.0
Actual loss on plan assets                                        (28.1)        (15.0)                            0.0          0.0
Company                                                             0.8           0.7                             5.0          4.5
contribution
Benefits paid                                                     (40.0)        (41.3)                           (5.0)        (4.5)
                                                                -------       -------                          ------       ------
Fair value of plan assets at end of year                        $ 645.4       $ 712.7                          $  0.0       $  0.0
                                                                =======       =======                          ======       ======


Funded status                                                   $ 137.1       $ 213.4                          $(92.0)      $(85.3)
Unrecognized actuarial gain                                      (158.8)       (260.9)                           (3.5)        (8.0)
Unrecognized prior service cost                                    19.2          20.7                            10.4         11.5
Unrecognized net transition obligation                              0.1           0.3                            24.9         27.3
                                                                -------       -------                          ------       ------
Accrued benefit                                                 $  (2.4)      $ (26.5)                         $(60.2)      $(54.5)
                                                                =======       =======                          ======       ======

Weighted-average assumptions as of December 31
Discount rate                                                      7.00%         7.25%                           7.00%        7.25%
Expected return on plan assets                                     8.50%         8.50%                             NA           NA
Rate of compensation increase                                      5.00%         5.00%                             NA           NA
</TABLE>

<TABLE>
<CAPTION>
                                                                                            (Millions)
                                                                   2001          2000         1999       2001       2000      1999
                                                                   ----          ----         ----       ----       ----      ----
<S>                                                            <C>            <C>           <C>        <C>        <C>       <C>
COMPONENTS OF NET PERIODIC (BENEFIT) COST
Service cost                                                    $   6.9       $   6.3       $  6.9     $  1.0     $  1.0     $ 1.1
Interest cost                                                      34.6          35.2         32.7        6.1        5.9       5.5
Expected return on plan assets                                    (56.0)        (54.0)       (49.6)       0.0        0.0       0.0
Unrecognized transition obligation                                  0.1           0.5          0.5        2.5        2.5       2.5
Amortization of prior service                                       1.7           1.7          0.8        1.1        1.1       1.0
Recognized actuarial gain                                         (10.6)        (11.0)        (5.5)       0.0       (0.1)      0.0
                                                                -------       -------       ------     ------     ------     -----
Net periodic (benefit) cost                                     $ (23.3)      $ (21.3)      $(14.2)    $ 10.7     $ 10.4     $10.1
                                                                =======       =======       ======     ======     ======     =====
</TABLE>


     In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits on a defined dollar basis. In 2001, 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.
<PAGE>

                                      76

     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 2001, 2000, and 1999 were $3.1
million, $3.1 million, and $2.8 million, respectively.


Note 6.  LONG-TERM DEBT

FIRST MORTGAGE BONDS OF RG&E

<TABLE>
<CAPTION>
                                                                                    (Thousands of Dollars)
                                                                                       Principal Amount
                                                                                         December 31
%                           Series             Due                                  2001                 2000
--                          ------             ----                                -----                 ----
<S>                         <C>                <C>                                <C>                 <C>
9.375                       PP                 Redeemed May 10, 2001              $     --            $100,000
8.25                        QQ                 Mar. 15, 2002                       100,000             100,000
6.35                        RR/(1)/            May  15, 2032                        10,500              10,500
6.50                        SS/(1)/            May  15, 2032                        50,000              50,000
6.95                        TT                 Apr.  1, 2011                       200,000                  --
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
                                                                                  --------          ----------
                                                                                 $ 680,500            $580,500
Less:  Net bond discount                                                              (727)               (368)
       Due within one year                                                        (100,000)                 --
                                                                                  --------          ----------
Total                                                                            $ 579,773            $580,132
                                                                                  ========          ==========
</TABLE>

(1)  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 General Mortgage provides security for the First Mortgage 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 General 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 $100.0 million in 2002, and $80.0 million in 2003.
<PAGE>

                                      77

<TABLE>
<CAPTION>
  PROMISSORY NOTES AND OTHER
                                                                           (Thousands of Dollars)
                                                                                December 31
Issued                                       Due Date                        2001          2000
------                                       ---------                       ----          ----
<S>                                          <C>                            <C>           <C>
September 2, 1998/)1)/                       September 1, 2033              $ 25,500      $ 25,500
August 19, 1997/(1)/                         August 1, 2032                  101,900       101,900
December 1, 1998/(2)/                        March 31, 2014                   84,457        88,530
                                                                           ---------      --------
Total                                                                       $211,857      $215,930
Less:  RG&E Due within one year                                                4,387         4,227
                                                                           ---------      --------
Total RG&E                                                                  $207,470      $211,703
August 3, 1998/(3)/                          August 3, 2005                   14,036        17,545
November, 2000/(4)/                          November, 2005                   10,245        13,617
Other Long Term Debt of Subsidiaries                                           6,230         8,730
                                                                           ---------      --------
        Total                                                               $237,981      $251,595
Less:  RGS Due within one year                                                 7,937         7,868
                                                                           ---------      --------
Total RGS                                                                   $230,044      $243,727
                                                                           =========      ========
</TABLE>

(1)  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.

(2)  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.

(3)  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.
     RG&E has made a financial guarantee on behalf of Energetix, which obligates
     RG&E in the event of a default by Energetix in payments under the Note.
     Beginning in 1998 payments of principal and interest 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.

(4)  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 and interest are made in sixty
     monthly installments and interest accrues at the rate of 8% per year.

     Based on an estimated borrowing rate at year-end 2001 of 7.05% for long-
term debt with similar terms and average maturities (10 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $913 million at December 31, 2001.

     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.
<PAGE>

                                      78

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>

     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, 2001          2001             2000        (per share) (1)
--       ------            -----------------       -------      -----------        ---------------
<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
4.75          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>

     (1)  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, 2001 and 2000 there were 250,000 shares of Series V, 6.60%
preferred stock shares outstanding with a value of $25.0 million.

     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 2001 of 5.17% 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 $27.0 million at December 31,
2001.

     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 (8.25 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $27.0 million at December 31,
2000.
<PAGE>

                                      79

Note 8.   COMMON STOCK AND STOCK OPTIONS

     COMMON STOCK. At December 31, 2001, there were 100,000,000 shares of 1c par
value Common Stock authorized, of which 34,663,542 were outstanding. No shares
of Common Stock are reserved for warrants, conversions, or other rights. There
were 1,763,152 shares of Common Stock reserved and unissued for employees under
the 1996 Performance Stock Option Plan, as further described below.

<TABLE>
<CAPTION>

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

Shares Issued through Stock Plans         86,116        2,151
Additional Paid in Capital                              3,406
                                     -----------   ----------   -----------  ----------

Balance, December 31, 2001            34,663,542     $591,126    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 $0.01 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 2001, the Board of Directors granted 106,563 options at an exercise
price of $29.56 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 $8.36 and $29.56 respectively. None of
these options have been exercised through the end of 2001 and these options are
included in the summary of stock option activity presented on the following
page.

     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 have been exercised through the end of 2001 and these options are
included in the summary of stock option activity presented on the following
page.

     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 have been exercised through the end of 2001 and these options are
included in the summary of stock option activity presented on the following
page.

     Vesting of all outstanding options is accelerated on a change of control.
<PAGE>

                                      80

     The weighted average contractual remaining life for all options issued is
6.8 years and exercise prices range from $19.06 to $33.91 at December 31, 2001.

     Compensation expense associated with the options granted is reflected in
2001, 2000 and 1999 net income. The compensation expense associated with the
options granted was $2.6 million in 2001, $1.1 million in 2000 and $0.5 million
in 1999. 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 4.84% to
5.19% for 2001, 6.19% to 6.86% for 2000 and 4.61% to 5.16% for 1999, expected
dividend yield of 6.13% for 2001, 8.78% for 2000 and 6.03% for 1999 and expected
stock volatility of 20% for 2001, 18% for 2000 and 19% for 1999. 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:

                                                                        Weighted
                                                                         Average
                                                  Options         Exercise Price
                                                  -------         --------------

Options granted 1999                              177,322                 $29.69
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 forfeited                                 (19,171)                $19.06
Options exercised                                 (70,913)                $19.06
Outstanding at 12/31/00                           907,581                 $22.53
Vested at 12/31/00                                298,343                 $19.48
Available for future grant at 12/31/00            957,102

Options granted 2001                              106,563                 $29.56
Options forfeited                                 (15,415)                $24.65
Options exercised                                 (86,116)                $19.06
Outstanding at 12/31/01                           912,613                 $23.65
Vested at 12/31/01                                331,672                 $20.16
Available for future grant at 12/31/01            850,539

Note 9.   SHORT-TERM DEBT

     On December 31, 2001, RGS had no short-term debt outstanding. At 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. The weighted-average interest rates for borrowings during 2001 and 2000
were 6.51% and 6.94% for RG&E and 7.38% and 7.47% for Energetix, respectively.

     RG&E has a $90.0 million revolving credit agreement which terminates on
December 13, 2002. 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.
There were no borrowings under this facility at December 31, 2001.

     Griffith, a subsidiary of Energetix, has a $33.0 million revolving credit
agreement that terminates July 31, 2003. Borrowings under this agreement are
secured by personal property of Griffith. Energetix has made a financial
guarantee on behalf of Griffith that obligates Energetix in the event of a
Griffith default.
<PAGE>

                                      81

     RG&E has a Loan and Security Agreement to provide for borrowings up to
$30.0 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. In addition, RG&E has unsecured lines of credit
totaling $27.0 million available from several banks, at their discretion. RG&E
had no borrowings under either of these uncommitted facilities as of December
31, 2001.

     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, 2001, RG&E would be able to incur approximately $111.6
million of additional unsecured debt under this provision.

Note 10.  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. Amounts for RG&E are not materially different.

<TABLE>
<CAPTION>
                                                        (Thousands of Dollars)
                                                       2001       2000      1999
                                                     --------   -------   -------
<S>                                                  <C>        <C>       <C>
     OPERATING INCOME
Current:
     Federal                                         $ 67,718   $51,588   $72,336
     State                                              4,481    11,612         0
                                                     --------   -------   -------
          Total current expense                        72,199    63,200    72,336
Deferred:
     Federal                                          (23,016)   (1,213)   (7,883)
     State                                              6,207    (1,506)        0
                                                     --------   -------   -------
          Total deferred expense                     $(16,809)  $(2,719)  $(7,883)
                                                     --------   -------   -------

Income taxes attributable to operating income        $ 55,390   $60,481   $64,453
                                                     ========   =======   =======


     OTHER INCOME
Current:
     Federal                                         $ (2,341)  $ 7,842   $(2,813)
     State                                             (2,381)      108         0
                                                     --------   -------   -------
          Total current expense                        (4,722)    7,950    (2,813)
Deferred:
     Federal                                           (5,718)   (5,167)    5,702
     State                                               (845)     (146)        0
     Deferred investment tax credit                   (14,928)   (2,141)   (4,223)
                                                     --------   -------   -------
          Total deferred expense                     $(21,491)  $(7,454)  $ 1,479
                                                     --------   -------   -------

Income taxes attributable to non-operating income    $(26,213)  $   496   $(1,334)
                                                     ========   =======   =======

Total income tax expense                             $ 29,177   $60,977   $63,119
                                                     ========   =======   =======
</TABLE>
<PAGE>

                                      82

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)

                                                       2001       2000       1999
                                                     --------   --------   --------
<S>                                                  <C>        <C>        <C>
Net Income                                           $ 73,040   $ 95,559   $ 93,580
Add: income tax expense                                29,177     60,977     63,119
                                                     --------   --------   --------

Income before income taxes                           $102,217   $156,536   $156,699
                                                     ========   ========   ========

Computed tax expense at statutory tax rate           $ 35,776   $ 54,788   $ 54,845
Increases (decreases) in tax resulting from:
 State income tax expense, net of federal benefit       4,850      6,544          0
 Difference between tax depreciation
 and amount deferred                                    4,820      3,503      7,103
 Deferred investment tax credit                       (14,928)    (2,141)    (4,223)
 Miscellaneous items, net                              (1,341)    (1,717)     5,394
                                                     --------   --------   --------

Total income tax expense                             $ 29,177   $ 60,977   $ 63,119
                                                     ========   ========   ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                        (Thousands of Dollars)

                                                       2001       2000       1999
                                                     --------   --------   --------
<S>                                                  <C>        <C>        <C>
FEDERAL & STATE
Nuclear decommissioning                              $(42,700)  $(37,982)  $(28,811)
Accelerated depreciation                              104,819    214,798    218,001
Deferred investment tax credit                         12,150     21,631     23,023
Depreciation previously flowed through                 61,964    120,750    127,448
Pension                                                (2,497)   (12,306)   (21,503)
Nine Mile Two                                         128,524          -          -
Deferred NYS deduction                                 (7,995)   (12,594)         -
Other                                                  (7,784)   (16,510)       536
                                                     --------   --------   --------

Total                                                $246,481   $277,787   $318,694
                                                     ========   ========   ========
</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 RG&E and
will be amortized consistent with the depreciation of these accounts. In 2001,
$45 million of this liability was reclassified as a result of the sale of Nine
Mile Two. The net amount of the additional liability at December 31, 2001 and
2000 was $52 million and $102 million, respectively. In conjunction with the
recognition of this liability, a corresponding regulatory asset was also
recognized.

     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>

                                      83

Note 11.  COMMITMENTS AND OTHER MATTERS

CAPITAL EXPENDITURES

     The Company's 2002 construction expenditures program is currently estimated
at $152.0 million for RGS of which $148.0 million is for RG&E. The Company has
entered into certain commitments for the 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 $24.3 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. Actual costs incurred in SIR efforts could vary
materially from these estimates 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 investigating the other
three sites. RG&E has recorded a liability of approximately $21.7 million for
SIR efforts.

     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 $0.7 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.

     In November 2000, Griffith acquired both Burnwell Gas and certain assets of
the New York Fuels Division of AllEnergy Marketing Company, L.L.C. Griffith
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, Griffith
reviewed existing Phase I and Phase II environmental reports provided by
AllEnergy together with the investigative reports prepared by independent
consulting firms during the two year period prior to the acquisition.

     Griffith estimates the present value of its future aggregate cleanup costs
as of December 31, 2001 discounted at 2.7% to be approximately $2.6 million, and
has recorded an accrual to reflect this liability.

     The previous owner of Griffith is obligated under the purchase agreement
pursuant to which Energetix acquired Griffith to pay for environmental claims or
remedial action on Griffith properties owned at the time of the acquisition 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.  As
of December 31,
<PAGE>

                                      84

2001 approximately $1.5 million has been spent on these facilities and it is
estimated $1.0 million will be spent in the future.

     NEW YORK INITIATIVES. The Governor of New York has directed the NYSDEC to
require electric generating units to further reduce emissions of substances
contributing to acid rain. The Governor's objective is to establish reduction
targets for sulfur dioxide ("SO2") 50% below the current federal Acid Rain Phase
II limits and for oxides of nitrogen ("NOX") approximately 40% below existing
federal standards. Draft regulations submitted to the NYS Office of Regulatory
Reform for comment provided for a phased-in implementation beginning in 2003 and
concluding in 2007. The NYSDEC has not published a final regulatory proposal for
purposes of beginning the rule-making process.

     Separately, the NYSDEC and the New York Attorney General served RG&E with a
notice of violation ("NOV") of provisions of the Clean Air Act. The notice
alleges that between 1983 and 1987 RG&E made certain repairs, maintenance and
parts replacement at Russell Station which constituted major modifications
resulting in a significant increase in the capacity to emit SO2 without the
appropriate permits and installation of the best available emissions control
technology. RG&E denies these allegations.

     Despite RG&E's inability to definitively predict the outcome of these
separate matters, it is investigating a number of options, which would resolve
the NOV and satisfy the anticipated regulatory requirements.

OTHER MATTERS

     LEASE AGREEMENTS. RG&E and Energetix lease a total of 25 properties for
administrative offices and operating activities and lease a number of vehicles.
The total lease obligations charged to operations was $5.6 million, $5.6 million
and $5.4 million in 2001, 2000 and 1999, respectively, including $1.7 million
and $1.7 million in 2001 and 2000, respectively, for Energetix. RG&E's estimated
annual lease obligations for the years 2002-2006 are $6.7 million, $6.0 million,
$5.7 million, $5.5 million and $5.1 million, respectively. Energetix's estimated
annual lease obligations for the years 2002-2006 are $2.3 million, $2.1 million,
$1.7 million, $1.4 million and $0.9 million, respectively. Commitments under
operating leases after 2006 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.

     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, 2001 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

                     Year               $ in Thousands
                  ----------         --------------------
                     2002                   67,779
                     2003                   69,121
                     2004                   59,542
                     2005                   54,878
                     2006                   54,152
                     2007                   55,145
                     2008                   46,135
                     2009                    1,616
<PAGE>

                                      85

RG&E currently contracts for gas supply on a seasonal basis; therefore, it has
no long-term gas supply obligations.

     LONG TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER. As of January 1,
2002, RG&E had the following long-term contracts to purchase electric power from
the New York Power Authority:

<TABLE>
<CAPTION>
Generating Facility              Expiration date of       Purchased capacity in        Estimated annual
                                 contract                 MW                           capacity cost
-------------------------------------------------------------------------------------------------------------
<S>                              <C>                      <C>                          <C>
FitzPatrick nuclear facility     December 31, 2003        50                           $1,663,800

Niagara - hydroelectric          August 31, 2007          100                          $1,200,000
project

St. Lawrence - hydroelectric     August 31, 2007          55                           $  660,000
project

Blenheim - Gilboa - pumped       June 30, 2002            150                          $2,070,000
storage generating station                                                             (6 Months)
</TABLE>

     The purchased capacities shown above are based on the contracts currently
in effect. The estimated annual capacity costs are subject to price changes and
are exclusive of applicable energy charges. The total cost of purchases under
these contracts, in millions, was approximately $15.0, $13.9 and $12.1 for the
years 2001, 2000 and 1999, respectively. RG&E continues to have a contract with
New York Power Authority ("NYPA") to purchase for resale power for NYPA's Power
for Jobs customers.

     On November 7, 2001, RG&E sold its share of the Nine Mile Two nuclear power
plant to Constellation Nuclear, LLC. Simultaneously with the sale, RG&E entered
into a ten year, unit-contingent power purchase agreement for energy and
capacity of 90% of its former 14% interest in the plant. The total cost of
purchases under this contract in 2001 was approximately $5.4 million.
<PAGE>

                                      86

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, 2001             $348,513      $22,670     $13,483        $12,557     $ .36        $ .36
September 30,2001/1/           325,764       21,359       3,581          2,656       .08          .07
June 30, 2001/1/               348,437       29,678       9,673          8,748       .25          .25
March 31, 2001                 507,779       63,621      46,304         45,379      1.31         1.30

December 31, 2000/1/          $437,259      $32,809     $23,827        $22,902     $ .66        $ .66
September 30, 2000/1/          314,304       26,812      14,095         13,170       .38          .38
June 30, 2000/1/               310,705       35,153      18,295         17,369       .49          .49
March 31, 2000/1/              385,851       53,655      39,342         38,418      1.07         1.07

RG&E
----
December 31, 2001             $254,053      $21,407     $12,911        $11,986         -            -
September 30, 2001             228,840       23,440       6,336          5,411         -            -
June 30, 2001                  226,416       30,525      11,515         10,590         -            -
March 31, 2001                 330,167       59,193      42,888         41,963         -            -

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         -            -
</TABLE>

/1/     Reclassified for comparative purposes.


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

        None
<PAGE>

                                      87

                                   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 following paragraphs identify the directors of RGS Energy Group,
including their principal occupations and business experience for the past five
years.

Class I (Term expiring in 2002)

G. Jean Howard. (age 58) Ms. Howard has served as Executive Director of Wilson
Commencement Park, a human services and housing management agency empowering
low-income, single-parent families to become socially and economically self-
sufficient, since 1990. Prior to joining WCP, Ms. Howard served in management
capacities at several human services agencies nationwide. Ms. Howard serves as a
board member or trustee of numerous civic and philanthropic organizations,
including Bennett College, Monroe Community College, Center for Governmental
Research, Inc. and McQuaid Jesuit High School. Ms. Howard has been a director of
RGS Energy since August 2, 1999 and a director of RG&E since April 29, 1999.

Samuel T. Hubbard, Jr. (age 51) Mr. Hubbard has served as President and Chief
Executive Officer of High Falls Brewing Company, LLC, a producer of malt
beverages, since January 2001. He previously served as President and Chief
Executive Officer from March 2000 until January 2001 and as President and Chief
Operating Officer from June 1999 to March 2000 of the Genesee Corporation, which
conducted business in the areas of malt beverages, dry-food processing and
packaging, equipment and real estate investment. Mr. Hubbard served as President
and Chief Executive Officer of the Alling and Cory Company, a wholesale
distributor of fine printing paper and industrial and business products, from
1986 until November 1998. He is a director of High Falls Brewing Company and M&T
Bank Corporation. Mr. Hubbard has been a director of RGS Energy since August 2,
1999 and a director of RG&E since 1996.

Cleve L. Killingsworth, Jr. (age 49) Mr. Killingsworth has served as President
and Chief Executive Officer of Health Alliance Plan, a corporate affiliate of
the Henry Ford Health System, since January 1998. He served as President of
several Kaiser Foundation Health Plans from 1994 to 1997 and in senior executive
positions at Blue Cross/Blue Shield of the Rochester Area from 1986 to 1994. Mr.
Killingsworth is a director of the Reynolds and Reynolds Company. He has been a
director of RGS Energy since August 2, 1999 and a director of RG&E since July
1998.

Roger W. Kober. (age 68) Mr. Kober served as Chairman of the Board and Chief
Executive Officer of RG&E from March 1996 until his retirement in January 1998.
Mr. Kober served as Chairman of the Board, President and Chief Executive Officer
of RG&E from January 1992 to March 1996. Mr. Kober is a director of Home
Properties of New York, Inc. He has been a director of RGS Energy since August
2, 1999 and a director of RG&E since 1988.

Class II (Term expiring in 2003)

Allan E. Dugan. (age 60) Mr. Dugan has served as Executive Vice President,
Business Ethics and Compliance of Xerox Corporation since September 2001. Prior
to assuming his current position, Mr. Dugan was Executive Vice President and
President, Worldwide Business Services, Executive Vice President, Business Group
Operations, Senior Vice President, Corporate Strategic Services and Senior Vice
President and General Manager, Manufacturing Operations Worldwide. Mr. Dugan has
been a director of RGS Energy since August 2, 1999 and a director of RG&E since
1991.

Susan R. Holliday. (age 46) Ms. Holliday has been President and Publisher of the
Rochester Business Journal since 1988. She serves as a board member or trustee
of several civic and philanthropic organizations including the United Way of
Greater Rochester, Rochester Museum and Science Center,
<PAGE>

                                      88

University of Rochester Medical Center and Rochester Institute of Technology.
Ms. Holliday has been a director of RGS Energy since August 2, 1999 and a
director of RG&E since 1997.

Charles I. Plosser. (age 53) Dean Plosser has served since 1991 as the John M.
Olin Distinguished Professor of Economics and Public Policy, and as Dean since
July 1993, of the William E. Simon Graduate School of Business Administration,
University of Rochester. He has been a director of RGS Energy since August 2,
1999 and a director of RG&E since 1996.

Thomas S. Richards. (age 58) Mr. Richards has been Chairman of the Board,
President and Chief Executive Officer of RGS Energy since August 2, 1999 and
Chairman of the Board, President and Chief Executive Officer of RG&E since
January 1998. Mr. Richards was President and Chief Operating Officer of RG&E
from March 1996 to January 1998, and has served in numerous senior executive
capacities since joining RG&E as General Counsel in October 1991. Prior to
joining RG&E, Mr. Richards was an attorney with the law firm of Nixon, Hargrave,
Devans & Doyle, now Nixon Peabody LLP. He has been a director of RGS Energy
since August 2, 1999 and a director of RG&E since 1996.

Class III (Term expiring in 2004)

Angelo J. Chiarella. (age 68) Mr. Chiarella has been Director of Planning at FJF
Architects, LLP since March 1999. He served as Vice President, Rochester Midtown
L.L.C., a real estate development and leasing company, from November 1997 until
January 1999. Mr. Chiarella was previously President and Chief Executive Officer
of Midtown Holdings Corp. He is a director of Transmation, Inc. Mr. Chiarella
has been a director of RGS Energy since August 2, 1999 and a director of RG&E
since 1992.

Mark B. Grier. (age 49) Mr. Grier has been Executive Vice President, Financial
Management of The Prudential Insurance Company of America since June 1997. He
served as Chief Financial Officer of The Prudential from May 1995 to June 1997
and as Executive Vice President, The Chase Manhattan Bank, N.A. from 1991 to May
1995. He is a director of Annuity & Life Reinsurance, Ltd. Mr. Grier has been a
director of RGS Energy since August 2, 1999 and a director of RG&E since 1997.

Jay T. Holmes. (age 59) Mr. Holmes has been an attorney and business consultant
since May 1996. He served as Executive Vice President and Chief Administrative
Officer of Bausch & Lomb Incorporated from March 1995 until his retirement in
May 1996. Mr. Holmes previously held numerous executive positions at Bausch &
Lomb, serving as Senior Vice President and Chief Administrative Officer from
November 1994 to March 1995 and as Senior Vice President-Corporate Affairs and
Secretary from 1983 until November 1994. He is a director of VISX, Incorporated.
Mr. Holmes has been a director of RGS Energy since August 2, 1999 and a director
of RG&E since 1992.

Section 16(a) Beneficial Ownership Reporting Compliance

     Section 16(a) of the Securities Exchange Act of 1934 requires RGS's
directors and executive officers, as well as persons holding 10% or more of
RGS's equity securities, to file reports of ownership and changes in ownership
with the SEC and the New York Stock Exchange. These reporting persons are also
required to provide RGS with copies of all such Section 16(a) forms they file.
Based solely on RGS's review of the copies of the reports received by it, and on
the written representations of certain reporting persons, RGS believes that
during 2001 all filing requirements were timely satisfied by the directors and
executive officers of RGS.

     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".
<PAGE>

                                      89

Item 11.  EXECUTIVE COMPENSATION

     The following tables show the compensation RGS and its subsidiaries paid
for services of the chief executive officer and the next four most highly
compensated executive officers for each of the last three fiscal years:

Summary Compensation Table

<TABLE>
<CAPTION>
                                                                              Long-Term Compensation
                                                                              ----------------------
                                                                              Securities         LTIP          All Other
                                    Fiscal      Annual Compensation           Underlying         Payouts       Compensation
                                                -------------------
Name and Principal Position          Year       Salary ($)    Bonus ($)(1)    Options(2)         ($)(3)        ($)(4)
---------------------------          ----       --------------------------    ----------         ------        ------
<S>                                <C>          <C>           <C>             <C>                <C>           <C>
THOMAS S. RICHARDS                   2001       447,508       130,428         19,535                   0       13,425
Chairman of the Board, President     2000       379,174       153,133         42,683             415,985       11,375
   and Chief Executive Officer,      1999       345,954       122,422         27,256             176,094        9,524
   RGS Energy and RG&E

MICHAEL T. TOMAINO                   2001       235,996        53,243          7,300                   0        7,080
Senior Vice President and            2000       214,412        65,290         19,231             210,567        6,432
   General Counsel, RGS Energy       1999       206,162        57,355         12,689             119,872        5,673
   and RG&E

MICHAEL J. BOVALINO                  2001       234,030        53,243          6,901                   0        7,021
Senior Vice President, RGS           2000       201,852        64,293         17,713             210,936        6,056
   Energy and President and          1999       189,886        55,029         11,687             120,345        5,225
   Chief Executive Officer,
   Energetix, Inc.

PAUL C. WILKENS                      2001       233,364        55,558          6,765                   0        7,001
Senior Vice President, RGS           2000       195,510        63,033         16,038             183,219        5,865
   Energy and RG&E                   1999       171,930        47,832         10,581              32,794        4,731

ROBERT C. MECREDY                    2001       178,536        34,658          4,383                   0        5,356
Vice President, Nuclear              2000       171,668        43,523         12,156             109,138        5,150
   Operations, RG&E                  1999       163,452        35,576          7,863              63,324        4,904
</TABLE>

___________
(1)  Under the Executive Incentive Plan, the amount of annual awards depends
     upon the level of achievement of one-year goals. If performance is below a
     minimal level, no award is earned. Actual amounts of annual awards earned
     under the plan are shown.

(2)  Reflects the number of shares of common stock underlying options granted
     during the periods presented.

(3)  Grants under the Long Term Incentive Plan ceased in January 1997 and were
     replaced with an annual grant of stock options. Under the terminated plan,
     the amount of annual awards depended upon the total shareholder return over
     a three-year period ending in December of such year, as compared to the
     companies which comprise the EEI Index of investor-owned electric
     utilities. The plan also included a financial performance measurement which
     compared RGS Energy's cash flow return on net assets against a pre-
     established target goal identified in RGS Energy's corporate business plan.
     The table reports actual amounts earned at the end of each performance
     cycle, grossed up to cover federal and state income taxes. Awards granted
     under the Plan were paid in cash. Participants were required to invest the
     after-tax proceeds in shares of RGS common stock and to retain the shares
     for a period of at least three years.

(4)  Amounts represent contributions to the RG&E Savings Plus Plan (401(k) Plan)
     and the 401(k) Restoration Plan.
<PAGE>

                                      90

Option Grants In Last Fiscal Year (2001)

<TABLE>
<CAPTION>
                                                                                   Individual Grants(1)
                                                         -----------------------------------------------------------------------
                                                         Number of       Percent of
                                                         Securities      Total Options
                                                         Underlying      Granted to      Exercise or               Grant Date
                                                         Options         Employees in    Base Price    Expiration  Present Value
Name                                                     Granted (#)     Fiscal Year     ($/Share)     Date        ($)(2)
----                                                     -----------     ----------      ---------     ----        ------
<S>                                                      <C>             <C>             <C>           <C>         <C>
Thomas S. Richards.....................................  19,535          18.3%           $29.56        1/17/11     $188,650
Michael T. Tomaino.....................................   7,300           6.9%           $29.56        1/17/11     $ 23,783
Michael J. Bovalino....................................   6,901           6.5%           $29.56        1/17/11     $ 66,643
Paul C. Wilkens........................................   6,765           6.3%           $29.56        1/17/11     $ 65,329
Robert C. Mecredy......................................   4,383           4.1%           $29.56        1/17/11     $ 42,327
</TABLE>

(1)  The options shown in this table were granted in January 2001 under the 1996
     Performance Stock Option Plan. All options are vested as of the date of
     grant; however, they may not be exercised for at least three years. Options
     carry dividend rights which provide for a cash payment upon exercise of an
     option in an amount equal to the quarterly dividend payments per share of
     RGS common stock paid to RGS shareholders from the date the option was
     granted until the date of exercise.

(2)  The grant date valuation was calculated using the Black-Scholes option
     pricing model assuming stock price volatility of 20%, a risk-free rate of
     return of 5.19% and an annual dividend yield of 6.13%. The weighted average
     fair value of an option as of the grant date is $8.36.

Aggregated Option Exercises in Last Fiscal Year (2001)
and Fiscal Year-End Option Values

<TABLE>
<CAPTION>
                                                              Number of Securities              Value of Unexercised In-the
                              Shares                          Underlying Unexercised            Money Options at Fiscal
                              Acquired on     Value           Options at Fiscal Year End (#)    Year End ($) (1)
Name                          Exercise (#)    Realized ($)    Exercisable      Unexercisable    Exercisable   Unexercisable
----                          ------------    ------------    -----------      -------------    -----------   -------------
<S>                           <C>             <C>             <C>              <C>              <C>           <C>
Thomas S. Richards..........             0               0    55,423           110,462          $923,556      $1,174,964
Michael T. Tomaino..........             0               0    24,913            47,525          $320,132      $  592,266
Michael J. Bovalino.........             0               0    31,785            36,301          $589,214      $  448,641
Paul C. Wilkens.............             0               0    18,300            44,752          $294,004      $  485,385
Robert C. Mecredy...........             0               0    19,171            24,402          $355,382      $  303,838
</TABLE>

___________
(1)  Based on the market value of the stock at fiscal year-end less exercise
     price. For exercisable options, does not include the value of dividend
     equivalent rights from the date the options were granted to December 31,
     2001 as follows: Mr. Richards, $486,214; Mr. Tomaino, $190,584; Mr.
     Bovalino, $286,065; Mr. Wilkens, $156,175; and Mr. Mecredy, $172,539.
<PAGE>

                                      91

Retirement Plans

     RGS has a non-contributory, tax qualified, defined benefit pension plan
known as the RG&E Retirement Plan. RGS also has an unfunded, non-qualified plan
known as the RG&E Unfunded Retirement Income Plan. All employees of RGS and
certain of its subsidiaries, including executive officers, are eligible to
participate in these plans. The benefit provided by the RG&E Retirement Plan and
the RG&E Unfunded Retirement Income Plan is based upon one of the two following
formulas depending on age and service on December 31, 1999:

     .  a pension equity plan formula; or
     .  final average pay (highest 36 month average of the last 120 months prior
        to retirement).

     The pension equity plan formula was introduced effective July 1, 1999.
Employees whose age and service equaled 75 or who were age 55 with 10 years of
service on December 31, 1999 receive the most valuable of these two formulas.
All other employees' benefits will be based on the pension equity plan formula
only. The pension equity plan provides a lump sum payment option as well as
monthly annuity options.

     RGS also has an unfunded supplemental executive retirement plan, known as
the RG&E Unfunded Supplemental Executive Retirement Plan, in which executive
officers participate. The annual pension benefit under these plans, taken
together, is determined by the employee's years of service and annual
compensation (salary and bonus). Under the Internal Revenue Code of 1986, the
annual benefit payable by the funded plan was limited to $140,000 for 2001. The
unfunded plans will provide those benefits which cannot be fully provided by the
funded plan. The table below may be used to calculate the approximate annual
benefits payable as a straight-life annuity to executive officers at normal
retirement age (65) under these plans in specified remuneration and years-of-
service classifications.

<TABLE>
<CAPTION>
                                             Retirement Benefits Based on Years of Service ($) (2)
                                             -----------------------------------------------------
Average Annual
--------------
Salary($)(1)                                 5          10         15         20         25         30         40
------------                                 -          --         --         --         --         --         --
<S>                                          <C>        <C>        <C>        <C>        <C>        <C>        <C>
150,000..................................     30,000     56,250     78,750     97,500     97,500     97,500    106,000
200,000..................................     40,000     75,000    105,000    130,000    130,000    130,000    143,500
250,000..................................     50,000     93,750    131,250    162,500    162,500    162,500    178,000
300,000..................................     60,000    112,500    157,500    195,000    195,000    195,000    216,500
350,000..................................     70,000    131,250    183,750    227,500    227,500    227,500    253,000
400,000..................................     80,000    150,000    210,000    260,000    260,000    260,000    289,500
450,000..................................     90,000    168,750    236,250    292,500    292,500    292,500    326,000
500,000..................................    100,000    187,500    262,500    325,000    325,000    325,000    362,500
550,000..................................    110,000    206,250    288,750    357,500    357,500    357,500    399,100
</TABLE>
___________
(1)  Average annual salary includes base pay (three highest consecutive years)
     and annual bonus (three highest years) during the last ten years before
     retirement. The amounts shown in the salary and bonus columns in the
     Summary Compensation Table constitute qualifying compensation under the
     plans.

(2)  Messrs. Richards, Tomaino, Bovalino, Wilkens and Mecredy have been credited
     with 18, 12, 5, 28 and 30 years of service, respectively, under the plans.
<PAGE>

                                      92
Severance Agreements

     RGS has entered into severance agreements for an indefinite term with
Messrs. Richards, Tomaino, Bovalino, Wilkens and Mecredy. The agreements provide
that each of the officers that is a party to the agreements is obligated, in the
event of an attempted change of control (as defined in the agreements), not to
leave RGS and to render certain services to RGS for a designated period. The
agreements also provide that the officer is entitled to specified compensation
and benefits if, within three years after a change in control, the officer's
employment is involuntarily terminated, other than for cause (as defined in the
agreements) or by reason of death, disability or normal retirement. Involuntary
termination also includes the officer's resignation following a change in duties
(as defined in the agreements). If an involuntary termination occurs within the
three-year covered period, the officer will receive a lump sum payment equal to
three times his annual salary (as defined in the agreements) in the case of
Messrs. Richards, Tomaino, Bovalino and Wilkens and two times his annual salary
(as defined in his agreement) for Mr. Mecredy and certain other benefits
including health and death benefits and outplacement and relocation expense
reimbursement. The agreements also provide for a gross-up for any excise taxes
that may apply under Section 4999 of the Internal Revenue Code.

Directors' Compensation

     RGS pays its directors an annual retainer of $22,000, $11,000 in cash and
$11,000 to be applied to the purchase of shares of RGS common stock. RGS pays
committee chairmen an additional annual cash retainer of $3,000. Directors
receive $900 for each Board or committee meeting attended and $600 for each
additional Board or committee meeting attended the same day.

     RGS does not pay its officers any fees for their services as directors. The
total amount of compensation RGS pays to its directors is comparable to the
total compensation paid to directors of similar sized combination electric and
gas utility companies.

     RGS has deferral plans under which a director's fees and the cash portion
of his or her retainer may either be deferred with interest in a cash account or
deferred and converted to common stock equivalent units which earn dividends
equal to dividends declared on RGS common stock. In either case, deferred
amounts are paid in cash, in a lump sum or over a period of up to ten years
commencing no later than the director's 70/th/ birthday.

     RGS has a Deferred Stock Unit Plan for Non-Employee Directors which also
serves to align the directors' financial interests with those of the
shareholders. Each director's deferred stock account is based on the amount of
the annual retainer, the number of years of Board service, and the price of
RGS's common stock. Under the Plan, each non-employee director is credited
annually with deferred stock units equal to 75% of his or her annual retainer.
Benefits under the Plan become partially vested after five years of service and
are fully vested after ten years. Upon cessation of membership on the Board,
deferred amounts will be payable in cash in a lump sum or in up to ten annual
installments as determined by each director.

Compensation Committee Interlocks and Insider Participation

     The RGS Committee on Management consists of three outside directors:
Messrs. Dugan, Grier, and Plosser (Chairman). There are no officers or employees
of RGS serving on the committee.
<PAGE>

                                      93

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        The following table indicates the number of shares of RGS common stock
and equivalent units beneficially owned as of December 31, 2001 by (a) each RGS
director, (b) each of the RGS executive officers named in the Summary
Compensation Table included elsewhere herein, and (c) the RGS executive officers
and directors as a group. As of December 31, 2001, each of the individuals
listed in the table, as well as the RGS directors and executive officers as a
group, beneficially owned less than 1.0% of the total shares outstanding. The
following persons disclaim beneficial ownership with respect to shares of RGS
common stock held by their spouses: Mr. Bovalino, 16,607 shares; Mr. Chiarella,
319 shares; Ms. Holliday, 411 shares; Mr. Kober, 8,256 shares; Mr. Wilkens,
2,586 shares; Mr. Mecredy, 8,732; and all RGS directors and executive officers
as a group, including the aforementioned, 46,284 shares.

<TABLE>
<CAPTION>
                                                                                              Total RGS Energy
                                                                                              Common Stock
                                                         RGS Energy         RGS Energy        and
                                                         Common             Common Stock      Common Stock
                                                         Stock              Equivalent Units  Equivalent Units
                                                         Beneficially       Beneficially      Beneficially
Name of Beneficial Owner                                 Owned(1)(2)        Owned(3)          Owned
------------------------                                 -----------        --------          -----
<S>                                                      <C>                <C>               <C>
Michael J. Bovalino...................................      49,386                393           49,779
Angelo J. Chiarella...................................       2,745             18,331           21,076
Allan E. Dugan........................................       1,780              9,480           11,260
Mark B. Grier.........................................       2,344              2,608            4,952
Susan R. Holliday.....................................       2,845              3,523            6,368
Jay T. Holmes.........................................       4,184             19,190           23,374
G. Jean Howard........................................       1,230              2,013            3,243
Samuel T. Hubbard, Jr.................................       1,744              4,314            6,058
Cleve L. Killingsworth, Jr............................         878              2,590            3,468
Roger W. Kober........................................      14,348              3,594           17,942
Robert C. Mecredy.....................................      29,502                 24           29,526
Charles I. Plosser....................................       1,536              4,269            5,805
Thomas S. Richards....................................      87,988              3,289           91,277
Michael T. Tomaino....................................      46,086                523           46,609
Paul C. Wilkens.......................................      29,076                281           29,357
All Directors and
Executive Officers as
a group (17 Individuals)..............................     322,810             74,422          397,232
</TABLE>

(1)  Includes shares of RGS common stock over which the named person has direct
     or indirect voting or investment power.

(2)  Includes shares of RGS common stock which may be acquired through the
     exercise of stock options as follows: Mr. Bovalino, 31,785 shares; Mr.
     Mecredy, 19,171 shares; Mr. Richards, 55,423 shares; Mr. Tomaino, 24,914
     shares; Mr. Wilkens, 18,300 shares; and all directors and executive
     officers as a group, including the aforementioned, 180,438 shares.

(3)  Includes RGS common stock equivalent units accrued under RGS and RG&E
     employee and director benefit plans for which the named person does not
     have voting rights.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        Since January 1, 2001, there have been no transactions involving any RGS
director, RGS executive officer, RGS security holder who is known to RGS to own
of record or beneficially more than five percent of RGS's voting securities, or
member of the immediate family of any of the foregoing, in which RGS or any of
its subsidiaries was or is to be a party, in which the amount of such
transaction exceeded
<PAGE>

                                      94

$60,000 and in which any of the aforementioned persons had, or will have, a
direct or indirect material interest.
<PAGE>

                                      95

                                    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, 2001, 2000 and 1999.

          RGS Consolidated Statement of Retained Earnings for each of the three
          years ended December 31, 2001, 2000 and 1999.

          RGS Consolidated Balance sheet at December 31, 2001 and 2000.

          RGS Consolidated Statement of Cash Flows for each of the three years
          ended December 31, 2001, 2000 and 1999.

          RG&E Consolidated Statement of Income for each of the three years
          ended December 31, 2001, 2000 and 1999.

          RG&E Consolidated Statement of Retained Earnings for each of the three
          years ended December 31, 2001, 2000 and 1999.

          RG&E Consolidated Balance sheet at December 31, 2001 and 2000.

          RG&E Consolidated Statement of Cash Flows for each of the three years
          ended December 31, 2001, 2000 and 1999.

          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, 2001, 2000 and 1999:

          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 the Nine Mile Point Two Nuclear Plant to
          Constellation Nuclear, a wholly owned subsidiary of Constellation
          Energy
<PAGE>

                                      96

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

                            (Thousands of Dollars)

FOR THE YEAR ENDED DECEMBER 31, 1999

<TABLE>
<CAPTION>
                                                              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

FOR THE YEAR ENDED DECEMBER 31, 2000

<CAPTION>
                                                              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

FOR THE YEAR ENDED DECEMBER 31, 2001

<CAPTION>
                                                              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                        $33,482                                           $4,000          $29,482
Materials and supplies obsolescence             2,264                                              699            1,565
Nuclear refueling outage accrual                2,898            11,308                          4,003           10,203

RGS Reserves for:
Uncollectible accounts                        $34,550         $   2,518           $ 36          $6,858          $30,246
Materials and supplies obsolescence             2,264                                              699            1,565
Nuclear refueling outage accruals               2,898            11,308                          4,003           10,203
</TABLE>


Beginning in 1992 the Company no longer charges uncollectible expenses through
the uncollectible reserve. The total amount written off directly to expense in
1999 was $11.9 million, in 2000 was $9.2 million and in 2001 was $9.5 million.

The Company levelizes estimated incremental non-fuel expenses due to planned
refueling outages at its nuclear power plant. Such costs are charged to expense
between refueling outages. On November 7, 2001, the Company sold its ownership
interest in Nine Mile Two to Constellation Nuclear.
<PAGE>

                                      97


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. (Filed as 2-1 in
                    February 2001 on Form 10-K for the year ended December 31,
                    2000, SEC File No.1-672)


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)
<PAGE>

Exhibit 10-1*            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 10-2*            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 10-3*            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 10-4*       (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 10-5*       (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 10-6*       (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 10-7*       (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 10-8*       (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 10-9*       (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 10-10*      (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 10-11*      (A)    Amendment to the April 26,2000 agreement, effective
                           February 21, 2001, between RGS, RG&E and Paul C.
                           Wilkens. (Filed as Exhibit 10-1 in May 2001 on Form
                           10-Q for the quarter ended March 31, 2001, SEC File
                           No. 0-30338)

Exhibit 10-12*      (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 10-13*      (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 10-14*      (A)    Amendment to the April 26,2000 agreement, effective
                           February 21, 2001, between RGS, Energetix and Michael
                           J. Bovalino. (Filed as Exhibit 10-2 in May 2001 on
                           Form 10-Q for the quarter ended March 31, 2001, 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)
<PAGE>

                                      99


Exhibit 10-16*      (A)       Amendment to the April 26,2000 agreement,
                              effective February 21, 2001, between RGS, RG&E and
                              Michael T. Tomaino. (Filed as Exhibit 10-3 in May
                              2001 on Form 10-Q for the quarter ended March 31,
                              2001, SEC File No. 0-30338)

Exhibit 10-17*                Amended and Restated Settlement Agreement dated
                              October 23, 1997 between the Company the Staff of
                              the New York Public Service Commission (PSC), and
                              certain other parties (Filed as Exhibit 10-4 on
                              Form 10-Q for the quarter ended September 30,
                              1997, SEC File No. 1-672) as amended pursuant to
                              an order of the PSC issued January 14, 1998
                              (excluding Appendices). (Filed as Exhibit 10-18 in
                              February 1998 on Form 10-K for the year ended
                              December 31, 1997, SEC File No. 1-672)

Exhibit 10-18*      (A)       Form of Rochester Gas and Electric Corporation
                              1996 Performance Stock Option Plan Agreement.
                              (Filed as Exhibit 10-1 in November 1997 on Form
                              10-Q for the quarter ended September 30, 1997, SEC
                              File No. 1-672)

Exhibit 10-19*                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 10-20*      (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 10-21*      (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 10-22*                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. (Filed as 10-21 in February 2001 on Form 10-
                              K for the year ended December 31, 2000, SEC File
                              No.1-672)

Exhibit 10-23*                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. (Filed as 10-22 in February 2001 on Form 10-
                              K for the year ended December 31, 2000, SEC File
                              No.1-672)

Exhibit 10-24*                Joint Proposal to PSC dated August 7, 2001 between
                              the Company the Staff of the New York Public
                              Service Commission, regarding the rate-making
                              treatment associated with RG&E's recovery of its
                              remaining investment in Nine Mile Two and related
                              costs. (Filed as Exhibit 99-1 on Form 8-K dated
                              August 9, 2001, SEC File No. 1-672)

Exhibit 10-25                 Order issued on October 26, 2001 by the PSC
                              authorizing the sale by certain owners of Nine
                              Mile Two of their interest in Nine Mile Two.

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>

                                      100

                                  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


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

DATE:  February 19, 2002

       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.

<TABLE>
<CAPTION>
SIGNATURE                                  TITLE (RGS and RG&E                  DATE
---------                                  ------                               ----
                                           unless otherwise noted)
<S>                                       <C>                                  <C>
Principal Executive Officer:



     /s/ Thomas S. Richards                Chairman, President and              February 19, 2002
----------------------------------
      (Thomas S. Richards)                 Chief Executive Officer


Principal Financial Officer:



     /s/ Mark Keogh                        Treasurer of RGS;                    February 19, 2002
----------------------------------
      (Mark Keogh)                         Vice President and Treasurer
                                           of RG&E


Principal Accounting Officer:



     /s/ William J. Reddy                  Controller of RGS;                   February 19, 2002
----------------------------------
      (William J. Reddy)                   Vice President and
                                           Controller of RG&E
</TABLE>
<PAGE>

                                      101

<TABLE>
<CAPTION>
SIGNATURE                                            TITLE                                     DATE
---------                                            -----                                     ----
<S>                                                  <C>                                     <C>
Directors of RGS and RG&E:

                                                     Director
____________________________________________
           (Angelo J. Chiarella)


             /s/ Allan E. Dugan                      Director                                  February 19, 2002
--------------------------------------------
              (Allan E. Dugan)


              /s/ Mark B. Grier                      Director                                  February 19, 2002
--------------------------------------------
               (Mark B. Grier)


                                                     Director
--------------------------------------------
            (Susan R. Holliday)


              /s/ Jay T. Holmes                      Director                                  February 19, 2002
--------------------------------------------
               (Jay T. Holmes)


             /s/ G. Jean Howard                      Director                                  February 19, 2002
--------------------------------------------
              (G. Jean Howard)


         /s/ Samuel T. Hubbard, Jr.                  Director                                  February 19, 2002
--------------------------------------------
          (Samuel T. Hubbard,Jr.)


       /s/ Cleve L. Killingsworth, Jr.               Director                                  February 19, 2002
--------------------------------------------
       (Cleve L. Killingsworth, Jr.)


             /s/ Roger W. Kober                      Director                                  February 19, 2002
--------------------------------------------
              (Roger W. Kober)


            /s/ Charles I. Plosser                   Director                                  February 19, 2002
--------------------------------------------
            (Charles I.Plosser)


           /s/ Thomas S. Richards                    Director                                  February 19, 2002
--------------------------------------------
             (Thomas S. Richards)
</TABLE>