UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION

                            Washington, D. C. 20549

                                   FORM 10-K

                                ---------------

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

For the fiscal year ended......................December 31, 1998

                         Commission file number 1-3268

                   CENTRAL HUDSON GAS & ELECTRIC CORPORATION
            ------------------------------------------------------
            (Exact name of registrant as specified in its charter)


            New York                               14-0555980
-------------------------------                  ----------------
(State or other jurisdiction of                  (I.R.S. Employer
incorporation or organization)                  Identification No.)

284 South Avenue, Poughkeepsie, New York                12601-4879
----------------------------------------                ----------
(Address of principal executive offices)                (Zip Code)


Registrant's telephone number, including area code (914) 452-2000
                                                   --------------

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

                                                Name of each exchange
Title of Each Class                              On Which Registered
-------------------                             ---------------------
Common Stock, $5.00 par value                   New York Stock Exchange

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

                               Title of Each Class
                               -------------------
                           Cumulative Preferred Stock:
                                  4 1/2% Series
                                  4.75% Series


<PAGE>



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

                  NO [   ]            YES  [ X ]

            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 ]

            The  aggregate  market  value of the  voting and  non-voting  common
equity held by  non-affiliates  of the  Registrant as of February 18, 1999,  was
$628,112,741 based upon the lowest price at which Registrant's  Common Stock was
traded on such  date,  as  reported  on the New York Stock  Exchange  listing of
composite transactions.

            The number of shares outstanding of Registrant's Common Stock, as of
February 18, 1999, was 16,862,087.

                      DOCUMENTS INCORPORATED BY REFERENCE
                      -----------------------------------

            Certain portions of Registrant's Annual Report to Shareholders,  for
the fiscal year ended December 31, 1998, are  incorporated by reference in Parts
I, II and IV of this Report.

            Registrant's  definitive Proxy Statement, to be dated March 1, 1999,
and to be used in connection  with its Annual Meeting of Shareholders to be held
on April 27, 1999, is incorporated by reference in Part III hereof.


<PAGE>



                               TABLE OF CONTENTS

                                                                        Page
                                                                        ----

Table of Contents
-----------------

                                    PART I
                                    ------

ITEM 1    BUSINESS                                                       1
------

            Generally                                                    1

            Rates                                                        2

            Regulation                                                   3

            Construction Program and Financing                           3

            Fuel Supply and Cost                                         4

            Environmental Quality                                        6

            Other Matters                                                9

            Executive Officers of the Company                           11

ITEM 2   PROPERTIES                                                     13
------

            Electric                                                    13

            New York Power Pool/Independent System Operator             18

            Gas                                                         19

            Other Matters                                               21

ITEM 3   LEGAL PROCEEDINGS                                              21
------

ITEM 4   SUBMISSION OF MATTERS TO A VOTE OF SECURITY
------   HOLDERS                                                        24

                                      (i)


<PAGE>



                          TABLE OF CONTENTS (Cont'd)

                                                                       Page
                                                                       ----

                                    PART II
                                    -------

ITEM 5      MARKET FOR THE COMPANY'S COMMON EQUITY AND
------      RELATED STOCKHOLDER MATTERS                                 24

ITEM 6      SELECTED FINANCIAL DATA                                     25
------

ITEM 7      MANAGEMENT'S DISCUSSION AND ANALYSIS OF
------      FINANCIAL CONDITION AND RESULTS OF OPERATIONS               27

ITEM 7A     QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
-------     MARKET RISK                                                 50

ITEM 8      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                 51
------

ITEM 9      CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
------      ON ACCOUNTING AND FINANCIAL DISCLOSURE                     100

                                   PART III
                                   --------

ITEM 10     DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY  100
-------

ITEM 11     EXECUTIVE COMPENSATION                                     100
-------

ITEM 12     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
-------     OWNERS AND MANAGEMENT                                      100

ITEM 13     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS             100
-------

                                    PART IV
                                    -------

ITEM 14     EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND
-------     REPORTS ON FORM 8-K                                        101

SIGNATURES                                                             103

                                     (ii)


<PAGE>



                                    PART I
                                    ------

FORWARD LOOKING STATEMENTS

            This Form 10-K Report and the  documents  incorporated  by reference
may  contain  statements  which,  to the  extent  they  are not  recitations  of
historical fact, constitute  "forward-looking  statements" within the meaning of
the Securities  Litigation  Reform Act of 1995 ("Reform Act").  These statements
will contain words such as "believes,"  "expects,"  "intends," "plan," and other
similar words. All such forward-looking statements are intended to be subject to
the safe harbor  protection  provided  by the Reform Act. A number of  important
factors  affecting  the  Company's  business and  financial  results could cause
actual results to differ  materially  from those stated in the forward-  looking
statements.   Those  factors   include   weather,   energy  supply  and  demand,
developments  in  the  legislative,   regulatory  and  competitive  environment,
electric and gas industry restructuring and cost recovery,  future market prices
for energy,  capacity and ancillary services,  nuclear industry regulation,  the
outcome of pending litigation,  and certain environmental matters,  particularly
ongoing  development of air quality  regulations and hazardous waste remediation
requirements.

      ITEM 1 - BUSINESS
      -----------------

GENERALLY

            Registrant  ("Company") is a gas and electric  corporation formed on
December 31, 1926, as a consolidation of several  operating  utilities which had
been accumulated  under one management during the previous 26 years. The Company
generates,  purchases and distributes electricity, and purchases and distributes
gas.  The  Company,  in the  opinion of its  general  counsel,  has,  with minor
exceptions,  valid  franchises,  unlimited  in  duration,  to serve a  territory
extending  about 85 miles  along the Hudson  River and about 25 to 40 miles east
and west from such River.  The southern  end of the  territory is about 25 miles
north of New York City, and the northern end is about 10 miles south of the City
of Albany.  The territory,  comprising  approximately  2,600 square miles, has a
population  estimated at 622,000.  Electric service is available  throughout the
territory,  and  natural  gas  service  is  provided  in and about the cities of
Poughkeepsie,  Beacon,  Newburgh  and  Kingston  and  in  certain  outlying  and
intervening territories.  The number of Company employees, at December 31, 1998,
was 1,149.

            The Company's  territory reflects a diversified  economy,  including
manufacturing  industries,  research firms, farms, governmental agencies, public
and private institutions, resorts, and wholesale and retail trade operations.

                                      1


<PAGE>



            For  information  concerning  revenues and  operating  income before
taxes and operating  profits and information  regarding assets for the electric,
gas, and other segments,  which are currently the significant  industry segments
of the Company, see Note 10 - "Segments and Related Information" of the Notes to
the  Financial  Statements  referred  to in Item 8 hereof  (each such Note being
hereinafter called the "Note").

            In 1998,  the  competitive  market  place  continued  to develop for
electric  utilities and certain electric customers were given the opportunity to
purchase  energy and  related  services  from  sources  other  than their  local
utility. These opportunities also exist today for natural gas customers.

            See Item 7 hereof under the caption "Competition/  Deregulation" and
Note 2 -  "Regulatory  Matters"  hereof  for a  discussion  of the  Amended  and
Restated Settlement Agreement  ("Agreement") reached between the Company and the
Public  Service  Commission  of the  State  of New  York  ("PSC")  in the  PSC's
Competitive  Opportunities   Proceeding,   which  Agreement  may  affect  future
operations of the Company.  See the caption "Holding Company  Restructuring"  in
Note 2 - "Regulatory  Matters"  hereof for a discussion of the proposed  holding
company restructuring of the Company.

RATES

            Generally:  The electric and gas rates of the Company  applicable to
service  supplied to retail customers within the State of New York are regulated
by the PSC.  Transmission  rates and rates for  electricity  sold for  resale in
interstate  commerce are regulated by the Federal Energy  Regulatory  Commission
("FERC").

            The Company's present full-service retail rate structure consists of
various service classifications covering residential,  commercial and industrial
customers.  During 1998,  the average price of electricity to such customers was
8.45 cents per kilowatthour ("kWh"),  representing a 1.2% decrease from the 1997
average price.

            Rate  Proceedings - Electric and Gas: For information  regarding the
Company's  most recent  electric  and gas cases  filed with the PSC,  see Item 7
hereof under the caption "Rate Proceedings."

            Cost  Adjustment  Clauses:  For  information  with  respect  to  the
Company's  electric and gas cost  adjustment  clauses,  see Note 1 - "Summary of
Significant  Accounting Policies" hereof under the caption "Rates,  Revenues and
Cost Adjustment Clauses."

                                      2


<PAGE>



REGULATION

            Generally:  The  Company is subject  to  regulation  by the PSC with
respect to, among other things,  service rendered (including the rates charged),
major  transmission  facility  siting,  accounting  procedures  and  issuance of
securities.

            Certain of the Company's  activities,  including  accounting and the
acquisition  and disposition of certain  property,  are subject to regulation by
the FERC,  under the Federal Power Act, by reason of the Company's  transmission
and sales for resale of electric energy in interstate commerce.

            The Company is not subject to the provisions of the Natural Gas Act.

            In the opinion of general  counsel for the  Company,  the  Company's
major hydroelectric facilities are not required to be licensed under the Federal
Power Act.

            Purchased  Electric Power Generation:  Pursuant to the provisions of
the federal Public Utility  Regulatory  Policies Act of 1978 ("PURPA"),  and the
New York  Public  Service Law  ("NYPSL"),  the Company is required to enter into
long-term  contracts  to  purchase  electric  power  generated  by small  hydro,
alternative   energy  and  cogeneration   facilities  which  meet  qualification
standards  established by such statutes and the regulatory programs  promulgated
thereunder.  With respect to facilities  qualified under PURPA, the Company must
pay its avoided cost (the cost the Company would otherwise incur to generate the
increment  of power  purchased)  for electric  power  purchased  from  qualified
facilities.  As of December  31,  1998,  the  Company's  avoided cost at the 115
kilovolt ("kV") transmission level was approximately 3.0 cents per kWh.

CONSTRUCTION PROGRAM AND FINANCING

            For  estimates  of   construction   expenditures,   internal   funds
available,  mandatory  and  optional  redemption  of long-term  securities,  and
working  capital  requirements  for  the  two-year  period  1999-2000,  see  the
subcaption  "Construction  Program" in Item 7 hereof under the caption  "Capital
Resources and Liquidity."

            For a  discussion  of the  Company's  capital  structure,  financing
program and short-term borrowing arrangements,  see Notes 5, 6 and 7 "Short-term
Borrowing Arrangements,"  "Capitalization - Capital Stock" and "Capitalization -
Long-term Debt," respectively,  and Item 7 hereof under the subcaptions "Capital
Structure,"  "Financing  Program" and "Short-Term  Debt" of the caption "Capital
Resources and Liquidity."

                                      3


<PAGE>



            The  Company's  Certificate  of  Incorporation  and its various debt
instruments do not contain any limitations upon the issuance of authorized,  but
unissued, preferred stock and common stock or of unsecured short-term debt.

            The Company's various debt instruments include limitations as to the
amount of  additional  funded  indebtedness  which the  Company  can issue.  The
Company  believes such  limitations  will not impair its ability to issue any or
all of the debt  described  under  the  above-referenced  subcaption  "Financing
Program."

FUEL SUPPLY AND COST

            The  Company's two primary  fossil  fuel-fired  electric  generating
stations are the Roseton  Steam  Electric  Generating  Plant  ("Roseton  Plant")
(described  in Item 2 hereof  under the  subcaptions  "Electric  - General"  and
"Electric - Roseton Plant") and the Danskammer  Point Steam Electric  Generating
Station  ("Danskammer Plant") (referred to in Item 2 hereof under the subcaption
"Electric - General").  Units 1 and 2 of the Roseton Plant are fully equipped to
burn both residual oil and natural gas. Units 1 and 2 of the  Danskammer  Plant,
which are  equipped to burn  residual  oil or natural  gas,  are  operated  when
economical.  Units  3  and  4  of  the  Danskammer  Plant,  which  are  operated
predominantly, are capable of burning coal, natural gas, or residual oil.

            For the 12 months ended  December 31, 1998,  the sources and related
costs of electric generation for the Company were as follows:

                                Aggregate
Sources of                    Percentage of                 Costs in 1998
Generation                  Energy Generated                   ($000)
----------                  ----------------                -------------
Purchased Power                   22.4%                       $ 40,441
Coal                              40.1                          43,289
Gas                                5.5                           8,190
Nuclear                           10.4                           2,984
Oil                               19.3                          27,892
Hydroelectric                     2.3                              450
                                -----

                                100.0%
                                =====

Fuel Handling Costs                                              1,729
Deferred Fuel Cost                                                 286
                                                              --------
                                                              $125,261
                                                              ========

          Residual Oil: At December 31, 1998, there were 403,369 barrels of fuel
oil in inventory in  Company-owned  tanks for use in the  Danskammer and Roseton
Plants, which aggregate amount

                                      4


<PAGE>



represents an average daily supply for 20 days.  The total oil storage  capacity
as of December 31,  1998,  for these  Plants was 16,251 and  1,079,000  barrels,
respectively. The Company's share of the Roseton Plant's oil storage capacity is
377,650 barrels.

            During  1998,  there  were no  purchases  of fuel  oil  made for the
Danskammer Plant.

            During 1998, the Roseton Plant's fuel oil requirements were supplied
under both firm and spot market  contracts.  The prices under the firm  contract
were  determined on the basis of published  market indices in effect at the time
of  delivery.  The term of the firm  contract  became  effective on September 1,
1996, and continued through its expiration on August 31, 1998. This contract was
replaced with the Company making spot market purchases.

            Coal: In order to provide for its future requirements for coal to be
burned in Units 3 and 4 at the Danskammer Plant, the Company,  effective January
1, 1997,  entered into two supply  contracts for the purchase of an aggregate of
720,000 tons per year of low sulfur (0.7% maximum) coal.

            One contract provides for the delivery of coal by water from sources
in Venezuela and Colombia, South America. As required by this contract, the base
price of purchases  under this  contract are  renegotiated  by the parties on an
annual  basis.  The  contract,  as last  renegotiated,  now covers the term from
January 1, 1998 through December 31, 2001.

            The second  contract,  which  provided  for the delivery of domestic
coal by rail,  expired on December  31, 1998.  The base price of  purchases  was
fixed for the term of that  contract.  The  Company,  effective  January 1, 1999
through December 31, 2001, has entered into another supply contract from sources
in Venezuela and Colombia and a third  contract  which provides for the delivery
of  domestic  coal by water or  rail.  All  three  contracts  can be  terminated
effective  December 31, 2000,  with six months'  written notice to the supplier.
The base price is fixed for 1999 with annual  reopeners  which provide for rates
to be renegotiated by all parties thereafter.

            The Company has also entered into a long-term  rail contract for the
delivery  of coal.  This  contract  covers  the period  January 1, 1997  through
December 31, 2001.  During the first two years of this contract,  rail rates are
fixed and thereafter such rates will be negotiated by the parties.

            The Company also purchased during 1998 approximately 172,600 tons of
its coal supply on the spot market.

                                      5


<PAGE>



            Nuclear:  For information  regarding fuel reloading at Unit No. 2 of
the Nine Mile Point Nuclear Station ("Nine Mile 2"), of which the Company owns a
9% interest,  see Item 7 hereof under the subcaption "Nuclear Operations" of the
caption "Results of Operations."

ENVIRONMENTAL QUALITY

            The Company is subject to regulation by federal,  state and, to some
extent,  local  authorities  with  respect to the  environmental  effects of its
operations, including regulations relating to air and water quality, aesthetics,
levels of noise,  hazardous wastes,  toxic substances,  protection of vegetation
and wildlife and  limitations on land use. In connection  with such  regulation,
certain  permits are required  with respect to the Company's  facilities,  which
permits have been obtained  and/or are in the renewal  process.  Generally,  the
principal  environmental  areas and requirements to which the Company is subject
are as follows:

            Air: State  regulations  affecting the Company's  existing  electric
generating  plants govern the sulfur content of fuel used therein,  the emission
of particulate matter and certain other pollutants  therefrom and the visibility
of such emissions. In addition,  federal and state ambient air quality standards
for sulfur dioxide ("SO2"),  nitrogen oxides ("NOx")and  suspended  particulates
must be complied with in the area surrounding the Company's  generating  plants.
Based on the operation of its continuous  emission stack monitoring  systems and
its ambient air quality  monitoring  system in the area  surrounding the Roseton
and Danskammer  Plants,  the Company believes that present air quality standards
for NOx, SO2 and particulates are satisfied in those areas.

            However,  beginning  in  1997  the  New  York  State  Department  of
Environmental  Conservation  ("NYSDEC"),  began an initiative  seeking penalties
from all New York electric  utilities  for past opacity  variances and requiring
various  opacity  reduction   measures  and  stipulated   penalties  for  future
excursions  after  execution of a consent  order.  Each New York State  electric
utility,  including  the  Company,  is in the  process  of  negotiating,  or has
negotiated,  the various terms and  conditions of a draft consent order with the
NYSDEC. The Company's  Danskammer Plant and the Roseton Plant are the subject of
these  negotiations.  The  outcome  of this  matter is  uncertain  at this time;
however,  the Company  believes that the amount of any civil penalty payment and
implementation of an opacity reduction  program,  in the aggregate,  will not be
material.

            The  Danskammer  Plant burns coal having a maximum sulfur content of
0.7%, fuel oil having a maximum sulfur content of 1%

                                      6


<PAGE>



and natural  gas. The sulfur  content of the oil burned at the Roseton  Plant is
limited  by  stipulation  with,  among  others,  the  NYSDEC,  to an amount  not
exceeding  1.5% maximum and 1.3% weighted  annual  average.  Such sulfur content
limitation  at the  Roseton  Plant can be modified by the NYSDEC in the event of
technological changes at such Plant, provided that the SO2 and NOx emissions are
limited to that which would have been  generated by the use of oil with a sulfur
content of 1.3% on a weighted annual average.  Natural gas is also burned at the
Roseton Plant.

            For more  information  on the impact of the Clean Air Act Amendments
of 1990 ("CAA  Amendments")  on the  Company's  efforts  to attain and  maintain
national  ambient air quality  standards  for emissions  from its  fossil-fueled
electric  power  plants,  the proposal of the federal  Environmental  Protection
Agency ("EPA") to modify emission standards for NOx and suspended  particulates,
and the proposal of the NYSDEC to modify NOx standards for generating facilities
operating in New York State, see Note 9 "Commitments and Contingencies,"  hereof
under the caption, "Environmental Matters - Clean Air Act Amendments."

            Except as set forth  above,  the  Company is unable to  predict  the
effect  (including  cost) of these programs on its power plant  operations since
the  details  of the CAA  Amendments  are yet to be  completely  established  by
implementing  regulations to be issued over a period of years by the EPA and the
NYSDEC.

          Water:  The Company is required  to comply with  applicable  state and
federal  laws  and  regulations  governing  the  discharge  of  pollutants  into
receiving waters.

            The  discharge  of  any  pollution  into   navigable   waterways  is
prohibited  except  in  compliance  with a permit  issued  by the EPA  under the
National Pollutant Discharge  Elimination System ("NPDES") established under the
Clean Water Act. Likewise,  under the New York  Environmental  Conservation Law,
industrial  waste  cannot  be  discharged  into  state  waters  without  a State
Pollutant  Discharge  Elimination  System ("SPDES") permit issued by the NYSDEC.
Issuance of a SPDES permit satisfies the NPDES permit requirement.

            The Company has received  SPDES  permits for both the Roseton  Plant
and  the  Danskammer  Plant,  its  Eltings  Corners  maintenance  and  warehouse
facility,  and its Rifton Recreation and Training Center.  The SPDES permits for
the Roseton and  Danskammer  Plants  expired on October 1 and  November 1, 1992,
respectively,  and such  permit  renewal  applications  are  pending  before the
NYSDEC.

            The Roseton  Plant  application  is  currently  being  reviewed in a
NYSDEC  proceeding.  The subject of the  restriction on use of water for cooling
purposes at that Plant (as referred

                                      7


<PAGE>



to in Item 3 hereof  under  the  caption  "Environmental  Litigation")  is being
considered in that proceeding.

            It is the Company's  belief that the expired SPDES permits  continue
in full force and effect pending issuance of the new SPDES permits.

            For further  discussion of the Company's  compliance  with the Clean
Water  Act and the  Company's  SPDES  permit  renewal  proceeding,  see Note 9 -
"Commitments and Contingencies," hereof under the caption "Environmental Matters
- Clean Water Act Compliance."

            Toxic  Substances  and Hazardous  Wastes:  The Company is subject to
state and federal laws and regulations  relating to the use, handling,  storage,
treatment,  transportation  and  disposal  of  industrial,  hazardous  and toxic
wastes.

            The  NYSDEC,  in  1986,  added  to the New York  State  Registry  of
Inactive  Hazardous Waste Disposal Sites ("Registry") six locations at which gas
manufacturing  plants owned or operated by the Company or by predecessors to the
Company  were once  located.  Two other  sites,  which  formerly  contained  gas
manufacturing  plants, have been identified by the Company.  The Company studied
these eight sites to determine  whether they contain any hazardous  wastes which
could pose a threat to the environment or public health and, if such wastes were
located  at  such  sites,  to  determine  the  remedial  actions  which  may  be
appropriate.

            All of these eight sites were  studied  using the Phase I guidelines
of the NYSDEC and five such sites were studied using the more extensive Phase II
guidelines of the NYSDEC.  As a result of these studies,  the Company  concluded
that no remedial  actions  were  required at any of these  sites.  In 1991,  the
NYSDEC advised the Company that four of the six sites had been deleted from such
Registry.  In 1992, the NYSDEC advised the Company that the two remaining  sites
listed on the  Registry  had been  deleted  from the  Registry.  The NYSDEC also
indicated  that such deletions of the sites were subject to  reconsideration  in
the future,  at which time new  analytical  tests may be  required to  determine
whether or not wastes on site are  hazardous.  If, as a result of such potential
new analytical tests, or otherwise,  remedial actions are ultimately required at
these sites by the NYSDEC, the cost thereof could have a material adverse effect
(the extent of which cannot be reasonably  estimated) on the financial condition
of the Company if the Company  could not recover all, or a  substantial  portion
thereof, through insurance and rates.

            For a discussion  of litigation  filed by the City of Newburgh,  New
York  against  the  Company   involving  one  of  the  Company's   eight  former
manufactured gas sites and a recent ruling

                                      8


<PAGE>



related thereto, see Note 9 - "Commitments and Contingencies,"  hereof under the
subcaption "Environmental Matters - Former Manufactured Gas Plant Facilities."

            In August  1992,  the NYSDEC  notified  the Company  that the NYSDEC
suspected that the Company's offices at Little Britain Road in New Windsor,  New
York, may constitute an inactive  hazardous  waste disposal site. As a result of
the  NYSDEC's  review of a site  assessment  report  prepared  by the  Company's
consultant  submitted  to the  NYSDEC in 1996,  the  Company  agreed to  perform
additional  testing,  which testing detected a limited amount of subsurface soil
contamination  near one corner of the site and  contaminants in the ground water
beneath  the site.  Operations  conducted  on the site by the  Company  since it
purchased  the property in 1978 are not believed to have  contributed  to either
the soil or the ground  water  contamination.  The  Company  and the NYSDEC have
reached an  agreement  in  principle  that the Company  will conduct a voluntary
clean-up of the site in terms to be further negotiated between the parties.  The
Company  can make no (i)  prediction  regarding  what action the NYSDEC may take
with regard to the  reports,  or (ii)  prediction  as to the outcome of recovery
attempts  against third parties by the Company.  However,  the Company  believes
that the cost of such  site  assessment  and  remediation,  if any,  will not be
material.

            Other:  The  Company's  expenditures  attributable,  in  whole or in
substantial part, to environmental  considerations totaled $8.7 million in 1998,
of which  approximately $.5 million related to capital projects and $8.2 million
were  charged  to  expense.  It is  estimated  that in 1999  the  total  of such
expenditures will be approximately $9.5 million.

            The Company is not involved as a defendant  in any court  litigation
with  respect to  environmental  matters and, to the best of its  knowledge,  no
litigation against it is threatened with respect thereto, except with respect to
the  litigation  described  in  Item 3  "Legal  Proceedings"  hereof  under  the
subcaption  "Environmental  Litigation - Newburgh Manufactured Gas Site," and as
described  in  Note  9 -  "Commitments  and  Contingencies,"  hereof  under  the
subcaption "Environmental Matters - Former Manufactured Gas Plant Facilities."

OTHER MATTERS

            Labor Relations:  The Company has agreements with the  International
Brotherhood  of Electrical  Workers  ("IBEW") for its 801  unionized  employees,
representing  production and maintenance  employees,  customer  representatives,
service  workers  and  clerical  employees  (excluding  persons  in  managerial,
professional  or supervisory  positions),  which  agreements  were  renegotiated
effective July 1, 1998. An agreement with Locals 2218 and 320

                                      9


<PAGE>



Non-Production  Plant Workers continues through April 30, 2003, and an agreement
with IBEW Local 320  Production  Plant Workers  expires on August 31, 2003.  The
agreements  provide  for an average  annual  general  wage  increase of 3.0% and
certain additional fringe benefits.

          AFFILIATES:

          CH  Energy  Group,  Inc.:  CH Energy  Group,  Inc.  is a  wholly-owned
subsidiary  of the Company  formed in April 1998.  Effective  upon a one-for-one
share  exchange  expected  to occur  during  the first  half of 1999,  a holding
company restructuring will be effected so that CH Energy Group, Inc. will become
the holding company parent  corporation of the Company and its then wholly-owned
subsidiaries  (with  the  exception  of  Phoenix  Development   Company,   Inc.)
identified below.

          For further information  regarding the holding company  restructuring,
see Item 7 hereof under the  captions  "Competition/Deregulation  -  Competitive
Opportunities Proceeding Settlement Agreement" and Note 2 - "Regulatory Matters"
hereof  under the  captions  "Competitive  Opportunities  Proceeding  Settlement
Agreement" and "Holding Company Restructuring."

          Central Hudson  Enterprises  Corporation:  Central Hudson  Enterprises
Corporation  ("CHEC") is engaged in the business of marketing electric,  gas and
oil  related  services  to retail and  wholesale  customers,  conducting  energy
audits; providing services including, but not limited to, the design, financing,
installation  and  maintenance  of energy  conservation  measures and generation
systems for private  businesses,  institutional  organizations  and governmental
entities;  and  participating in cogeneration,  small hydro,  alternate fuel and
energy production  projects and services.  During 1998, CHEC formed Scasco, Inc.
("SCASCO"),  a Connecticut corporation,  as CHEC's wholly-owned  subsidiary.  In
August  1998,  SCASCO  purchased  the assets of a fuel oil  business  located in
Connecticut,  for the purpose of expanding  the customer base of CHEC and SCASCO
and providing additional  energy-based services. This expansion continued during
February 1999, when SCASCO purchased Island Sound Commercial Energy Sales, Inc.,
a business which holds contracts to sell natural gas to customers in Connecticut
and Rhode Island, to be SCASCO's wholly-owned subsidiary.

          CH Resources, Inc.: CH Resources, Inc. is a wholly-owned subsidiary of
the Company established to hold real property for generating electricity and for
other uses of the  Company,  directly or  indirectly  through one or more of its
affiliates.  In December  1998,  CH  Resources  acquired  an 80 megawatt  ("MW")
combined cycle gas turbine facility in Solvay,  New York and in December,  1998,
it acquired an 80 MW combined  cycle gas turbine  facility in Beaver Falls,  New
York.

                                      10


<PAGE>



          CH Syracuse  Properties,  Inc.: In December  1998, CH Resources,  Inc.
established  CH Syracuse  Properties,  Inc.,  a  wholly-owned  subsidiary  of CH
Resources, Inc., to lease real property.

          Phoenix  Development  Company,  Inc.,  and  Greene  Point  Development
Corporation:  These corporations,  are wholly-owned subsidiaries of the Company,
established to hold or lease real property for the future use of the Company, or
to participate in energy-related  ventures.  Currently, the assets held by these
subsidiaries are not material.

EXECUTIVE OFFICERS OF THE COMPANY

            The names of the current  officers of the Board of Directors and the
executive officers of the Company,  their positions held and business experience
during the past five (5) years and ages (at December 31, 1998) are as follows:

                                         Principal Occupation or
                                         Employment and Positions
Name of Officer, Age                   and Offices with the Company
 and Position Held                    During the Past Five (5) Years
--------------------                  ------------------------------

                             Officers of the Board
                             ---------------------

John E. Mack III,  64,                Present  positions,  except  Chairman
  Chairman of the Board;              of the Board since August 1,
  Chairman of the                     1998;  Chairman  of  the  Board  and
  Executive, Retirement               Chief  Executive  Officer,  December
  and Finance Committees              1993-July 31, 1998; Chairman of
                                      the Committee on Finance, April
                                      1996

Jack Effron, 65,                      Present position since April 1994;
  Chairman of Committee               President of EFCO Products, a
  on Compensation and                 bakery ingredients corporation;
  Succession                          member of the St. Francis Health
                                      Care Foundation; Chairman of the
                                      Chief Executive's Network for
                                      Manufacturing of the Council of
                                      Industry of Southeastern New York

Heinz K. Fridrich, 65,                Present position since April 1995;
  Chairman of the                     Courtesy Professor, University of
  Committee on Audit                  Florida at Gainsville since 1994;
                                      Board of Trustees, Mount St. Mary
                                      College

                                      11


<PAGE>



                                         Principal Occupation or
                                         Employment and Positions
Name of Officer, Age                   and Offices with the Company
 And Position Held                    During the Past Five (5) Years
--------------------                  ------------------------------

                       Executive Officers of the Company
                       ---------------------------------

Paul J. Ganci, 60,                    Present position since August 1,
  President and Chief                 1998; President and Chief Oper-
  Executive Officer                   ating Officer, December 1993-
                                      July 31, 1998

Carl E. Meyer, 51,                    Present position since April 1998;
  Executive Vice                      Senior Vice President - Customer
  President - Operations              Services, April 1996-April 1998;
                                      Vice President - Customer
                                      Services, December 1993-April 1996

Allan R. Page, 51,                    Present position since April 1998;
  Executive Vice                      Senior Vice President - Corporate
  President - Energy                  Services, April 1996-April 1998;
  Resources & Development             Vice President - Corporate
                                      Services, December 1993-April 1996

Ronald P. Brand, 60,                  Present position since November
  Senior Vice President -             1998; Vice President - Engineering
  Engineering,                        and Environmental Affairs,
  Environmental Affairs &             December 1993-November 1998
  Special Projects

Joseph J. DeVirgilio, Jr.,            Present position since November
  47, Senior Vice                     1998; Vice President - Human
  President - Corporate               Resources and Administration,
  Services and                        December 1993-November 1998
  Administration

Arthur R. Upright, 55,                Present position since November
  Senior Vice President -             1998; Assistant Vice President -
  Regulatory Affairs,                 Cost & Rate and Financial Plan-
  Financial Planning and              ning, February 1994-November 1998;
  Accounting                          Manager, Cost & Rate and Financial
                                      Planning, December 1993-February
                                      1994

James P. Lovette, 49,                 Present position since November
  Vice President - Fossil             1998; Assistant Vice President -
  Production                          Fossil Production, October 1997-
                                      November 1998; Plant Superinten-
                                      dent, December 1993-November 1997

                                      12


<PAGE>



                                         Principal Occupation or
                                         Employment and Positions
Name of Officer, Age                   and Offices with the Company
 and Position Held                    During the Past Five (5) Years
--------------------                  ------------------------------

                Executive Officers of the Company - (Continued)
                -----------------------------------------------

Steven V. Lant, 41,                 Present position since November
  Chief Financial Officer,          1998; Treasurer and Assistant
  Treasurer and Corporate           Secretary, December 1993-November
  Secretary                         1998

Donna S. Doyle, 50,                 Present position since April 1995;
  Controller                        Assistant Controller, April 1994-
                                    April 1995; Manager of Taxes
                                    Budgets & Customer Acctg.,
                                    December 1993-April 1995

Gladys  L.  Cooper,  47,            Present  positions  since  September
  Assistant  Vice  President        1995;  leave of absence  for
  -  Governmental Relations         educational purposes, December
                                    1993-September 1995; Corporate
                                    Secretary, December 1993-April
                                    1994

John C. Checklick, 50,              Present position since November
  Assistant Vice President -        1998; Manager of Customer
  Customer Services                 Services, December 1993-November
                                    1998

          There are no family relationships  existing among any of the executive
officers of the Company.

          Each of the above executive  officers is elected or appointed annually
by the Board of Directors.

     ITEM 2 - PROPERTIES
     -------------------

ELECTRIC

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

                                      13


<PAGE>

<TABLE>


<CAPTION>
                                                                                (MW)*
Electric                                                                        Net Capability                1998 Unit
Generating                                               Year Placed                (97-98)                   Net Output
Plant                      Type of Fuel                  in Service           Summer       Winter                (Mwh)
----------                 ------------                  ----------           ------       ------             ----------

<S>                        <C>                           <C>                 <C>          <C>                 <C>
Danskammer                 Residual Oil, Natural         1951-1967              492          502              2,721,238
Plant **                   Gas and Coal

Roseton Plant              Residual Oil                  1974                   425          404              1,320,329
(35% share)**              and Natural Gas

Neversink                  Water                         1953                    23           22                 64,232
Hydro Station

Dashville                  Water                         1920                     5            5                 13,995
Hydro Station

Sturgeon Pool              Water                         1924                    16           16                 58,229
Hydro Station

High Falls                 Water                         1986                     3            4                  7,701
Hydro Station

Coxsackie Gas              Kerosene or                   1969                    19           24                  2,554
Turbine ("GT")             Natural Gas

So. Cairo GT               Kerosene                      1970                    19           21                  1,532

Nine Mile 2                Nuclear                       1988
Plant (9% share)                                                               103          104                 653,322
                                                                             -----        -----               ---------
                          Total                                              1,105        1,102               4,843,132
                                                                             =====        =====               =========
</TABLE>

*   Reflects  maximum  one-hour net  capability  of the  Company's  ownership of
    generation  resources  and,  therefore,  does not include firm  purchases or
    sales.
**  Plants  subject to auction  based on the  Agreement  as  described in Item 7
    hereof   under   the   caption   "Competition/Deregulation   -   Competitive
    Opportunities  Proceeding  Settlement Agreement" and in Note 2 - "Regulatory
    Matters"  hereof  under the caption  "Competitive  Opportunities  Proceeding
    Settlement Agreement."

                                      14


<PAGE>



            The Company has a contract with the Power  Authority of the State of
New York ("PASNY")  which entitles the Company to 49 MW net capability  from the
Blenheim-Gilboa Pumped Storage Hydroelectric Plant through 2002.

            See Item 1 hereof, under the caption "Regulation" and the subcaption
"Purchased  Electric Power  Generation,"  with respect to  alternative  electric
power generation interconnected with the Company's system.

            The Company  owns 83  substations  having an  aggregate  transformer
capacity of 4.5 million kVa. The transmission  system consists of 588 pole miles
of line and the  distribution  system of 7,277 pole miles of overhead  lines and
860 trench miles of underground lines.

            Load and Capacity:  The Company's maximum one-hour demand within its
own territory,  for the year ended December 31, 1998, occurred on July 22, 1998,
and amounted to 900 MW. The  Company's  maximum  one-hour  demand within its own
territory,  for that part of the 1998-1999  winter  capability  period,  through
February 18, 1999, occurred on January 14, 1999 and amounted to 825 MW.

            Based on current  projections of peak one-hour  demands for the 1999
summer  capability  period,  the Company  estimates  that it will have  capacity
available to satisfy its  projected  peak demands plus the  estimated  installed
reserve generating  capacity  requirements which it is required to maintain as a
member of the New York Power Pool ("NYPP"), described herein.

            The Company plans to divest its Roseton and Danskammer  Plants under
the terms of the  Agreement.  This  divestiture  is likely to occur between late
1999 and mid-2001.

            For further information  regarding the Agreement,  see Item 7 hereof
under the caption  "Competition/Deregulation"  and Note 2 - "Regulatory Matters"
hereof.  Following such  divestiture,  the Company will no longer own sufficient
capacity  to  serve  the  peak  demands  of its  transmission  and  distribution
customers and may need to rely on purchased  capacity from third party providers
to meet such demands not satisfied.

            See the caption "New York Power  Pool/Independent  System Operator,"
of this Item for further  information  regarding the termination of the NYPP and
the  formation  of  the  Independent   System  Operator  ("ISO")  to  coordinate
reliability and transmission of New York State's bulk power systems.

                                      15


<PAGE>



The following  table sets forth the amounts of any excess capacity by summer and
winter capability periods for 1999 and 2000:
<TABLE>
<CAPTION>

                          Forecasted          Forecasted
                            Peak -              Peak -             Peak Plus                                Excess of Capacity
                            Total                Full              Installed                                over Peak Plus NYPP
                           Delivery            Service            Reserve of           Available            Installed Reserve
  Capability              Rqts. (MW)          Rqts. Only           18% (MW)             Capacity              Requirements
    Period                   (1)                 (2)                  (3)                 (MW)              (MW)(3)  Percent(3)
  ----------              ----------          ----------           --------             --------            -------  ----------
<S>                          <C>                 <C>                 <C>                  <C>                  <C>      <C>
1999      Summer             910                 860                 1,015                1,149                134      13.2
1999-2000 Winter             845                 800                 1,015*               1,169                134      15.2

</TABLE>

*    Summer  period peak plus reserve  requirements  carry over to the following
     winter period.

(1)  Total  delivery  requirements  include  requirements  for both full service
     (delivery and energy) and retail access (delivery only) customers

(2)  Excludes  retail  access  customer  requirements  (3) Based on full service
     requirements

                                      16


<PAGE>



          Roseton Plant: The Roseton Plant is located in the Company's franchise
area at Roseton,  New York,  and is owned by the  Company,  Consolidated  Edison
Company of New York,  Inc. ("Con  Edison") and Niagara Mohawk Power  Corporation
("Niagara Mohawk") as tenants-in-common. The Roseton Plant, placed in commercial
operation in 1974,  has a generating  capacity of 1,200 MW consisting of two 600
MW generating units, both of which are capable of being fired either by residual
oil or natural gas (see  subcaption  below entitled "Gas - Sufficiency of Supply
and  Future Gas  Supply").  The  Company is acting as agent for the owners  with
respect to operation of the Roseton Plant. Generally, the owners share the costs
and expenses of the operation of such Plant in accordance with their  respective
ownership interests.

          The Company,  under a 1968  agreement,  has the option to purchase the
interests of Niagara  Mohawk (25%) and of Con Edison (40%) in the Roseton  Plant
in  December  2004.  The  exercise  of this  option is subject to PSC  approval.
However,  by  agreement  dated  March 30,  1994  between the Company and Niagara
Mohawk,  Niagara Mohawk was given,  among other things,  an option to retain its
25% interest in the Roseton Plant,  provided that Niagara Mohawk  exercises such
option by May 31, 1999.

            As part of Niagara  Mohawk's  restructuring  plan,  the PSC,  in May
1998,  authorized  Niagara Mohawk to divest its fossil- fueled and hydroelectric
generating  assets by auction by mid- 1999,  except  that the auction of Niagara
Mohawk's interest in the Roseton Plant was permitted by the PSC to be delayed to
be coordinated  with the Company's  auction of that Plant. Con Edison has agreed
to divest and transfer certain of its electric  generating assets (including its
interest in the Roseton Plant) to unregulated entities,  including third parties
and Con Edison affiliates,  by the end of 2002. The Company,  Niagara Mohawk and
Con Edison adopted Principles of Agreement on October 7, 1998, concluding that a
joint  auction of the Roseton Plant will  maximize  proceeds from the sale,  and
that the  cotenants  intend to enter into an agreement  whereby the Company will
conduct the auction  sale on behalf of the  cotenants in  coordination  with the
auction of the Company's adjacent Danskammer Plant, which Agreement was accepted
by the PSC by order  issued and  effective  December 18,  1998.  For  additional
information  with respect to the  Company's  obligation  to divest itself of its
interest in the  Roseton  and  Danskammer  Plants,  see Item 7 hereof  under the
caption   "Competition/Deregulation   -  Competitive   Opportunities  Proceeding
Settlement  Agreement"  and Note 2 -  "Regulatory  Matters,"  under the  caption
"Competitive Opportunities Settlement Agreement."

            The 345 kV transmission  lines and related facilities to connect the
Roseton  Plant  with  other  points in the  system of the  Company  and with the
systems of Con Edison and Niagara Mohawk to the north and west of such Plant are
100%-owned by the Company.

                                      17


<PAGE>



The  share  of each  of the  parties  in the  output  of the  Roseton  Plant  is
transmitted  over  these  lines  pursuant  to a certain  transmission  agreement
relating to such Plant, which provides,  among other things, for compensation to
the  Company for such use by the other  parties.  In  addition,  the Company has
contract  rights  which  entitle  the  Company  to the  lesser of 300 MW, or one
quarter of the  capacity  in a 345 kV  transmission  line owned by PASNY,  which
connects  the  Roseton  Plant with a Con Edison  substation  to the east of such
Plant in East  Fishkill,  New York.  In exchange for these  rights,  the Company
agreed to provide PASNY  capacity in the 345 kV  transmission  lines the Company
owns from the Roseton  Plant,  to the extent it can do so after  satisfying  its
obligations to Con Edison and Niagara Mohawk.

            Nine  Mile 2 Plant:  For a  discussion  of the  Company's  ownership
interest in, costs for, and certain  operating matters relating to the Nine Mile
2 Plant, see Item 7 hereof under the subcaption  "Nuclear  Operations," Note 3 -
"Nine Mile 2 Plant," and Note 1 - "Summary of Significant  Accounting Policies,"
under the subcaption "Jointly-Owned Facilities."

NEW YORK POWER POOL/INDEPENDENT SYSTEM OPERATOR

            The  Company  is a  member  of the  NYPP  consisting  of  the  major
investor-owned  electric  utility  companies in the State,  Long Island Lighting
Company ("LILCO"), a subsidiary of the Long Island Power Authority ("LIPA"), and
PASNY. The members of the NYPP, by agreement,  provide for coordinated operation
of their bulk  power  electric  systems  with the  objectives  of using the most
economical source of electricity,  for the maintenance of a reserve margin equal
to at  least  18% of each  member's  forecasted  peak  load and for the sale and
interchange of electric generating capability and energy among such members. The
members of the NYPP also provide for the  cooperative  development of long-range
plans for the expansion on an  integrated  basis of the bulk power supply system
for New York State, compatible with environmental  standards,  and appropriately
related to interstate and international capacity and reliability considerations.

            As part of the ongoing  discussions  regarding the  restructuring of
the electric  industry in New York State  referred to in Item 7 hereof under the
caption  "Competition/Deregulation,"  proposals  have been made to terminate the
NYPP and establish the following: In a filing with FERC, dated January 31, 1997,
the member systems of the NYPP proposed a new market  structure that included as
its key elements  the  establishment  of an ISO, the New York State  Reliability
Council ("NYSRC"),  and the New York Power Exchange ("NYPE"). The ISO, NYSRC and
NYPE will collectively replace the NYPP.

                                      18


<PAGE>



            By order dated June 30,  1998,  FERC  conditionally  authorized  the
establishment of the ISO and, by order dated January 27, 1999 FERC conditionally
accepted,  with  modifications,  the proposed ISO tariff and the proposed market
rules of the ISO and granted the request for market-based rates. The January 27,
1999,  order calls for public  hearings on certain aspects of the proposed rates
and provides for settlement judge proceedings.  Future filings with FERC will be
required to obtain FERC  approval  of the  transfer of control of all  necessary
facilities  to the ISO;  any such  transfer  would not involve  the  transfer of
ownership of such assets.

            The ISO's  principal  mission will be to maintain the reliability of
the New York State bulk power systems and to provide  transmission  service on a
comparable  and  non-discriminatory  basis.  The ISO  will  be  open to  buyers,
sellers,  consumers,  and transmission providers;  each of these groups would be
represented  on the Board of  Directors  of the ISO,  which is  proposed to be a
not-for-profit New York corporation.  The NYSRC's mission will be to promote and
preserve the reliability of the bulk power system within New York State, through
its primary  responsibility  for the promulgation of reliability  rules; the ISO
will  develop  the  procedures  necessary  to operate  the system  within  these
reliability  rules.  The NYSRC is to be  governed by a  committee  comprised  of
transmission providers and representatives of buyers,  sellers, and consumer and
environmental  groups.  The NYPE will provide a vehicle through which buyers and
sellers  can  participate  in the markets for  energy,  capacity  and  ancillary
services.  For more  information  on the ISO,  see caption  "Independent  System
Operator" in Note 2 "Regulatory Matters" hereof.

GAS

          General:   The  Company's   gas  system   consists  of  161  miles  of
transmission pipelines and 986 miles of distribution pipelines.

            During 1998,  natural gas was  available to firm gas  customers at a
price competitive with that of alternative  fuels. As compared to 1997, in 1998,
firm retail gas sales,  normalized for weather,  decreased by 1% and the average
number of firm gas  customers  increased  by 1% or 633.  Sales to  interruptible
customers  decreased  22% in 1998 as compared to 1997.  As compared to 1997,  in
1998, firm retail  transportation  sales,  normalized for weather,  increased by
983% due to the average  number of  customers  using firm retail  transportation
service increasing to 31 customers.  In total, as compared with 1997 normalized,
firm gas sendout increased by 1% in 1998.

                                      19


<PAGE>



            For  further   information   regarding   the   Company's   incentive
arrangements for interruptible gas sales, see Item 7 hereof under the subcaption
"Interruptible Gas Sales."

            For the year  ended  December  31,  1998,  the  total  amount of gas
purchased  from all sources was 16,962,360  million cubic feet  ("Mcf."),  which
includes 369,067 Mcf. purchased directly for use as a boiler fuel at the Roseton
Plant.

            The  Company  also  owns  two  propane-air   mixing  facilities  for
emergency and peak shaving purposes located in Poughkeepsie and in Newburgh, New
York.  Each  facility is capable of  supplying  8,000 Mcf.  per day with propane
storage capability  adequate to provide maximum facility sendout for up to three
consecutive days.

            Sufficiency  of Supply and Future Gas Supply:  The peak daily demand
for natural gas by the Company's customers for the year ended December 31, 1998,
occurred on December  30,  1998,  and  amounted  to 91,070  Mcf.  The  Company's
peak-day  gas  capability  in 1998 was 116,865  Mcf.  The peak daily  demand for
natural gas by the Company's  customers  for that part of the 1998-1999  heating
season through February 18, 1999,  occurred on January 14, 1999, and amounted to
109,676 Mcf.

            Other:  FERC  permits  non-discriminatory  access  to  the  pipeline
facilities  of interstate  gas pipeline  transmission  companies  subject to the
jurisdiction  of FERC under the Natural Gas Act. This rule allows access to such
pipelines by the pipeline  transmission  company's  customers  enabling  them to
transport  gas purchased  directly  from third parties and spot sources  through
such  pipelines.   Such  access  also  permits   industrial   customers  of  gas
distribution  utilities  to  connect  directly  with the  pipeline  transmission
company and to contract  directly  with the pipeline  transmission  companies to
transport  gas,  thereby  by-passing  the  distribution  utility.  None  of  the
Company's customers have elected this by-pass option.

            The PSC has authorized New York State  distribution gas utilities to
transport  customer-owned  gas  through  their  facilities  upon  request  of  a
customer.  Currently,  interstate pipeline transmission companies are located in
certain  areas  where the  Company  provides  retail gas  service  (the Towns of
Carmel, Pleasant Valley, Coxsackie, and LaGrange in New York State).

            For a discussion of the PSC proceeding relating to issues associated
with the  restructuring  of the natural gas market,  see Item 7 hereof under the
subcaption  "Natural Gas - PSC  Restructuring  Policy  Statement" of the caption
"Competition/ Deregulation."

                                      20


<PAGE>



OTHER MATTERS

            The  Danskammer  Plant  and the  Roseton  Plant and all of the other
principal generating plants and important property units of the Company are held
by it in fee simple, except (1) certain rights-of-way,  and (2) a portion of the
property  used in  connection  with  the  hydroelectric  plants  of the  Company
consisting of flowage or other riparian rights.  The Company's present interests
in the Roseton Plant and the Nine Mile 2 Plant are owned as undivided  interests
as a  tenant-in-common  with the other utility  owners  thereof.  Certain of the
properties of the Company are subject to  rights-of-way  and easements  which do
not interfere with the Company's operations. In the case of certain distribution
lines,  the Company owns only a part  interest in the poles upon which its wires
are  installed,  the  remaining  interest  being owned by  telephone  companies.
Certain electric transmission facilities owned by others are used by the Company
pursuant to long-term contractual arrangements.

            All of the physical  properties of the Company,  other than property
such as material and supplies  excluded in the  Company's  First  Mortgage  Bond
Indenture  ("Mortgage")  and its  franchises,  are  subject  to the  lien of the
Mortgage under which all of its Mortgage Bonds are outstanding.  Such properties
are from time to time subject to liens for current taxes and  assessments  which
the Company pays regularly as and when due.

            During the  three-year  period ended  December 31, 1998, the Company
made gross  property  additions of $139.4 million and property  retirements  and
adjustments   of  $32.5  million,   resulting  in  a  net  increase   (including
Construction Work in Progress) in utility plant of $106.9 million, or 7.4%.

      ITEM 3 - LEGAL PROCEEDINGS
      --------------------------

ASBESTOS LITIGATION

            For  a  discussion  of  litigation  against  the  Company  involving
asbestos, see Note 9 - "Commitments and Contingencies," hereof under the caption
"Asbestos Litigation."

ENVIRONMENTAL LITIGATION

            Roseton  Plant:  On March 23, 1992, in an action  brought in 1991 by
the Natural  Resources  Defense  Council,  Inc.,  the Hudson  River  Fisherman's
Association and Scenic Hudson, Inc., a Consent Order was approved by the Supreme
Court of the State of New York, Albany County.

                                      21


<PAGE>



            Such Consent Order provides for certain  operating  restrictions  at
the Roseton Plant relating to the use of river water for plant cooling purposes,
which restrictions have not, and are not expected to impose material  additional
costs on the Company.  The Consent Order was extended until February 1, 1998, by
agreement of the parties and Court approval. The Consent Order has since lapsed;
however,  both parties continue to consider themselves bound by its terms. For a
description of the pending NYSDEC proceeding  involving the renewal of the SPDES
permit  for  the  Roseton  Plant,   see  Item  1  hereof  under  the  subcaption
"Environmental  Quality - Water," and Note 9  "Commitments  and  Contingencies,"
under the caption  "Environmental  Matters - Clean Water Act  Compliance." For a
description of the Company's negotiations with the NYSDEC on a consent order for
alleged   opacity   violations,   see  Item  1  hereof   under  the   subcaption
"Environmental Quality - Air."

            Newburgh Manufactured Gas Site: For a discussion of litigation filed
against the Company by the City of Newburgh,  New York,  on May 26, 1995, in the
United States District Court,  Southern  District of New York, and the Company's
response  thereto,  see Note 9 -  "Commitments  and  Contingencies,"  under  the
subcaption "Environmental Matters - Former Manufactured Gas Plant Facilities."

CATSKILL INCIDENT

            An  explosion  occurred in a dwelling in the  Company's  gas service
territory in Catskill,  New York in  November,  1992 which  resulted in personal
injuries,  the death of an occupant  and  property  damage.  Lawsuits  have been
commenced  against  the  Company  arising out of such  incident,  including  the
following which could be material to the Company:

            By complaint, dated February 2, 1994, Carl Fatzinger, as executor of
the estate of Mildred Fatzinger,  and Virginia Fatzinger  commenced an action in
the Supreme Court of the State of New York,  Greene County,  against the Company
and two  other  defendants.  The  complaint  sought  an  unspecified  amount  of
compensatory  and punitive  damages  based on theories of  negligence,  absolute
liability  and gross  negligence  for the death of Mildred  Fatzinger,  personal
injuries to Virginia  Fatzinger and property  damage alleged to have been caused
by said explosion.

            By complaint, dated October 18, 1993, and filed in the Supreme Court
of the State of New York, Greene County, Frank Reyes commenced an action against
the Company for  unspecified  personal  injuries and property  damage alleged to
have  been  caused  by  said  explosion.  The  complaint  seeks  $2  million  in
compensatory damages and $2 million in punitive damages from the Company,  based
on theories of negligence and gross negligence.

                                      22


<PAGE>



            The Fatzinger  lawsuit was settled by the Company in January 1999 in
an  amount  that is not  material  to the  Company.  With  regard  to the  Reyes
litigation,  the Company believes that it has adequate  insurance with regard to
the claims for compensatory damages. The Company's insurance,  however, does not
extend to punitive damages.  If punitive damages were ultimately  awarded in the
Reyes lawsuit,  such award could have a material adverse effect on the financial
condition of the Company. At this time, the Company can make no prediction as to
any other litigation which may arise out of this incident.

WAPPINGERS FALLS INCIDENT

            Two consecutive fires and explosions  occurred on February 12, 1994,
destroying a residence and commercial establishment in the Village of Wappingers
Falls,  New  York,  in the  Company's  service  territory.  Lawsuits  have  been
commenced  against  the  Company  arising out of such  incident,  including  the
following:

            On August  31,  1994,  the  Company  was served  with a summons  and
complaint  in an action  brought by John  DeLorenzo  against the Company and the
Village  of  Wappingers  Falls in the  Supreme  Court of the  State of New York,
County of Dutchess. The complaint seeks unspecified amounts of damages, based on
a theory of  negligence,  for personal  injuries and property  damage alleged to
have been caused by the incident.

            On  March 9,  1995,  the  Company  was  served  with a  summons  and
complaint  in an action  brought by Cengiz  Ceng,  individually  and as executor
under the last will and  testament of  Nizamettin  Ceng,  and Tarkan Thomas Ceng
against the Company and the Village of Wappingers  Falls in the Supreme Court of
the State of New York,  County of  Dutchess.  The  complaint  seeks  recovery of
$250,000  from the  Company,  based on the theory of  negligence,  for  property
damages alleged to have been caused by the incident.

            The above  lawsuits have been  consolidated  into one action against
the Company; however, no trial date has been set.

            The Company  continues to investigate these claims and presently has
insufficient information on which to predict their outcome. The Company believes
that it has  adequate  insurance  with  regard to the  claims  for  compensatory
damages;  however,  the Company's insurance does not extend to punitive damages.
If punitive  damages were ultimately  awarded,  in any of these  lawsuits,  such
award(s) could have a material adverse effect on the financial  condition of the
Company.  At this  time,  the  Company  can make no  prediction  as to any other
litigation which may arise out of this incident.

                                      23


<PAGE>



      ITEM 4 -  SUBMISSION OF MATTERS TO A VOTE OF SECURITY
                HOLDERS
      -----------------------------------------------------

            No matter was  submitted  to a vote of security  holders  during the
fourth quarter of the Company's fiscal year covered by this Report.

                                    PART II
                                    -------

      ITEM 5 -  MARKET FOR THE COMPANY'S COMMON EQUITY AND
                RELATED STOCKHOLDER MATTERS
      ----------------------------------------------------

            For information  regarding the market for the Company's common stock
and related stockholder  matters,  see Item 7 hereof under the captions "Capital
Resources & Liquidity - Financing Program" and "Common Stock Dividends and Price
Ranges" and Note 6 - "Capitalization - Capital Stock."

            Pursuant   to   applicable   statutes   and   its   Certificate   of
Incorporation,  the Company may pay  dividends on shares of Preferred and Common
Stock only out of surplus.

            For  information on the Company's  program to repurchase some of its
issued and outstanding  common stock pursuant to a program  approved by the PSC,
see Item 7 hereof under the subcaption "Financing Program."

                                      24


<PAGE>



      ITEM 6 - SELECTED FINANCIAL DATA
      --------------------------------

FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA*
(In Thousands)
<TABLE>
<CAPTION>

                                                            1998           1997            1996               1995          1994
                                                            ----           ----            ----               ----          ----
<S>                                                      <C>           <C>             <C>               <C>           <C>          
Operating Revenues
  Electric........................................       $ 418,507     $ 416,429       $  418,761        $  409,445    $  411,082
  Gas.............................................          84,962       103,848           95,210           102,770       104,586
                                                         ---------     ---------        ---------         ---------     ---------
    Total.........................................         503,469       520,277          513,971           512,215       515,668
                                                         ---------     ---------        ---------         ---------     ---------

Operating Expenses

  Operations......................................         266,472      284,714           267,779           274,665       274,497
  Maintenance.....................................          26,904       27,574            28,938            29,440        32,716
  Depreciation and amortization...................          45,560       43,864            42,580            41,467        40,380
  Taxes, other than income tax....................          63,458       64,879            66,145            66,709        66,899
  Federal income tax..............................          29,775       29,190            32,700            29,040        28,043
                                                         ---------     --------         ---------         ---------     ---------
    Total.........................................         432,169      450,221           438,142           441,321       442,535
                                                         ---------     --------         ---------         ---------     ---------

Operating Income..................................          71,300       70,056            75,829            70,894        73,133
                                                         ---------     --------         ---------         ---------     ---------

Other Income
  Allowance for equity funds
   used during construction.......................             585          387               466               986           866
  Federal income tax..............................           1,148        2,953             1,632               353         1,237
  Other - net.....................................           6,865        8,079             4,815             8,886         6,296
                                                         ---------     --------         ---------         ---------     ---------
    Total.........................................           8,598       11,419             6,913            10,225         8,399
                                                         ---------     --------         ---------         ---------     ---------

Income before Interest Charges....................          79,898       81,475            82,742            81,119        81,532

Interest Charges..................................          27,354       26,389            26,660            28,397        30,603
                                                         ---------     --------         ---------         ---------     ---------
</TABLE>




                                      25


<PAGE>


<TABLE>

FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA* (CONT'D)
(In Thousands)
<CAPTION>

                                                                1998          1997           1996               1995          1994
                                                                ----          ----           ----               ----          ----
<S>                                                        <C>           <C>             <C>               <C>           <C>
Net Income........................................             52,544        55,086          56,082            52,722        50,929
Premium on Preferred Stock Redemption-Net.........               -             -                378               169          -
Dividends Declared on Cumulative Preferred Stock..              3,230         3,230           3,230             4,903         5,127
                                                            ---------     ---------       ---------         ---------     ---------
Income Available for Common Stock.................             49,314        51,856          52,474            47,650        45,802

Dividends Declared on Common Stock................             36,567        37,137          37,128            36,459        35,541
                                                            ---------     ---------       ---------         ---------     ---------
Amount Retained in the Business...................             12,747        14,719          15,346            11,191        10,261
Retained Earnings - beginning of year.............            120,540       105,821          90,475            79,284        69,023
                                                            ---------     ---------       ---------         ---------     ---------
Retained Earnings - end of year...................         $  133,287    $  120,540      $  105,821        $   90,475    $   79,284
                                                            =========     =========       =========         =========     =========

Common Stock
  Average shares outstanding (000s)...............             17,034        17,435          17,549            17,380        17,102
  Earnings per share on
   average shares outstanding.....................              $2.90         $2.97           $2.99             $2.74         $2.68
  Dividends declared per share....................             $2.155        $2.135          $2.115            $2.095        $2.075
  Book value per share (at year-end)..............             $28.00        $27.61          $26.87            $25.96        $25.34

Total Assets......................................         $1,316,038    $1,252,090      $1,249,106        $1,250,092    $1,250,781
Long-term Debt....................................            356,918       361,829         362,040           389,245       389,364
Cumulative Preferred Stock........................             56,030        56,030          56,030            69,030        81,030
Common Equity.....................................            472,180       477,104         471,709           454,239       436,731

* This summary should be read in  conjunction  with the  Consolidated  Financial
  Statements and Notes thereto included in Item 8 of this Form 10-K Report.
</TABLE>

                                      26


<PAGE>



      ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF
               FINANCIAL CONDITION AND RESULTS OF OPERATIONS
      ------------------------------------------------------

COMPETITION/DEREGULATION

GENERAL

            The Company  remains  subject to regulation  for retail rates by the
PSC   and   wholesale   rates   by  the   FERC.   However,   as  a   result   of
competition/deregulation  initiatives  and policy  changes  instituted  by these
agencies, the Company is experiencing increased electric and gas competition.

COMPETITIVE OPPORTUNITIES PROCEEDING SETTLEMENT AGREEMENT

            For a discussion of the Company's Agreement,  approved by the PSC in
its Competitive Opportunities Proceeding,  and a discussion of the impact of the
Agreement on the Company's  Accounting  Policies,  see the caption  "Competitive
Opportunities Proceeding Settlement Agreement" in Note 2 "Regulatory Matters"
hereof.

FORMATION OF HOLDING COMPANY

            For  information  with  respect to the  Company's  proposed  holding
company restructuring see the caption "Holding Company  Restructuring" in Note 2
- "Regulatory Matters" hereof.

FERC - ELECTRIC

            On  April  24,  1996,  the FERC  released  Order  Nos.  888 and 889,
promoting  wholesale  competition  between  public  utilities by providing  open
access,  non-discriminatory transmission services. The Orders have the effect of
(i) requiring  electric  utilities to open their transmission lines to wholesale
competitors, while allowing recovery of certain "stranded costs," (ii) requiring
electric  utilities to establish  electronic  systems to share information about
available  transmission  capacity,  subject to certain standards of conduct, and
(iii)  requiring  certain  functional  separation of power  marketing from other
operations.  The Company duly filed its open access transmission tariff ("OATT")
with FERC, as required by Order No. 888, which tariff has been approved by FERC.
Under the OATT,  the  Company  must  offer  transmission  service  to  wholesale
customers on a basis that is  comparable to that which it provides  itself.  The
Company is also  required to offer and/or  provide  certain  ancillary  services
which contribute to the reliability and security of the transmission system. For
information  with  respect to filings  with the FERC to  terminate  the NYPP and
establish an ISO, see the caption

                                      27


<PAGE>



"Independent System Operator" in Note 2 - "Regulatory Matters" hereof.

NATURAL GAS-PSC RESTRUCTURING POLICY STATEMENT

            On November 3, 1998, the PSC, by Order, issued its "Policy Statement
Concerning  the Future of the Natural  Gas  Industry in New York State and Order
Terminating  Capacity Assignment" which sets forth the PSC's view of how best to
ensure a  competitive  market  for  natural  gas in New York  State.  That Order
requires local  distribution  companies  ("LDCs") to cease assigning capacity to
migrating  customers  no later than April 1, 1999,  and  indicates  LDCs will be
provided a reasonable  opportunity to recover  strandable  capacity costs.  LDCs
will also be  required to develop  individual  plans to  effectuate  the changes
required  by the  PSC.  Each LDC must  address  gas  supply  and  stranded  cost
strategies,  rates,  and  customer  education.  In  such  Order,  the  PSC  also
identified  several  generic  issues  related to the gas industry  which must be
addressed.  The PSC has  indicated  a desire to  address  these  issues  through
collaborative sessions on a state-wide basis.

THE YEAR 2000 ISSUE

OVERVIEW

            Over the last several decades, certain computer systems and programs
were designed to identify the year with two digits.  Such systems may read dates
in the year 2000 and  thereafter  as if those dates  represent  the year 1900 or
thereafter.  As a result,  errors  may  occur if  computers  cannot  distinguish
between 1900 and 2000. All mainframe and personal computers, and related system,
application code and process control systems using embedded chip technology have
a potential for being adversely affected by the use of two digit definitions for
the  identification  of the year  component of date  information.  These include
corporate business  applications,  facilities maintenance and operation systems,
energy  generation,  control and  distribution  processes,  customer service and
support activities and the equipment related to the support of these activities.
If such adverse  effects are not  successfully  remediated  before  December 31,
1999,  interruption  to electric  and/or  natural gas service could occur,  with
attendant lost revenues and adverse customer relations impacts.

            At the Company,  the Year 2000 problem project ("Project") is a high
priority undertaking,  encompassing all aspects of the Company's operations. The
Project focuses on mission critical systems affecting delivery of service to the
Company's  customers  and  business  critical  applications  necessary  for  the
operational and financial stability of the Company.  The Project is currently on
schedule with  implementation  projected to be completed by June 1999. A Project
Committee  comprised of Company officers reports directly to the Chief Executive
Officer

                                      28


<PAGE>



on a monthly  basis on the status of its efforts to assess and  remediate any of
the Company's Year 2000 problems.

            The Company is actively  engaged in the coordination and remediation
of  Year  2000  problems  potentially  affecting  interconnection  affiliations,
electric  transmission grid impact planning,  service  reliability and emergency
and  operational  requirements  with the  North  American  Electric  Reliability
Council   ("NERC")  and  NYPP.  The  Company  has  combined  with  domestic  and
international  electric utilities in developing and sharing  information through
the Electric Power Research  Institute  ("EPRI") data base  addressing Year 2000
problem  assessment,  testing and  remediation of digital and embedded  systems.
Under the NERC guidelines, the Company's remediation is scheduled for completion
by July 1999. The PSC has accepted the NERC guidelines and schedule. The Company
has joined in similar  initiatives to facilitate Year 2000 problem solving among
electric and gas utilities under the auspices of the Edison  Electric  Institute
("EEI") and American Gas Association ("AGA"), respectively.

            The Company has not experienced  any significant  Year 2000 problems
to date nor does it anticipate  problems which may impact the Company's  ability
to provide uninterrupted service to its customers. However, given the complexity
of Year 2000 problems and the Company's technology sensitive industry,  even the
most  comprehensive  and intensive  program cannot  guarantee that an unforeseen
problem will not occur. Therefore,  all Company operational emergency,  disaster
recovery and  contingency  plans  currently in place are being reviewed  against
potential Year 2000 problem  impacts.  A Year 2000 problem  contingency  plan to
deal with any  unanticipated  problems  which may occur  will be in place by the
summer of 1999 and will address the reasonably likely worst-case scenarios. This
contingency  plan will  identify  supplemental  staffing  required  to  manually
operate critical systems and intervene to resolve  unanticipated  problems.  The
Company also plans for an  independent,  external  review and  assessment of all
Project activities in the second quarter of 1999.

SCOPE & STATUS

            The Project  began in 1995 to determine  the  potential for the Year
2000 problem to interrupt the Company's ability to provide reliable electric and
gas services to its customers.  The Project Committee was established to address
the issues  and  established  Year 2000  problem  Project  teams for each of the
Company's operating areas to address the following key components:

1.   Computer hardware and software operating systems and infrastructure;

                                      29


<PAGE>



2.    Information applications,  including customer service, financial and human
      resource systems;

3.    Telecommunication systems;

4.    Digital  systems  and  devices  with  embedded  processors  such as  power
      instrumentation, controls and metering; and

5.    Major suppliers.

            The part of the Project dealing with the inventory and assessment of
all known  Company  mission  critical  and  business  critical  systems has been
completed.  These items are those believed by the Company to affect the delivery
of service to the customer, the integrity of the environment,  the financial and
operational infrastructure of the Company and the safety of individuals.

            The part of the Project  dealing with the  remediation,  testing and
implementation  of required  modifications  to Company  assets to eliminate Year
2000  problems  and  achieve  Year  2000  compliant  status  is on, or ahead of,
schedule. The design, development and testing of Company contingency planning is
following the guidelines for content and completeness as issued by the NERC.

            The process of identifying and prioritizing critical suppliers,  has
been  completed with  evaluation of supplier  status  currently in progress.  To
identify the Company's critical  suppliers,  the Company's materials control and
fuels procurement  personnel  reviewed those materials and services required for
support of mission and business critical activities. These results were reviewed
with management and formed the basis of direct written requests to suppliers for
information  on their Year 2000  compliance.  Evaluation  of  responses to those
requests will determine future verification  procedures.  Validation of supplier
compliance  may  include  on-site  verification  of their  Year  2000  readiness
information,  including  individual  and/or  industry  compliance  test results.
Supplier contingency  planning is scheduled to be developed  concurrently and as
part of the Company's overall contingency planning.

COSTS

            Total  Project  costs  for  all  activities,   including  inventory,
remediation  and testing  required to become Year 2000  compliant are not deemed
material nor significant  relative to the Company's  financial  position.  It is
expected that all Project  expenditures will be paid for by the Company from its
normal operating and maintenance budgets.

            Of a total  Project  estimate  of $3.0  million  approximately  $1.4
million has been expended through December, 1998, including $814,400 of internal
labor  charges.  The Company does not expect final  Project costs to exceed this
estimate; however, no assurances can be given.

                                      30


<PAGE>



RISKS

            The reasonably likely worst-case  scenario should the Company and/or
its suppliers fail to correct a material Year 2000 problem is an interruption in
the  Company's  ability to deliver  electric  and/or gas  service to  customers,
thereby adversely impacting the ability of major customers to continue effective
operations. If such interruption extended for a lengthy period of time, it could
result in a loss of revenue  that could  have a material  adverse  effect on the
Company's financial  position.  Additionally,  Year 2000-related  problems could
disrupt  the  operations  of major  customers,  reducing  their  use of  Company
services or their ability to pay for such services. However, it is expected that
any  potential  impact  to the  Company  specifically  related  to a  Year  2000
problem-induced  business failure for any of its customers would not differ from
an extended  Company  service  interruption  attributable  to  physical  service
failures,  weather  events or natural  disaster.  The Company  believes that the
completion of the Project as scheduled will significantly reduce the possibility
of significant  interruptions  to its normal business  operations;  however,  no
assurance can be given.

RATE PROCEEDINGS

ELECTRIC

            See the caption  "Competitive  Opportunities  Proceeding  Settlement
Agreement" in Note 2 hereof.

GAS

            The Company currently does not have a gas rate case on file with the
PSC.  Management  will  continue  to monitor the  financial  position of its gas
business to determine the necessity of filing a gas rate case in the future.

CAPITAL RESOURCES AND LIQUIDITY

CONSTRUCTION PROGRAM

            As shown  in the  Consolidated  Statement  of Cash  Flows,  the cash
expenditures  related to the Company's  construction  program  amounted to $45.1
million in 1998,  a $1.6 million  increase  from the $43.5  million  expended in
1997. As shown in the table below, cash  construction  expenditures for 1999 are
estimated  to be $50.7  million,  an increase of $5.6  million  compared to 1998
expenditures.

            In 1999,  the  Company  expects  to  satisfy  its  external  funding
requirements,  either through short-term  borrowings or issuances of medium term
notes.

                                      31


<PAGE>



            Estimates of construction  expenditures,  internal funds  available,
mandatory and optional  redemption or  repurchase of long-term  securities,  and
working capital  requirements for the two-year period 1999-2000 are set forth by
year in the following table:

                                                                       Total
                                        1999           2000          1999-2000
                                        ----           ----          ---------
                                              (In Thousands)

Construction Expenditures*.....      $ 50,700        $ 49,100        $ 99,800
Internal Funds Available.......        55,200          45,200         100,400
                                      -------         -------         -------

Excess of Construction
 Expenditures over Internal
 Funds.........................        (4,500)          3,900             600)
                                      -------         -------          ------

Mandatory Redemption of Long-
 term debt.....................        20,100          35,100          55,200


Optional Redemption or Purchase
 of Long-term debt.............        37,600            -             37,600

Other Cash Requirements........         3,000          19,000          22,000
                                      -------         -------         -------

Total Cash Requirements........      $ 56,200        $ 58,000        $114,200
                                      =======         =======         =======

* Excluding the equity  portion of Allowance for Funds Used During  Construction
("AFDC"), a noncash item.

            Estimates of  construction  expenditures  are subject to  continuous
review and adjustment,  and actual  expenditures may vary from estimates.  These
construction  expenditures include capitalized  overheads,  nuclear fuel and the
debt portion of AFDC and assume that the planned  divestiture of the Roseton and
Danskammer  Plants occurs on January 1, 2000.  The actual date of divestiture is
likely to occur at some future date in 2000.

            Included  in the 1999  construction  expenditures  are  expenditures
which are  required to comply with the Clean Air Act and related  Amendments  of
1990.

            As shown in the table above,  it is presently  estimated  that funds
available  from  internal  sources  will  finance  100%  of the  Company's  cash
construction  expenditures  in 1999 and 92% in 2000.  During this same  two-year
period, total external financing  requirements are projected to amount to $114.2
million,  of which  $55.2  million  is related to the  mandatory  redemption  of
long-term  securities and $37.6 million is related to the optional redemption of
long-term securities.

                                      32


<PAGE>



CAPITAL STRUCTURE

            Over the period 1989-1996, the Company worked to increase its common
equity  ratio to a target range of 50% to 52%,  which it achieved in 1996.  As a
result of the ratio  exceeding  this  target  range  during  1997,  the  Company
instituted a common stock repurchase program,  which enabled the Company to both
maintain  the target  equity ratio and enhance  earnings per share in 1998.  The
Company  reached the target  equity ratio  through the retention of a portion of
its  earnings,  original  issuances  of its  common  stock  under  its  Dividend
Reinvestment Program ("DRP") and its Customer Stock Purchase Plan ("CSPP") (both
of which have since been superseded, effective January 1, 1997, by the Company's
Stock  Purchase  Plan  described  in this  Item 7 under the  caption  "Financing
Program,"  below and in Note 6  "Capitalization  - Capital  Stock"  hereof)  and
redemptions of debt and preferred stock. However, the common equity ratio target
range of 50% to 52% was established under a "vertically integrated" structure in
effect  prior to the  effectiveness  of the  Agreement,  (described  in Note 2 -
"Regulatory  Matters"  hereof  under  the  caption  "Competitive   Opportunities
Proceeding  Settlement  Agreement").  The  Agreement  requires  that the Company
divest  itself of its  fossil-fueled  generation  and  permits  the  Company  to
establish a holding company  structure which will allow the Company to invest in
unregulated business ventures. Divesture of its fossil-fueled generation and the
formation  of the  holding  company  structure  will  require  that the  Company
reevaluate  its common  equity  ratio  target.  The target  equity  ratio may be
reduced  in view of a  potentially  lower  level of  business  risk  after  such
divestiture.  This reduction may make  additional  equity  capital  available to
invest in unregulated business ventures.

            The  increase  in the common  equity  ratio has  contributed  to the
significant improvement in the Company's interest coverage ratios as shown under
the caption "Financial  Indices" in this Item 7. The Company's interest coverage
ratios have also  improved  due to the  refinancing  of a portion of its debt at
lower interest rates.  Despite a tightening of bond rating  criteria  applied to
the electric utility industry, the Company has maintained or improved its senior
secured debt ratings since 1991. During 1998, Moody's Investors  Service,  Inc.,
upgraded the Company's senior debt rating from "A3" to "A2." The Company's other
bond ratings,  which were  reaffirmed  during 1998, are "A" by Standard & Poor's
Corporation,  Duff & Phelps Credit Rating Co. and Fitch/IBCA  Investors Service.
The Company's continuing goal is to achieve and maintain bond ratings at the "A"
level.

            Under the terms of the Agreement,  the Company may invest up to $100
million in unregulated  businesses  prior to the formation of a holding  company
structure, which formation is contemplated to become effective in the first half
of 1999. After its formation, such holding company structure will be free

                                      33


<PAGE>



to invest in new businesses subject only to the terms of the Agreement. Pursuant
to the terms of the  Agreement,  the Company has  invested an  additional  $25.5
million of equity capital in unregulated ventures.

            Set forth below is certain information with respect to the Company's
capital structure at the end of 1998, 1997 and 1996:

                                       YEAR-END CAPITAL STRUCTURE
                                    -------------------------------
                                    1998          1997         1996
                                    ----          ----         ----
Long-term debt ..........           41.0%(a)     40.5%         40.1%
Short-term debt .........            1.9           -            1.7
Preferred stock .........            6.1          6.3           6.2
Common equity ...........           51.0         53.2          52.0
                                   -----        -----         -----
                                   100.0%       100.0%        100.0%
                                   =====        =====         =====

(a) Excludes $16.7 million of bonds issued through the New York Energy  Research
    and Development  Authority  ("NYSERDA") on December 2, 1998, discussed below
    under the subcaption "Financing Program."

FINANCING PROGRAM

            By an Order issued and effective  December 4, 1996,  the PSC granted
the Company authorization to issue and sell, through December 31, 1999, up to an
additional $40 million of securities which can be comprised of medium term notes
or common stock solely or a  combination  of medium term notes and common stock.
The December 1996 Order also authorizes the Company to acquire, through December
31, 1999, not more than 2.5 million shares of its issued and outstanding  common
stock.  The Company also received  approval to combine its DRP, its CSPP and its
Employee Stock Purchase Plan ("ESPP") into a new Stock Purchase Plan,  which was
done  effective  January 1, 1997. The Stock Plan can be either an original issue
plan or an open market  purchase  plan.  The Stock Purchase Plan is currently an
open-market purchase plan.

            Pursuant to the aforementioned PSC  authorization,  the Company,  in
January 1997,  instituted a common stock  repurchase  program  primarily for the
purpose of managing its common  equity ratio.  Since  inception of such program,
the Company  repurchased through December 31, 1998, 692,900 shares of its common
stock.  As a result of such program and the issuance of  incremental  debt,  the
Company's common equity ratio declined to 51.0% at December 31, 1998. In view of
the price per share of common stock,  cash flow and opportunities to reinvest in
the Company's business or invest in new unregulated businesses,  the Company has
suspended this program,  effective December 31, 1998. However,  the Company will
continue to reevaluate  reactivation  of its  repurchase  program on a quarterly
basis.

          Under  the terms of the  Agreement,  prior to the  formation  of a new
holding company structure, the Company may

                                      34


<PAGE>



transfer  up to  $100  million  from  its  regulated  utility  business  to  its
unregulated   businesses,   of  which   approximately  $25.5  million  has  been
transferred  as of  December  31,  1998.  The  Company  may,  pursuant  to  this
authorization,  issue,  no later than June 30,  2001,  up to $100 million of new
securities,   including  up  to  one  million  shares  of  common  stock.   This
authorization is separate from the securities  issuance  authorization under the
PSC's  December,  1996 Order  discussed  above.  Following  the formation of the
holding company structure contemplated under the Agreement,  the holding company
may issue new securities in furtherance of its business plan.

            On  September  8, 1998,  the  Company  issued and sold a $15 million
tranche of its unsecured Medium-Term Notes, Series B, under its medium term note
program  pursuant  to said PSC Order of December  1996.  Such notes bear a fixed
annual  interest  rate of  5.93%,  mature on  September  10,  2001,  and are not
redeemable at the option of the Company  prior to maturity.  The net proceeds to
the  Company  from the sale of such notes  were  $14,947,500  or 99.65%  (before
deducting expenses).

            On December 2, 1998,  the Company  refinanced  the 8.375%  series of
pollution control bonds issued on its behalf in 1988 in the aggregate  principal
amount of $16.7 million by NYSERDA (the "1988  NYSERDA  Bonds") by refunding the
1988  NYSERDA  Bonds with the  proceeds of the issuance and sale on that date of
$16.7 million  aggregate  principal amount of a new series of NYSERDA bonds (the
"1998 NYSERDA  Bonds").  The redemption date for the 1988 NYSERDA Bonds is March
1, 1999.  The 1998 NYSERDA Bonds have the same maturity date  (December 1, 2028)
as the 1988 NYSERDA Bonds they  refunded;  however,  the 1998 NYSERDA Bonds have
multi-  modal  features,  which allows the Company in certain  circumstances  to
convert the 1998 NYSERDA  Bonds from time to time to and from  certain  interest
rate modes (variable and fixed) of varying lengths, at the end of which the 1998
NYSERDA are subject to mandatory  tender and purchase and may be remarketed,  or
their  interest  rate may be  converted to a fixed rate until  maturity.  During
certain  variable  interest  rate modes,  the 1998 NYSERDA  Bonds are subject to
optional  tender and purchase by their holders and may be  remarketed.  The 1998
NYSERDA Bonds are insured as to payment of principal and interest as they become
due by a municipal bond insurance  policy issued by Ambac Assurance  Corporation
and purchased by the Company.  The 1998 NYSERDA Bonds were issued initially in a
term rate mode for five years,  ending on November 30, 2003, during which period
they will bear interest at the fixed annual rate of 4.20%.  Upon their mandatory
tender for  purchase on December  1, 2003,  the Company  will have the option to
convert the 1998 NYSERDA  Bonds to an alternate  interest  rate mode or to bonds
bearing a fixed rate of interest  for the  remainder  of their term as described
above.

            On January  15,  1999,  the  Company  issued and sold a $20  million
tranche of its unsecured Medium-Term Notes, Series C, under its medium term note
program  pursuant  to said PSC Order of December  1996.  Such notes bear a fixed
annual interest rate of

                                      35


<PAGE>



6.00%,  mature on January 15, 2009,  and are not redeemable at the option of the
Company prior to maturity. The net proceeds to the Company from the sale of such
notes were  $19,875,000 or 99.875% (before  deducting  expenses).  Such proceeds
were  applied to the payment at maturity on January 15, 1999,  of a  $20,000,000
tranche  of the  Company's  unsecured  Medium-Term  Notes,  Series  A, that bore
interest at a fixed annual interest rate of 5.38%.

            If interest rates are  favorable,  the Company may redeem its 6 1/4%
NYSERDA Bonds ($4.1 million) at par and its 7 3/8% NYSERDA Bonds ($33.4 million)
at 103%.

            For more information with respect to the Company's financing program
in  general,  see  Note  6  -  "Capitalization  Capital  Stock"  and  Note  7  -
"Capitalization - Long-Term Debt."

SHORT-TERM DEBT

            As  more  fully   discussed  in  Note  5  -  "Short-Term   Borrowing
Arrangements"  hereof,  the Company has a revolving  credit  agreement with four
commercial  banks for borrowing up to $50 million  through  October 23, 2001. In
addition,  the Company has several  committed and  uncommitted  bank  facilities
ranging  from $.5  million to $50  million  from which it may obtain  short-term
financing.  Such agreements give the Company competitive options to minimize its
cost of short-term  borrowing.  Authorization from the PSC limits the amount the
Company may have  outstanding at any time under all of its short-term  borrowing
arrangements to $52 million in the aggregate.

            As part of its establishing a holding company,  structure, CH Energy
Group,  Inc., the proposed holding  company,  has established a revolving credit
agreement with three  commercial  banks for borrowing up to $50 million  through
December 4, 2001. No borrowings  are permitted  under such  agreement  until the
share exchange  establishing CH Energy Group, Inc. as a holding company has been
effected.

RESULTS OF OPERATIONS

            The following discussion and analysis includes an explanation of the
significant  changes in revenues and expenses  when  comparing  1998 to 1997 and
1997 to 1996. Additional  information relating to changes between these years is
provided in the Notes.

EARNINGS

            Earnings  per share of common  stock are shown after  provision  for
dividends on preferred stock and are computed on the basis of the average number
of common shares  outstanding  during the year. The number of common shares, the
earnings per share and the rate of return earned on average common equity are as
follows:

                                      36


<PAGE>



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

Average shares outstanding (000s)..           17,034      17,435      17,549
Earnings per share.................           $ 2.90      $ 2.97      $ 2.99
Return earned on common equity
 per financial statements*.........            10.3%       10.8%       11.1%

* Return on equity  for  regulatory  rate-making  purposes  differs  from  these
figures.

            Earnings per share in 1998 when compared to 1997  decreased $.07 per
share.  This  decrease  resulted  primarily  from the net effect of $.11 for the
non-recurring  items recorded in 1998 and 1997. The 1998 non-recurring items are
the  final  provision  for the  non-recoverable  portion  of a  purchased  power
contract and the gain on the sale of a subsidiary asset.  Nonrecurring  items in
1997 included the recording of tax adjustments from the favorable  settlement of
various  Internal  Revenue Service ("IRS") audits and the initial  provision for
the non-recoverable  portion of a purchased power contract. Also contributing to
the decrease  was  increased  depreciation  of $.07 on the  Company's  plant and
equipment and decreased  net  operating  revenues of $.07.  The reduction in net
operating  revenues  includes a reduction in gas net operating  revenues of $.05
resulting  primarily  from a decrease in usage by  residential,  commercial  and
industrial  customers due to milder  weather.  Heating  billing  degree days, as
compared to 1997, were 11% lower in 1998.

            These  decreased  earnings  in 1998  were  partially  offset  by the
favorable  earnings impact of decreased  operation and  maintenance  expenses of
$.11,  of which $.10 is a reduction  in  employee  compensation  and  associated
fringe  benefits  and  the  favorable  impact  of  the  Company's  common  stock
repurchase  program of $.07. The reduction in compensation is primarily due to a
reduction in the number of employees.

            Earnings per share in 1997, when compared to 1996 results, decreased
$.02 per share.  This decrease resulted  substantially  from a $.13 reduction in
electric and gas net  operating  revenues  (including  fuel costs and  purchased
electricity)  attributable largely to decreased sales resulting primarily from a
decrease  in  usage  by  residential  and  industrial   electric  customers  and
residential and commercial gas customers due to unseasonable weather experienced
in 1997.  Heating billing degree days were 8% lower and cooling degree days were
16%  lower,  when  1997  results  were  compared  to 1996.  The  effect of these
unseasonable  weather  conditions  alone reduced  earnings by an estimated $.22,
despite a 1%  increase  in the number of  customers.  Also  contributing  to the
decrease in 1997 earnings were decreased electric earnings related to regulatory
incentive  programs based on fuel costs and energy  efficiency of $.10,  largely
due to the reduced availability of purchased power at a cost below the Company's
fossil-fueled  generation,  and  increased  depreciation  expense of $.07 on the
Company's plant and equipment.

                                      37


<PAGE>



            Partially  offsetting  these  decreases in 1997  earnings was a $.09
increase  resulting from the net effect of two  non-recurring  items as follows:
the 1997 recording of tax adjustments  from the favorable  settlement of various
IRS audits and the 1997 provision for the non-recoverable portion of a purchased
power  contract.   Other  items  which  impacted  earnings  favorably  included:
decreased  uncollectible  accounts of $.05,  avoided  interest  expense from the
optional redemption in May 1996 of the Company's 8 3/4% Series $30 million First
Mortgage  Bonds of $.04 and $.10 due to the  combined  effect of  various  other
items  including a decrease in interest  expense and an increase in interest and
dividend income.

            The Company has  established  a projection  for earnings in calendar
year 1999 of $2.79 per  share.  This  projected  level,  which is $.11 per share
below the actual 1998 level of $2.90 per share, reflects the planned transfer of
equity capital from regulated  utility  operations to unregulated  affiliates in
stages  over the course of the year.  These  transfers  will fund  expansion  of
unregulated  affliates into new competitive  energy markets to take advantage of
opportunities expected to develop due to industry restructuring.  However, these
transfers are projected to result in a modest reduction in earnings per share in
1999 as the new operations mature. As a result of the Company's strong financial
condition  and  conservative  dividend  policy,  the  Company  expects  that any
resulting  reduction in earnings as new business  development  activities mature
will not impact the Company's ability to maintain the current level of dividend,
although no assurances can be given.

                                      38


<PAGE>



OPERATING REVENUES

            Total  operating  revenues  decreased  $16.8 million (3%) in 1998 as
compared to 1997 and increased $6.3 million (1%) in 1997, as compared to 1996.

See the table below for details of the variations:
<TABLE>

                                                              INCREASE OR (DECREASE) FROM PRIOR YEAR
                                    -------------------------------------------------------------------------------------------
                                                       1998                                               1997
                                                       ----                                               ----
                                    ELECTRIC           GAS            TOTAL             ELECTRIC          GAS             TOTAL
                                    --------           ---            -----             --------          ---             -----
                                                                        (In Thousands)
<S>                                 <C>             <C>             <C>                 <C>             <C>             <C>
Customer sales.............         $   770         $(12,797)       $(12,027)           $(7,860)        $ 2,624         $(5,236)
Sales to other utilities...           6,991              561           7,552              4,840          (2,290)          2,550
Fuel cost adjustment.......           1,743           (8,172)         (6,429)              (291)          8,846           8,555
Deferred revenues..........          (7,013)           1,563          (5,450)               675          (1,125)           (450)
Miscellaneous..............            (412)             (42)           (454)               304             583             887
                                     ------          -------         -------             ------          ------          ------
      Total...............          $ 2,079         $(18,887)       $(16,808)           $(2,332)        $ 8,638         $ 6,306
                                     ======          =======         =======             ======          ======          ======
</TABLE>



                                      39


<PAGE>



SALES

            The  Company's   sales  vary  seasonally  in  response  to  weather.
Generally  electric  revenues  peak in the summer and gas  revenues  peak in the
winter.

            Sales  of  electricity   within  the  Company's   service  territory
increased  1% in 1998  and  decreased  3% in  1997.  Electric  sales  in 1998 to
residential,  commercial  and  industrial  customers each increased 1%. In 1997,
electric  sales  decreased  3% due  primarily  because of a decrease in usage by
residential and industrial  customers  largely due to the  unseasonable  weather
conditions experienced in 1997, when compared to 1996.

            Firm  sales  of  natural  gas  (which  excludes   interruptible  and
transportation sales) decreased 12% in 1998 due primarily to a decrease in usage
by residential and commercial  customers largely due to the unseasonable weather
conditions experienced in 1998. In addition,  firm sales to industrial customers
decreased  due  substantially  to a  decrease  in  usage  by a large  industrial
customer  and  the   conversion   of  a  number  of   industrial   customers  to
transportation  service.  Firm sales of  natural  gas in 1997  decreased  5% due
primarily to a decrease in usage by residential and commercial customers.

            Changes  in sales from last year by major  customer  classification,
including  interruptible  gas sales, are set forth below. Also indicated are the
changes related to energy delivery service:

                                            % Increase (Decrease)
                                                From Prior Year
                                     ----------------------------------------
                                       Electric (MWh)           Gas (Mcf)
                                       --------------           ---------
                                     1998        1997        1998        1997
                                     ----        ----        ----        ----
Residential......................      1          (2)        (11)         (6)
Commercial.......................      1           -          (9)         (6)
Industrial.......................      1          (6)        (32)         11
Interruptible....................     N/A         N/A        (22)        111
Energy Delivery Service
  Electric ......................     (a)         N/A        N/A         N/A
  Gas - Firm Customers...........     N/A         N/A        869         (a)
      - Interruptible............     N/A         N/A         (3)         74

(a) - Prior year was zero.

            Residential and Commercial Sales: Residential electric and gas sales
are  primarily  affected by the growth in the number of customers and the change
in customer  usage.  In 1998,  sales of  electricity  to  residential  customers
increased  1% due  to an  increase  in  usage  per  customer.  Commercial  sales
increased  1%  resulting  from the net effect of a 2%  increase in the number of
customers  and  a 1%  decrease  in  usage  per  customer.  Unseasonable  weather
conditions  (billing degree days were 11% lower)  contributed to the decrease in
residential and commercial sales

                                      40


<PAGE>



of gas.  Sales  of gas to  residential  customers  decreased  11% due to the net
effect of a 12%  decrease  in usage per  customer  due to  unseasonable  weather
conditions  and a 1%  increase  in the  number of  customers.  Commercial  sales
decreased 9% due to the net effect of a 12% decrease in usage per customer and a
3% increase in the number of customers.

            In 1997, residential electric and gas sales and commercial gas sales
decreased  primarily  because of a decrease in customer usage largely due to the
unseasonable  weather  experienced in the Company's  service  territory in 1997.
Heating billing degree days were 8% lower and cooling degree days were 16% lower
in 1997 than in the prior year.

            Industrial Electric Sales: In 1998, as compared to 1997,  industrial
electric sales increased 1%. In 1997, as compared to 1996,  industrial  electric
sales  decreased 6% primarily  due to a decrease in usage by a large  industrial
customer.

            Industrial  Gas  Sales:  In  1998,  firm  gas  sales  to  industrial
customers  decreased  32%  primarily  because of a decrease  in usage by a large
industrial  customer and the  conversion of a number of industrial  customers to
firm  transportation  service.  Firm gas sales to industrial  customers for 1997
increased  11%  primarily  because  of  increased  usage  by a large  industrial
customer.

            Interruptible Gas Sales: In 1998,  interruptible gas sales decreased
22%  largely  due to a  decrease  in boiler gas usage for  electric  generation.
Interruptible  gas sales  increased  111% in 1997, due largely to an increase in
natural gas sold for use as a boiler fuel at the Roseton  Plant.  The use of gas
as a boiler fuel at the Roseton Plant is dependent upon its economic  benefit as
compared to the use of oil for generation or the purchase of electricity to meet
the Company's load requirements.  Due to sharing  arrangements,  as described in
the  caption  "Incentive  Arrangements"  of Item 7 hereof  that are in place for
interruptible gas sales and  transportation of  customer-owned  gas,  variations
from year to year typically have a minimal impact on earnings.

            Electric  Delivery  Service:  The  phase-in  of  retail  access  for
residential,  commercial and small industrial customers began in 1998 as part of
the  Agreement.  As a  result  of .1% of the  Company's  customers  moving  from
purchases of electricity from the Company within the Company's franchise area to
purchases from energy marketers  (retail access),  53 million kWh of electricity
was delivered to retail access customers in 1998.

          Transportation of Customer-owned Gas: The volume of customer-owned gas
transported for firm customers  increased 869% in 1998 due to an increase in the
number of customers switching

                                      41


<PAGE>



from  full gas  supply to firm  transportation  service,  which had no  material
revenue  impact on the Company.  No volumes of gas were  transported in 1996 for
firm customers. Transported gas for interruptible customers decreased 3% in 1998
due to a decrease in usage by a large industrial customer. In 1997,  transported
gas for interruptible  customers  increased 74% due to an increase in usage by a
large industrial customer.

INCENTIVE ARRANGEMENTS

            Pursuant to certain  incentive  formulas  approved  by the PSC,  the
Company either shares with its customers,  certain  revenues and/or cost savings
exceeding  defined  predetermined  levels,  or is  penalized  in some  cases for
shortfalls from the targeted levels or defined performance standards.

            Incentive  formulas are in place for fuel cost variations,  sales of
electricity  and gas to  other  utilities,  interruptible  gas  sales,  capacity
release transactions and customer satisfaction.

            The net results of these incentive  formulas were to increase pretax
earnings by $1.0 million, $700,000 and $2.9 million during 1998, 1997, and 1996,
respectively.

OPERATING EXPENSES

            Changes  from the  prior  year in the  components  of the  Company's
operating expenses are listed below:

                                             Increase or (Decrease)
                                                From Prior Year
                                     --------------------------------------
                                             1998              1997
                                      ----------------   -----------------
                                       Amount      %        Amount      %
                                       ------      -        ------      -
                                                 (In Thousands)
Operating Expenses:
  Fuel and purchased
   electricity...............        $  3,280       3      $  7,584      7
  Purchased natural gas......         (16,550)    (27)       10,878     22
  Other expenses of
   operation.................          (4,972)     (5)       (1,527)    (2)
  Maintenance................            (670)     (2)       (1,364)    (5)
  Depreciation and
   amortization..............           1,696       4         1,284      3
  Taxes, other than
   income tax................          (1,421)     (2)       (1,266)    (2)
  Federal income tax.........             585       2        (3,510)   (11)
                                      -------               -------
          Total..............        $(18,052)     (4)     $ 12,079      3
                                      =======               =======

            The most  significant  elements of  operating  expenses are fuel and
purchased electricity in the Company's electric department and purchased natural
gas in the Company's gas

                                      42


<PAGE>



department.  Approximately  30% in 1998 and 29% in 1997 of every revenue  dollar
billed by the Company's  electric  department was expended for the combined cost
of fuel used in electric generation and purchased electricity. The corresponding
figures in the Company's gas  department  for the cost of purchased gas were 53%
and 59%, respectively.

            In an  effort  to  keep  the  cost  of  electricity  at  the  lowest
reasonable level, the Company purchases energy from sources such as other member
companies of the NYPP,  Canadian  hydro  sources and energy  marketers  whenever
energy  can be  purchased  at a unit cost  lower  than the  incremental  cost of
generating the energy in the Company's plants.

            Purchased  natural gas decreased $16.6 million (27%) in 1998 largely
due to lower firm and  interruptible  gas sales,  including gas used as a boiler
fuel. Other expenses of operations decreased $5.0 million (5%) in 1998 resulting
from  decreased  employee  compensation  due to fewer  employees and  associated
fringe benefits.  In 1997, fuel and purchased electricity increased $7.6 million
(7%)  primarily  because of a 3% increase in total system  sales which  includes
sales to other utilities. Purchased natural gas increased $10.9 million (22%) in
1997 primarily because of higher interruptible gas sales including gas used as a
boiler fuel at the Roseton Plant.

            See Note 4 -  "Federal  Income  Tax,"  hereof  for an  analysis  and
reconciliation of the federal income tax.

OTHER INCOME AND INTEREST CHARGES

           Other income  (excluding  AFDC)  decreased $3.0 million (27%) in 1998
and increased $4.6 million (71%) in 1997. The 1998 decrease  resulted  primarily
from interest  refunded in 1997 from the  settlement of various IRS audits.  The
1997 increase was due primarily to interest refunded in 1997 from the settlement
of  various  IRS  audits  and the 1996  charges  associated  with  the  optional
redemption of the 8 3/4% Series of First Mortgage Bonds.

           Total interest  charges  (excluding AFDC) increased $1.0 million (4%)
in 1998  primarily  because of an increase in  borrowings,  and $533,000 (2%) in
1997.

                                      43


<PAGE>



           The  following  table sets forth  some of the  pertinent  data on the
Company's outstanding debt:

                                            1998        1997         1996
                                            ----        ----         ----
                                                 (In Thousands)
Long-term debt:
  Debt retired................           $     90    $     85      $ 30,000
  Outstanding at year-end*:
  Amount (including current
   portion)...................            396,998     363,744       364,026
  Effective rate..............              6.56%       6.78%         6.70%
Short-term debt:
  Average daily amount
   outstanding ...............           $  1,171    $  1,692      $  5,477
  Weighted average
   interest rate .............              5.51%       5.54%         5.59%

*Including  debt of  subsidiaries of $9.0 million in 1998, $7.4 million in 1997,
and $7.6 million in 1996.

See Note 5 - "Short-Term  Borrowing  Arrangements"  and Note 7 "Capitalization -
Long-Term  Debt" hereof for  additional  information on short-term and long-term
debt of the Company.

NUCLEAR OPERATIONS

          The Nine Mile 2 Plant is owned, as tenants-in-common,  by the Company,
Niagara  Mohawk,  New York State  Electric & Gas  Company  ("NYSEG"),  LILCO,  a
subsidiary of LIPA,  and Rochester Gas and Electric  Corporation  ("Rochester").
Niagara Mohawk operates the Nine Mile 2 Plant.

          The  Company  owns a 9%  interest  of the Nine Mile 2 Plant,  which is
discussed in Note 3 - "Nine Mile 2 Plant."

          The  Company's  share of operating  expenses,  taxes and  depreciation
pertaining  to the  operation  of the  Nine  Mile 2 Plant  are  included  in the
Company's  financial  results.  For  both  1998 and  1997,  the  actual  cost of
operations  was  less  than  the  allowable  Nine  Mile 2  Plant  operation  and
maintenance  expenses  provided  in  Supplement  No.  5 to the  1990  Settlement
Agreement,  as approved by the PSC. In both 1998 and 1997,  the  underruns  were
entirely  deferred for the future benefit of customers (see Note 2 - "Regulatory
Matters").

          The Company has continued to participate  actively in the  management,
operations and accounting committees for the Nine Mile 2 Plant and will continue
to do so in the future.

          On October 12, 1996,  Niagara Mohawk and Rochester  announced plans to
establish  a joint  nuclear  operating  company to be known as New York  Nuclear
Operating Company ("NYNOC").  NYNOC was envisioned to assume full responsibility
for  operation of all the nuclear  plants in New York State,  including the Nine
Mile 2 Plant, Niagara Mohawk's Unit No. 1 of the Nine Mile Point Nuclear Station
and Rochester's Ginna Nuclear Plant. Since that time

                                      44


<PAGE>



NYNOC has been  organized  as a New York  Limited  Liability  Company with three
members:  Niagara Mohawk,  Rochester, and Con Edison. Although not a member, the
PASNY has  participated  in the  development of plans to implement  NYNOC. It is
expected that NYNOC could  contribute to maintaining a high level of operational
performance,  contribute to continued satisfactory Nuclear Regulatory Commission
("NRC")  regulatory   compliance,   provide  opportunities  for  continued  cost
reductions  and provide the basis for  satisfactory  economic  regulation by the
PSC.  The initial work  associated  with plans for  implementation  of NYNOC was
completed  in  1998.  No  substantial  further  work  on its  implementation  is
anticipated  until  completion  of the PSC  proceeding  regarding  the future of
nuclear  power  plants  in New  York  State  (as  described  below).  Sufficient
information is not available for the Company to make an assessment of such plans
or  whether it would  consent  to such plans to the extent  that the Nine Mile 2
Plant is affected.  Until such  assessment  can be made, the Company can take no
position with respect to such plans.

            On or about June 15, 1998, NYSEG, one of the owners of the Nine Mile
2 Plant,  commenced an action  against  Niagara Mohawk (which is the operator of
the Nine Mile 2 Plant)  in  Supreme  Court of the  State of New  York,  Tompkins
County,  demanding,  among other things,  judgment to (i) enjoin  Niagara Mohawk
from  transferring  operating  responsibility of the Nine Mile 2 Plant to NYNOC;
and  (ii)  declare  that  Niagara  Mohawk  may  not  transfer  its   operational
responsibility for the Nine Mile 2 Plant to NYNOC without NYSE&G's consent.  The
Company can make no prediction as to the outcome of this litigation.

            Niagara Mohawk and NYSE&G  publicly  announced in January 1999 plans
to pursue the sale of their nuclear assets, including their interest in the Nine
Mile 2 Plant.  The Company can make no  prediction as to whether or not any such
sale will occur, or if such sale occurs, the effect on the Company's interest in
the Nine Mile 2 Plant or its operations.

            On  August  27,  1997,  the PSC Staff  issued a  "Notice  Soliciting
Comments on Nuclear Generation"  requesting comments and alternative  approaches
by  interested  parties  on a "Staff  Report on  Nuclear  Generation"  ("Nuclear
Report").  The Nuclear  Report  concludes  that  nuclear  generation  along with
non-nuclear  generation  facilities,  should be  subject  to the  discipline  of
market-based pricing.

            On March 20,  1998,  the PSC  initiated  a  proceeding  to examine a
number of issues  raised by the  Nuclear  Report and the  comments  received  in
response to it. In reviewing the Nuclear Report and parties' comments,  the PSC:
(a) adopted as a rebuttable presumption the premise that nuclear power should be
priced on a market  basis to the same degree as power from other  sources,  with
parties  challenging  that  premise  having  to  bear a  substantial  burden  of
persuasion,  (b)  characterized the proposals in the Staff paper as by and large
consistent  in  concept  with  the  PSC's  goal of a  competitive,  market-based
electricity industry,

                                      45


<PAGE>



(c)  questioned  PSC  Staff's  position  that  would  leave  funding  and  other
decommissioning responsibilities with the sellers of nuclear power interests and
(d)  indicated  interest  in the  potential  for the NYNOC to benefit  customers
through  efficiency  gains and  directed  pursuit of that matter in this nuclear
generating  proceeding or separately upon the filing of a formal NYNOC proposal.
The proceeding is expected to be completed in 1999.

            A  decommissioning  study for the Nine Mile 2 Plant was completed in
1995.  The  study's   estimate  of  the  cost  to  decommission   the  Plant  is
significantly  higher  than  previous  estimates.   The  Company  believes  that
decommissioning  costs, if higher than currently  estimated,  will ultimately be
recovered in rates,  although no such  assurance can be given.  However,  future
developments in the utility industry,  including the effects of deregulation and
increasing competition could change this conclusion.  The Company cannot predict
the outcome of these  developments.  For further information on decommissioning,
see Note 3 - "Nine Mile 2 Plant."

            The NRC issued a policy statement on the  Restructuring and Economic
Deregulation of the Electric Utility Industry ("Policy  Statement") in 1997. The
Policy Statement  addresses NRC's concerns about the adequacy of decommissioning
funds and about the potential  impact on operational  safety and reserves to the
NRC the right, in highly unusual situations where adequate  protection of public
health and safety would be compromised,  to consider  imposing joint and several
liability on minority  co-owners  when one or more  co-owners  have defaulted on
their  contractual  obligations.   On  December  28,  1998,  the  NRC  announced
commencement of a rulemaking  proceeding initiated by a group of utilities which
are non-operating  joint owners of nuclear plants.  These utilities request that
the  enforcement  provisions  of the NRC  regulations  be amended to clarify NRC
policy  regarding the potential  liability of joint owners if other joint owners
become  financially  incapable  of  bearing  their  share of the burden for safe
operation or decommissioning  of a nuclear power plant.  Current NRC regulations
allow a utility to set aside  decommissioning  funds annually over the estimated
life of a plant. In addition to the above Policy Statement, the NRC is proposing
to amend its  regulations  on  decommissioning  funding  to  reflect  conditions
expected from deregulation of the electric power industry. The Company is unable
to predict how such increased stringency may affect the results of operations or
financial condition of the Nine Mile 2 Plant.

            On July 5, 1998, the Nine Mile 2 Plant completed its sixth refueling
outage,  which commenced on May 2, 1998. It is scheduled to commence its seventh
refueling outage March 1, 2000.

                                      46


<PAGE>



OTHER MATTERS

            New Accounting  Standards:  In June 1998,  the Financial  Accounting
Standards Board ("FASB") issued Statement of Financial  Accounting Standards No.
133,  "Accounting  for Derivative  Instruments  and Hedging  Activities"  ("SFAS
133").  This  Statement  establishes  accounting  and  reporting  standards  for
derivative  instruments and for hedging  activities.  It requires that an entity
recognize all  derivatives  as either assets or liabilities in the balance sheet
and measure those  instruments  at fair value.  Any gain or loss  resulting from
changes in such fair value is  required  to be  recognized  in  earnings  to the
extent the  derivatives  are not effective as hedges.  SFAS 133 is effective for
fiscal years beginning after June 15, 1999, and is effective for interim periods
in the  initial  year  of  adoption.  The  Company  currently  does  not own any
derivative  instruments;  however,  the Company  intends to  implement an energy
trading  risk  management  program in 1999 to manage the price risks  associated
with fuel  purchases  for  generation,  natural  gas  purchases  for native load
customers,  and wholesale  power  transactions.  The Company may utilize various
financial instruments, such as futures, options, swaps, caps, floors and collars
to  stabilize  the price  volatility  of these  commodities.  At this time,  the
Company cannot assess the impact that the proposed hedging program would have on
its financial position or results of operations.

            In  February  1996,  the FASB  issued  an  exposure  draft  entitled
"Accounting for Certain Liabilities Related to Closure and Removal of Long-Lived
Assets," which includes nuclear plant decommissioning.  Over the past two years,
this  exposure  draft has been the  source  of  continual  debate.  The FASB has
committed  to  completing  this  project and is  proceeding  toward  issuance of
another  exposure  draft  (expected  in the  second  quarter  of  1999).  If the
accounting  standard  proposed in such  exposure  draft were  adopted,  it could
result  in  higher  annual  provisions  for  removal  or  decommissioning  to be
recognized  earlier in the operating life of nuclear and other  generating units
and an accelerated  recognition of the decommissioning  obligation.  The FASB is
continuing to explore  various  issues  associated  with this project  including
liability measurement and recognition issues. In addition, an effective date for
the new exposure  draft has not yet been  determined.  The FASB is  deliberating
this issue and the resulting  final  pronouncement  could be different from that
proposed in the exposure draft.  The Company can make no prediction at this time
as to the ultimate form of such  proposed  accounting  standard,  assuming it is
adopted,  nor can it make any  prediction  as to its  ultimate  effect(s) on the
financial condition of the Company.

                                      47


<PAGE>



            Other   Issues:   On  an  ongoing   basis,   the  Company   assesses
environmental issues which could impact the Company and its customers.  Note 3 -
"Nine Mile 2 Plant" and Note 9 "Commitments and  Contingencies"  discuss current
environmental   issues   affecting   the   Company,   including   (i)  the  1995
decommissioning  cost study of the Nine Mile 2 Plant,  (ii) the Clean  Water Act
and CAA  Amendments,  which  require  control of  emissions  from  fossil-fueled
electric  generating  units,  (iii) asbestos  litigation cases, and (iv) a legal
action filed in 1995 against the Company by the City of Newburgh, New York.

                                      48


<PAGE>


<TABLE>

FINANCIAL INDICES

            Selected  financial indices for the last five years are set forth in
the following table:
<CAPTION>
                                                                     1998          1997          1996          1995          1994
                                                                     ----          ----          ----          ----          ----
<S>                                                                  <C>           <C>           <C>           <C>           <C>
Pretax coverage of total interest charges:
     Including AFDC.....................................             3.83x         3.94x         4.08x         3.68x         3.38x
     Excluding AFDC.....................................             3.54x         3.69x         3.83x         3.43x         3.15x
     Funds from Operations..............................             4.39x         5.18x         5.29x         4.69x         4.24x

Pretax coverage of total interest
 charges and preferred stock dividends..................             3.27x         3.37x         3.47x         2.97x         2.74x

Percent of construction expenditures
 financed from internal funds...........................             100%          100%           100%          100%          100%

AFDC and Mirror CWIP* as a percentage
 of income available for common stock...................              17%           13%            13%           16%           16%

Effective tax rate......................................              35%            32%           36%           35%           35%

*  Refer  to  Note 2 -  "Regulatory  Matters"  under  the  caption  "Summary  of
Regulatory Assets and Liabilities" and the subcaption  "Deferred Finance Charges
- Deferred Nine Mile 2 Plant Costs" for a definition of Mirror CWIP.
</TABLE>

                                      49


<PAGE>



COMMON STOCK DIVIDENDS AND PRICE RANGES

            The Company and its principal  predecessors  have paid  dividends on
its common stock in each year  commencing  in 1903,  and the common stock of the
Company has been  listed on the New York Stock  Exchange  since 1945.  The price
ranges and the  dividends  paid for each  quarterly  period during the Company's
last two fiscal years are as follows:
<TABLE>
<CAPTION>

                                   1998                                             1997
                   ----------------------------------                ----------------------------------
                     HIGH          LOW       DIVIDEND                  HIGH         LOW        DIVIDEND


<S>                 <C>          <C>          <C>                    <C>          <C>          <C>
1st Quarter        $43 3/4       $39 5/8      $.535                  $33 3/8      $30 1/2      $ .53
2nd Quarter         46            38 7/8       .535                   34 3/4       29 3/4        .53
3rd Quarter         47 1/16       40 7/8       .54                    35 7/8       32 1/8        .535
4th Quarter         45 1/8        39 7/8       .54                    43 7/8       34 11/16      .535
</TABLE>

            On June 26, 1998, the Company increased its quarterly  dividend rate
to $.54 per share from $.535 in 1997.  On June 27, 1997,  the Company  increased
its quarterly dividend rate to $.535 per share from $.53 per share.

            Any determination with regard to future dividend  declarations,  and
the amounts and dates of such dividends, will depend on the circumstances at the
time of consideration of such declaration.  One such  consideration  will be the
effect on the Company of the proposed holding company restructuring described in
this Item 7 under the caption "Competition/Deregulation."

            The number of registered  holders of common stock as of December 31,
1998,  was 21,416.  Of these,  20,836 were accounts in the names of  individuals
with  total  holdings  of  5,132,676  shares,  or an  average  of 246 shares per
account.  The 580  other  accounts,  in the  names  of  institutional  or  other
non-individual  holders,  for the most part, hold shares of common stock for the
benefit of individuals.

     ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
               MARKET RISK
     -------------------------------------------------------

            The Company  intends to implement an energy trading risk  management
program in 1999 to manage the price risks  associated  with fuel  purchases  for
generation, natural gas purchases for native load customers, and wholesale power
transactions.  The Company may utilize various financial  instruments,  such as,
futures,  options,  swaps,  caps,  floors  and  collars to  stabilize  the price
volatility of these  commodities.  At this time,  the Company  cannot assess the
impact that this proposed  hedging program would have on its financial  position
or results of operations.

                                      50


<PAGE>



     ITEM 8 -  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
     -----------------------------------------------------

I - Index to Financial Statements:                               PAGE
                                                                 ----
       Report of Independent Accountants                          52
       Statement of Management's Responsibility                   53
       Consolidated Balance Sheet at
         December 31, 1998 and 1997                               54
       Consolidated Statement of Income for the
         three years ended December 31, 1998                      56
       Consolidated Statement of Retained Earnings
         for the three years ended December 31, 1998              58
       Consolidated Statement of Cash Flows for the
         three years ended December 31, 1998                      59
       Notes to Consolidated Financial Statements                 61
       Selected Quarterly Financial Data (Unaudited)              98

II - Schedule II - Reserves

            All other  schedules are omitted  because they are not applicable or
the required  information is shown in the Consolidated  Financial  Statements or
the Notes thereto.

SUPPLEMENTARY DATA

            Supplementary data is included in "Selected Quarterly Financial Data
(Unaudited)" referred to in I above and reference is made thereto.

                                      51


<PAGE>



REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of Central Hudson Gas
& Electric Corporation

In our opinion, the consolidated financial statements listed in the accompanying
index  present  fairly,  in all material  respects,  the  financial  position of
Central Hudson Gas & Electric  Corporation and its  subsidiaries at December 31,
1998 and 1997, and the results of their operations and their cash flows for each
of the three years in the period ended  December 31, 1998,  in  conformity  with
generally accepted  accounting  principles.  These financial  statements are the
responsibility of the Company's management;  our responsibility is to express an
opinion on these  financial  statements  based on our audits.  We conducted  our
audits of these  financial  statements in  accordance  with  generally  accepted
auditing  standards  which  require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement.  An audit includes examining, on a test basis, evidence supporting
the  amounts  and  disclosures  in  the  financial  statements,   assessing  the
accounting  principles  used and significant  estimates made by management,  and
evaluating the overall  financial  statement  presentation.  We believe that our
audits provide a reasonable basis for the opinion expressed above.

PRICEWATERHOUSECOOPERS LLP

New York, New York
January 29, 1999

                                      52


<PAGE>



STATEMENT OF MANAGEMENT'S RESPONSIBILITY

Management is responsible for the preparation,  integrity and objectivity of the
consolidated  financial  statements of Central Hudson Gas & Electric Corporation
and  its  subsidiaries  (collectively,   the  Company)  as  well  as  all  other
information  contained  in this Form 10-K  Report.  The  consolidated  financial
statements have been prepared in conformity with generally  accepted  accounting
principles  and, in some cases,  reflect amounts based on the best estimates and
judgements of the Company's Management, giving due consideration to materiality.

The Company maintains adequate systems of internal control to provide reasonable
assurance,  that,  among other things,  transactions  are executed in accordance
with Management's authorization,  that the consolidated financial statements are
prepared in accordance with generally  accepted  accounting  principles and that
the assets of the  Company  are  properly  safeguarded.  The systems of internal
control are documented,  evaluated and tested by the Company's internal auditors
on a continuing  basis. Due to the inherent  limitations of the effectiveness of
internal  controls,  no internal control system can provide  absolute  assurance
that errors will not occur.  Management believes that the Company has maintained
an effective  system of internal  control over the  preparation of its financial
information including the consolidated financial statements of the Company as of
December 31, 1998.

Independent  accountants  were  engaged  to  audit  the  consolidated  financial
statements  of the  Company  and  issue  their  report  thereon.  The  Report of
Independent   Accountants,   which  is  presented  above,  does  not  limit  the
responsibility  of  Management  for  information  contained in the  consolidated
financial statements and elsewhere in this Form 10-K Report.

The  Company's  Board of  Directors  maintains  a  Committee  on Audit  which is
composed of Directors  who are not  employees of the Company.  The  Committee on
Audit meets with Management,  its Internal Auditing Manager, and its independent
accountants  several times a year to discuss  internal  controls and  accounting
matters, the Company's consolidated financial statements,  the scope and results
of the  audits  performed  by the  independent  accountants  and  the  Company's
Internal  Auditing  Department.  The  independent  accountants and the Company's
Internal Auditing Manager have direct access to the Committee on Audit.

John E. Mack III                             DONNA S. DOYLE
Chairman of the Board                        Controller

                                        January 29, 1999

                                      53


<PAGE>



CONSOLIDATED BALANCE SHEET
(In Thousands)
                                                        December 31,
ASSETS                                                1998            1997
                                                      ----            ----
Utility Plant
  Electric...............................          $1,222,743     $1,193,735
  Gas....................................             158,165        151,222
  Common.................................              94,271         91,522
  Nuclear fuel...........................              42,317         37,262
                                                    ---------      ---------
                                                    1,517,496      1,473,741

  Less: Accumulated depreciation.........             597,383        560,304
        Nuclear fuel amortization........              35,381         33,059
                                                    ---------      ---------
                                                      884,732        880,378

  Construction work in progress..........              43,512         52,413
                                                    ---------      ---------
    Net Utility Plant....................             928,244        932,791
                                                    ---------      ---------

Other Property and Plant.................              19,059          1,089
                                                    ---------      ---------

Investments and Other Assets
  Prefunded pension costs................              40,218         23,536
  Other..................................              18,209         13,869
                                                    ---------      ---------
    Total Investments and Other Assets...              58,427         37,405
                                                    ---------      ---------
Current Assets
  Cash and cash equivalents..............              10,499          9,054
  Accounts receivable from customers -
   net of allowance for doubtful accounts;
   $2.4 million in 1998 and $2.8 million
   in 1997...............................              45,564         49,643
  Accrued unbilled utility revenues......              15,233         16,229
  Other receivables......................               4,555          2,073
  Materials and supplies, at average cost:
    Fuel.................................              11,797         11,920
    Construction and operating...........              11,790         12,180
  Special deposits and prepayments.......              34,823         14,210
                                                    ----------     ---------
    Total Current Assets.................             134,261        115,309
                                                    ----------     ---------
Deferred Charges
  Regulatory assets (Note 2).............             149,261        139,236
  Unamortized debt expense...............               5,062          5,002
  Other..................................              21,724         21,258
                                                   ----------     ----------
    Total Deferred Charges...............             176,047        165,496
                                                   ----------     ----------

           TOTAL ASSETS                            $1,316,038     $1,252,090
                                                    =========      =========


The Notes to Consolidated Financial Statements are an integral part hereof.

                                      54


<PAGE>



CONSOLIDATED BALANCE SHEET  (CONT'D)
(In Thousands)

                                                          December 31,
CAPITALIZATION AND LIABILITIES                        1998           1997
                                                      ----           ----
Capitalization
 Common Stock Equity
   Common stock, $5 par value (Note 6)...          $   87,775     $   87,775
   Paid-in capital (Note 6)..............             284,465        284,465
   Retained earnings.....................             133,287        120,540
   Reacquired capital stock (Note 6).....             (27,143)       (9,398)
   Capital stock expense.................              (6,204)       (6,278)
                                                    ---------      --------
    Total Common Stock Equity............             472,180        477,104
                                                    ---------      ---------
 Cumulative Preferred Stock (Note 6)
   Not subject to mandatory redemption...              21,030         21,030
   Subject to mandatory redemption.......              35,000         35,000
                                                    ---------      ---------
    Total Cumulative Preferred Stock.....              56,030         56,030
                                                    ---------      ---------

 Long-term Debt (Note 7).................             356,918        361,829
                                                    ---------      ---------

    Total Capitalization.................             885,128        894,963
                                                    ---------      ---------

Current Liabilities
 Current maturities of long-term debt....              39,507          1,317
 Notes payable...........................              18,000              -
 Accounts payable........................              23,591         24,368
 Dividends payable.......................               9,913         10,052
 Accrued taxes and interest..............               6,334          3,240
 Accrued vacation .......................               4,400          4,339
 Customer deposits.......................               4,248          4,001
 Other...................................               7,932          6,545
                                                    ---------      ---------
    Total Current Liabilities............             113,925         53,862
                                                    ---------      ---------

Deferred Credits and Other Liabilities
 Regulatory liabilities (Note 2).........              81,065         81,271
 Operating reserves......................               5,995          6,582
 Other...................................              27,251         10,019
                                                    ---------      ---------
  Total Deferred Credits and
   Other Liabilities.....................             114,311         97,872
                                                    ---------      ---------

Deferred Income Tax (Note 4).............             202,674        205,393
                                                    ---------      ---------
Commitments and contingencies
  (Notes 2, 3 and 9).....................

 TOTAL CAPITALIZATION AND LIABILITIES              $1,316,038     $1,252,090
                                                    =========      =========

The Notes to Consolidated Financial Statements are an integral part hereof.

                                      55


<PAGE>



CONSOLIDATED STATEMENT OF INCOME
(In Thousands)


                                                 Year ended December 31,
                                            1998          1997           1996
                                            ----          ----           ----
Operating Revenues
  Electric.........................      $418,507       $416,429       $418,761
  Gas..............................        84,962        103,848         95,210
                                          -------        -------        -------
    Total Operating Revenues.......       503,469        520,277        513,971
                                          -------        -------        -------

Operating Expenses
 Operation:
  Fuel used in electric
   generation.......................       84,688         66,117         58,874
  Purchased electricity.............       40,573         55,864         55,523
  Purchased natural gas.............       44,964         61,514         50,636
  Other expenses of operation              96,247        101,219        102,746
 Maintenance........................       26,904         27,574         28,938
 Depreciation and amortization
 (Note 1)...........................       45,560         43,864         42,580
 Taxes, other than income
  tax...............................       63,458         64,879         66,145
 Federal income tax
 (Note 4)............................      29,775         29,190         32,700
                                          -------        -------        -------
    Total Operating Expenses.........     432,169        450,221        438,142
                                          -------        -------        -------

Operating Income.....................      71,300         70,056         75,829
                                          -------        -------        -------
Other Income
  Allowance for equity funds
   used during construction
   (Note 1)..........................         585            387            466
  Federal income tax (Note 4)               1,148          2,953          1,632
  Other - net........................       6,865          8,079          4,815
                                          -------        -------        -------
    Total Other Income...............       8,598         11,419          6,913
                                          -------        -------        -------
Income before Interest
  Charges............................      79,898         81,475         82,742
                                          -------        -------        -------











The Notes to Consolidated Financial Statements are an integral part hereof.

                                      56


<PAGE>



CONSOLIDATED STATEMENT OF INCOME (CONT'D)
(In Thousands)

                                                  Year ended December 31,
                                            1998          1997          1996
                                            ----          ----          ----
Interest Charges
 Interest on long-term debt..........      23,115         23,097        23,617
 Other interest......................       3,639          2,647         2,626
 Allowance for borrowed
  funds used during
  construction (Note 1)..............        (324)          (261)         (523)
 Amortization of expense on
  debt...............................         924            906           940
                                          -------        -------       -------
   Total Interest Charges............      27,354         26,389        26,660
                                          -------        -------       -------

Net Income...........................      52,544         55,086        56,082

Premium on Preferred Stock
  Redemptions-Net....................           -              -           378
Dividends Declared on Cumul-
 ative Preferred Stock...............       3,230          3,230         3,230
                                          -------        -------       -------
Income Available for
 Common Stock........................    $ 49,314       $ 51,856      $ 52,474
                                          =======        =======       =======
Common Stock:
  Average shares outstanding
  (000s).............................      17,034         17,435         17,549
  Earnings per share on
   average shares outstanding........       $2.90          $2.97          $2.99














The Notes to Consolidated Financial Statements are an integral part hereof.

                                      57


<PAGE>



CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(In Thousands)
                                                   Year ended December 31,
                                             1998          1997           1996
                                             ----          ----           ----

Balance at beginning of year.........    $120,540       $105,821       $ 90,475

Net Income...........................      52,544         55,086         56,082
Premium on preferred stock
  redemption-net.....................        -              -               378

Dividends declared:
  On cumulative preferred
   stock.............................       3,230          3,230          3,230
  On common stock ($2.155 per
   share 1998; $2.135 per
   share 1997 $2.115 per
   share 1996).......................      36,567         37,137         37,128
                                          -------        -------        -------

     Total dividends declared........      39,797         40,367         40,358
                                          -------        -------        -------

Balance at end of year...............    $133,287       $120,540       $105,821
                                          =======        =======        =======












The Notes to Consolidated Financial Statements are an integral part hereof.

                                      58


<PAGE>



CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands)                                  Year ended December 31,
                                           1998           1997          1996
                                           ----           ----          ----
Operating Activities
  Net Income ........................    $ 52,544      $ 55,086       $ 56,082
  Adjustments to reconcile net
      income to net cash provided
      by operating activities:
       Depreciation and amortization
         including nuclear fuel
         amortization................      49,011        48,348         47,073
     Deferred income taxes...........        (116)       14,077         17,848
     Allowance for equity funds used
       during construction...........        (585)         (387)          (466)
     Nine Mile 2 Plant deferred
       finance charges, net..........      (4,855)       (4,855)        (4,855)
     Provisions for uncollectibles...       2,639         3,493          4,336
     Accrued pension costs...........     (12,277)       (8,555)        (6,757)
      Deferred gas costs.............       1,072          3,475        (4,861)
      Deferred gas refunds...........      (1,640)         1,695        (1,556)
     Other - net.....................       4,888          7,233         4,039
  Changes in current assets and
   liabilities, net:
     Accounts receivable and unbilled
       utility revenues..............         (46)        (4,420)       (6,338)
     Materials and supplies..........         513          3,995          (505)
     Special deposits and
       prepayments...................     (20,613)          (770)         (781)
     Accounts payable................        (777)        (1,769)        1,704
     Accrued taxes and interest......       3,094         (2,107)       (2,477)
     Other current liabilities.......       1,695            (61)          602
                                         --------        --------       -------
  Net cash provided by operating
   activities........................      74,547        114,478       103,088
                                         --------        -------       -------
















The Notes to Consolidated Financial Statements are an integral part hereof.

                                      59


<PAGE>



CONSOLIDATED STATEMENT OF CASH FLOWS (CONT'D)
(In Thousands)                             1998            1997          1996
                                           ----            ----          ----
Investing Activities
  Additions to plant.................   (45,661)         (43,868)      (49,860)
  Allowance for equity funds used
   during construction...............       585              387           466
                                       --------          -------       -------
  Net additions to plant.............   (45,076)         (43,481)      (49,394)
  Subsidiaries' fixed asset
   additions.........................   (19,460)             -             -
  Nine Mile 2 Plant decommissioning
   trust fund........................      (868)            (868)       (1,008)
  Other - net........................      (801)             396          (526)
                                       --------          -------       -------
  Net cash used in investing
   activities........................   (66,205)         (43,953)      (50,928)
                                       --------          -------       -------
Financing Activities
  Proceeds from issuance of:
    Long-term debt...................    35,250            2,000         3,090
    Common stock.....................       -                -           1,817
  Net borrowings (repayments) of
   short-term debt...................    18,000          (15,600)       15,600
  Retirement & redemption
   of long-term debt.................    (2,466)          (2,282)      (30,779)
  Retirement & redemption of
   cumulative preferred stock........       -                -         (13,000)
  Premium on preferred stock
   redemption........................       -                -            (378)
  Dividends paid on cumulative
   preferred and common stock........   (39,936)        (40,426)       (40,489)
  Issuance and redemption costs......       -               -              736
  Reacquired capital stock...........   (17,745)         (9,398)           -
                                       --------         -------        -------
  Net cash used in financing
   activities........................    (6,897)        (65,706)       (63,403)
                                       --------         -------        -------


Net Change in Cash and Cash
 Equivalents.........................     1,445           4,819         (11,243)
Cash and Cash Equivalents at
 Beginning of Year...................     9,054           4,235          15,478
                                       --------         -------         -------
Cash and Cash Equivalents at End
 of Year.............................  $ 10,499        $  9,054        $  4,235
                                        =======         =======         =======
Supplemental Disclosure of Cash
 Flow Information
    Interest paid....................  $ 24,002        $ 24,309        $ 25,184
    Federal income taxes paid........    26,900          17,111          15,875


The Notes to Consolidated Financial Statements are an integral part hereof.

                                      60


<PAGE>



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

            The  consolidated  financial  statements  include  the  accounts  of
Central Hudson Gas & Electric Corporation (the "Company"), and its subsidiaries.
Intercompany balances and transactions have been eliminated.

            The Company's  subsidiaries  are each directly or indirectly  wholly
owned  and are  comprised  of  landholding,  cogeneration,  fuel  oil,  electric
generating  or energy  management  companies.  The net  income of the  Company's
subsidiaries  is  reflected  in the  Consolidated  Statement  of Income as other
non-operating income.

            Effective   April  24,  1998,  the  Company  formed  a  wholly-owned
subsidiary  named CH  Energy  Group,  Inc.,  which,  after a  one-for-one  share
exchange, will become the holding company parent of the Company and its existing
subsidiaries (with the exception of Phoenix Development Company, Inc.). See Note
2 - "Regulatory Matters," under the caption "Holding Company  Restructuring" for
further details.

RATES, REVENUES AND COST ADJUSTMENT CLAUSES

            Electric  and gas retail rates are  regulated by the Public  Service
Commission  of the State of New York  ("PSC").  Transmission  rates,  facilities
charges and rates for  electricity  sold for resale in  interstate  commerce are
regulated by the Federal Energy Regulatory Commission ("FERC").

            Revenues  are  recognized  on the basis of cycle  billings  rendered
monthly or bimonthly.  Estimated revenues are accrued for those customers billed
bimonthly whose meters are not read in the current month.

            The Company's  tariff for retail  electric  service  includes a fuel
cost adjustment  clause pursuant to which electric rates are adjusted to reflect
changes in the average cost of fuels used for electric generation and in certain
purchased  power costs,  from the average of such costs  included in base rates.
The Company's tariff for gas service contains a comparable  clause to adjust gas
rates for changes in the price of purchased natural gas.

UTILITY PLANT

            The costs of additions to utility plant and  replacements of retired
units of property are  capitalized at original cost. The Company's  share of the
costs of Unit No. 2 of the Nine Mile Point Nuclear Station ("Nine Mile 2") Plant
are capitalized at original cost, less the disallowed investment of

                                      61


<PAGE>



$169.3  million which was recorded in 1987.  Capitalized  costs  include  labor,
materials  and  supplies,  indirect  charges  for such items as  transportation,
certain taxes,  pension and other employee benefits,  and Allowance for the Cost
of Funds Used During  Construction  ("AFDC"),  a non-cash  item.  Replacement of
minor items of property is included in maintenance expenses.

            The original  cost of property,  together  with removal  cost,  less
salvage, is charged to accumulated  depreciation at such time as the property is
retired and removed from service.

JOINTLY OWNED FACILITIES

            The Company has a 9%, or 103 megawatt ("MW"),  undivided interest in
the 1,143 MW Nine Mile 2 Plant (see Note 3 - "Nine Mile 2 Plant")  and a 35%, or
420 MW, undivided  interest in the 1,200 MW Roseton Electric  Generating Station
("Roseton Plant").

            The Company's share of the respective investments in the Nine Mile 2
Plant and the Roseton Plant,  as included in its  Consolidated  Balance Sheet at
December 31, 1998 and 1997, were:

                                                  1998               1997
                                                  ----               ----
                                                       (In Thousands)
      Nine Mile 2 Plant
       Plant in service...................     $315,358           $316,123
       Accumulated depreciation...........      (77,178)           (70,202)
       Construction work in progress......        2,132              1,032
     Roseton Plant
       Plant in service...................     $135,197           $134,555
       Accumulated depreciation...........      (80,486)           (77,438)
       Construction work in progress......          213                571

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION

            The  Company's  regulated  utility  plant  includes  AFDC,  which is
defined in applicable  regulatory systems as the net cost of borrowed funds used
for construction purposes and a reasonable rate on other funds when so used. The
concurrent  credit for the amount so capitalized is reported in the Consolidated
Statement  of Income as follows:  the portion  applicable  to borrowed  funds is
reported as a reduction  of interest  charges  while the portion  applicable  to
other funds (the equity component,  a noncash item) is reported as other income.
The AFDC rate was 8.5% in 1998 and 8.0% in 1997 and 7.5% in 1996.

            For a  discussion  of the  effect  of  the  Statement  of  Financial
Accounting  Standards  No. 71,  "Accounting  for the Effects of Certain Types of
Regulation  ("SFAS 71"), as issued by the Financial  Accounting  Standards Board
("FASB"),  on  the  Company's  fossil-fueled   generating  plants,  see  Note  2
"Regulatory  Matters," under the caption "Impact of Amended Settlement Agreement
on Accounting  Policies."  Accordingly,  beginning in 1998,  significant capital
projects relating to the

                                      62


<PAGE>



fossil-fueled  generating plants include  capitalized  interest instead of AFDC.
For 1998 no such projects met the criteria for capitalized interest.

DEPRECIATION AND AMORTIZATION

            For  financial  statement  purposes,   the  Company's   depreciation
provisions are computed on the straight-line method using rates based on studies
of the estimated  useful lives and  estimated  net salvage value of  properties,
with the exception of the Nine Mile 2 Plant which is  depreciated on a remaining
life  amortization  method.  The year 2026,  which is the year in which the Nine
Mile 2  Plant  operating  license  expires,  is  used  as the  end  date  in the
development  of  the  remaining   life   amortization.   The  Company   performs
depreciation  studies on a  continuing  basis  and,  upon  approval  by the PSC,
periodically adjusts the rates of its various classes of depreciable property.

            The Company's  composite rates for  depreciation  were 3.2% in 1998,
3.16% in 1997 and  3.13% in 1996 of the  original  cost of  average  depreciable
property.  The ratio of the amount of  accumulated  depreciation  to the cost of
depreciable  property at December 31 was 39.6% in 1998,  38.2% in 1997 and 36.5%
in 1996.

            For federal  income tax  purposes,  the Company uses an  accelerated
method of  depreciation  and generally uses the shortest life permitted for each
class of assets.

            The  cost of the  Nine  Mile 2 Plant  nuclear  fuel  assemblies  and
components  is  amortized  to  operating  expense  based on the quantity of heat
produced for the generation of electric energy.

CASH AND CASH EQUIVALENTS

            For  purposes  of the  Consolidated  Statement  of Cash  Flows,  the
Company  considers  temporary cash investments with a maturity when purchased of
three months or less to be cash equivalents.

FEDERAL INCOME TAX

            The Company and its  wholly-owned  subsidiaries  file a consolidated
federal  income tax return.  Federal  income  taxes are  allocated  to operating
expenses  and other  income and  deductions  in the  Consolidated  Statement  of
Income.  Federal  income  taxes  are  deferred  under  the  liability  method in
accordance with Financial  Accounting  Standard No. 109,  "Accounting for Income
Taxes,"  ("SFAS 109").  Under the liability  method,  deferred  income taxes are
provided for all differences between financial statement and tax basis of assets
and  liabilities.  Additional  deferred  income taxes and offsetting  regulatory
assets or  liabilities  are  recorded to  recognize  that  income  taxes will be
recoverable or refundable through future revenues.

                                      63


<PAGE>



USE OF ESTIMATES

            Preparation of the financial statements in accordance with generally
accepted accounting  principles includes the use of estimates and assumptions by
management  that  affect the  reported  amounts of assets  and  liabilities  and
disclosures  of contingent  assets and  liabilities at the date of the financial
statements  and reported  amount of revenues and expenses  during the  reporting
period. Actual results may differ from those estimates.

NEW ACCOUNTING STANDARDS AND OTHER FASB PROJECTS

            Derivatives  and Hedging  Accounting:  In June 1998, the FASB issued
Statement of Financial  Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging  Activities"  ("SFAS 133").  This Statement  establishes
accounting and reporting  standards for derivative  instruments  and for hedging
activities.  It requires  that an entity  recognize  all  derivatives  as either
assets or liabilities in the balance sheet and measure those instruments at fair
value. Any gain or loss resulting from changes in such fair value is required to
be  recognized  in earnings to the extent the  derivatives  are not effective as
hedges.  SFAS 133 is effective for fiscal years  beginning  after June 15, 1999,
and is  effective  for interim  periods in the  initial  year of  adoption.  The
Company currently does not own any derivative instruments;  however, the Company
intends to implement an energy trading risk management program in 1999 to manage
the price risks  associated  with fuel  purchases  for  generation,  natural gas
purchases for native load  customers,  and  wholesale  power  transactions.  The
Company may utilize various  financial  instruments,  such as futures,  options,
swaps,  caps,  floors,  and collars to stabilize  the price  volatility of these
commodities.  At this time,  the  Company  cannot  assess  the  impact  that the
proposed  hedging  program  would have on its  financial  position or results of
operations.

            Plant Decommissioning: In February 1996, the FASB issued an exposure
draft  entitled  "Accounting  for  Certain  Liabilities  Related to Closure  and
Removal of Long-Lived  Assets,"  which includes  nuclear plant  decommissioning.
Over the past two years,  this  exposure  draft has been the source of continual
debate.  The FASB has  committed  to  completing  the project and is  proceeding
toward  issuance of another  exposure  draft  (expected in the second quarter of
1999). If the accounting  standard proposed in such exposure draft were adopted,
it could result in higher annual provisions for removal or decommissioning to be
recognized  earlier in the operating life of nuclear and other  generating units
and an accelerated  recognition of the decommissioning  obligation.  The FASB is
continuing to explore  various  issues  associated  with this project  including
liability measurement and recognition issues. In addition, an effective date for
the new

                                      64


<PAGE>



exposure draft has not yet been determined.  The FASB is deliberating this issue
and the resulting final  pronouncement  could be different from that proposed in
the exposure  draft.  The Company can make no  prediction at this time as to the
ultimate form of such proposed accounting standard,  assuming it is adopted, nor
can it  make  any  prediction  as to its  ultimate  effect(s)  on the  financial
condition of the Company.

NOTE 2 - REGULATORY MATTERS

COMPETITIVE OPPORTUNITIES PROCEEDING SETTLEMENT AGREEMENT

            In  response  to the May 1996 Order of the PSC issued in its generic
Competitive Opportunities Proceeding ("Proceeding"),  the Company, the PSC Staff
and  certain  other  parties  entered  into an Amended and  Restated  Settlement
Agreement, dated January 2, 1998, ("Agreement").  The PSC approved the Agreement
by its final Order issued and effective June 30, 1998.

            Shortly  after the PSC issued its May 1996  Order,  the  Company and
other electric utilities filed a court challenge to such Order. In addition, the
Public  Utility Law Project  ("PULP") filed a similar  appeal.  Both appeals are
stayed at this time.  Subsequently,  in December 1998,  PULP filed an additional
appeal  with  respect  to  such  Order  approving  the  Company's  restructuring
settlement.  The Company has moved to dismiss  this  second  appeal.  The matter
remains  pending at this time and the Company can make no  prediction  as to the
potential outcome of these matters.

            The  Agreement  generally  includes the  following  provisions:  (i)
continuation  of a basic  electric rate freeze,  along with a phase-in of retail
access, for residential,  commercial and small industrial customers through June
2001; (ii) a 5% reduction in base electric rates for large industrial customers;
(iii) a 10.6%  return  on  equity  ("ROE")  cap with  excess  earnings,  if any,
deferred  for stranded  cost  mitigation  (at  December  31,  1998,  the Company
recorded an estimated  regulatory liability of $651,000 due to excess earnings);
(iv) a  reasonable  opportunity  to recover all  prudently  incurred  strandable
costs, defined as "production expenditures of the company made in fulfilling its
obligation to serve and provide  safe,  reliable  electric  service to customers
within its franchise  territory  which are not expected to be  recoverable  in a
competitive  electricity  market";  (v)  functional  separation of the Company's
Danskammer Steam Generating Station ("Danskammer Plant") and its interest in the
Roseton  Plant in 1998;  (vi)  transfer of title by an auction of the  Company's
Danskammer  Plant and its interest in the Roseton  Plant to be completed by June
30,  2001,  (an  affiliate  of the Company  can bid,  and the PSC  reserved  its
authority  to require an auction  and  transfer of the  Company's  fossil-fueled
electric generating assets prior to June 30, 2001 if such action is found by the
PSC to be in the public  interest);  (vii) approval to effect a holding  company
restructuring not later than June 30,

                                      65


<PAGE>



2001,  which holding company  initially would own the Company and all but one of
the Company's existing wholly-owned subsidiaries;  and (viii) permission for the
Company to transfer up to $100 million of equity from the Company to unregulated
affiliates prior to such holding company restructuring.

            In addition,  the PSC  directed  the PSC Staff to provide  assurance
that the  Company  does not incur  imprudent  generation  costs  which  could be
avoided by divestiture of fossil-fueled electric generating assets prior to June
30, 2001, and added a provision dealing with mergers and  acquisitions;  namely,
pursuant to a petition filed jointly or individually by the Company, the Company
will  have the  flexibility  to  retain,  on a  cumulative  basis,  all  savings
associated  with an acquisition  or merger with another  utility for a period of
five  years from the date of  closing  of any  merger or  acquisition  up to the
amount of the  acquisition  premium  paid over the  lesser of book value or fair
market value of assets merged or acquired, and savings in excess of the recovery
will be disposed of by the PSC.

            The consideration received by the Company in an auction, referred to
in (vi) of the second preceding paragraph above, would, up to the net book value
of the assets sold,  be  available  for  investment  in  unregulated  operations
without PSC approval. Any excess over such net book value will be required to be
used to offset the Company's fossil-fueled  generation related regulatory assets
and, to the extent of any  remaining  consideration,  to reduce the book cost of
the Company's  investment  in the Nine Mile 2 Plant.  In the event that the sale
price of any such assets is below the Company's then current net book value, the
difference  will be preserved  for recovery as strandable  costs.  The Company's
potential  strandable costs are those prior utility  investments and commitments
that may not be recoverable in a competitive energy market. Examples include any
unrecovered cost of the Company's  fossil-fueled  generating  plants  (resulting
from the auction process) and net generation related  regulatory assets.  During
the period  ending  June 30,  2001,  the  Company  will  continue to recover its
potential electric strandable costs in the rates it charges its transmission and
distribution  customers.  Following  June  2001,  the  Company  will be  given a
reasonable  opportunity  to  recover,   through  a  non-  bypassable  charge  to
customers,  all  prudently  incurred,  verifiable  and  appropriately  mitigated
electric strandable costs. The net book value of the Company's fossil generating
assets at December 31, 1998, represented approximately 18% of net utility plant.

            In the event that no Company affiliate elects to bid in its auction,
the Company will retain, prior to application of the consideration  described in
the immediately  preceding paragraph,  10% of the proceeds in excess of the book
value of the Company's  fossil-fueled  generation  assets,  not to exceed in the
aggregate $17.5 million.

          After  such  divestiture,  the  Company  expects  to be  obligated  to
continue to serve a portion of its electric

                                      66


<PAGE>



customers.  The Company  cannot predict the amount of such service which it will
be obligated to provide or the cost or  availability  of  electricity to satisfy
its service obligations.

HOLDING COMPANY RESTRUCTURING

            Effective   April  24,  1998,  the  Company  formed  a  wholly-owned
subsidiary  named  CH  Energy  Group,  Inc.  which,  after a  one-for-one  share
exchange,  will  become the holding  company  parent of the Company and its then
existing  subsidiary  companies  (with  the  exception  of  Phoenix  Development
Company,  Inc.). The Company has received  approval from its  shareholders,  the
PSC,  the FERC,  and the  Nuclear  Regulatory  Commission  ("NRC")  to form such
holding  company.  While no specific date has been  established,  it is expected
that the  holding  company  restructuring  will occur some time during the first
half of 1999.  This will  allow the  Company  to  coordinate  closely  with such
restructuring the transfer of up to $100 million in equity (as authorized by the
PSC under the Agreement)  from the Company to unregulated  operations,  of which
approximately  $25.5  million  has been  transferred  as of December  31,  1998.
Initially,  the holding company (CH Energy Group,  Inc.) will own, as first tier
subsidiaries,  the Company and its  existing  subsidiaries,  as described in the
subcaption  "Affiliates"  under the caption in Item 1 "Other Matters",  with one
exception:  Phoenix  Development  Company,  Inc.,  which holds real property for
future use,  will remain a  wholly-owned  subsidiary  of the Company.  CH Energy
Group, Inc., following the share exchange, may also establish other subsidiaries
over time.

IMPACT OF AMENDED SETTLEMENT AGREEMENT ON ACCOUNTING POLICIES

            The Agreement  created certain  changes to the Company's  accounting
policies.  The  Company's  accounting  policies  conform to  generally  accepted
accounting principles,  which, for regulated public utilities,  include SFAS 71.
Under  SFAS 71,  regulated  companies  apply  AFDC to the  cost of  construction
projects.  Because the Company's  fossil-fueled  generating plants are no longer
subject to SFAS 71, capitalized  interest will be applied instead of AFDC. Under
SFAS 71,  regulated  companies  defer costs and credits on the balance  sheet as
regulatory  assets and  liabilities  when it is  probable  that those  costs and
credits will be allowed in the  rate-making  process in a period  different from
when they  otherwise  would  have  been  reflected  in  income.  These  deferred
regulatory  assets and liabilities are then reflected in the income statement in
the  period in which the same  amounts  are  reflected  in rates.  If some of an
enterprise's operations are regulated and meet the appropriate criteria, SFAS 71
is applied only to the regulated portion of the enterprise's operations.

            During 1997, the FASB Emerging Issues Task Force ("EITF")  concluded
that an entity should discontinue  application of SFAS 71, to any portion of its
business when a deregulation

                                      67


<PAGE>



transition plan is in place and the terms are known.  However,  the EITF further
qualified,  in its Issue No. 97-4, that regulatory assets and liabilities should
be  evaluated  based  on  where  the  cash  flows  are  to  be  derived  in  the
determination  of the  applicability  of SFAS 71.  When the cash  flows are from
rates to be charged to  customers  of the  regulated  business  for recovery and
settlement,  respectively, of regulatory assets and liabilities, they should not
be eliminated until: a) they are recovered or settled through the regulated cash
flows,  or b) they are  individually  impaired or the regulator  eliminates  the
individual  obligation or c) the portion of the business providing the regulated
cash flows no longer meets the criteria of SFAS 71. None of these conditions has
occurred  as it applies to the  Company's  fossil-fueled  generation  regulatory
assets and  liabilities  even though the Agreement put into place a deregulation
transition plan with the ultimate goal of divesting the Company's  fossil-fueled
generating plant assets.  Therefore,  these balances continue to be reflected in
the total for regulatory  assets and  liabilities in the Company's  consolidated
balance sheet. At December 31, 1998, and 1997, net regulatory  assets associated
with the fossil-fueled generating assets totalled $6.5 million and $7.6 million,
respectively.

                                      68


<PAGE>



SUMMARY OF REGULATORY ASSETS AND LIABILITIES

            The following table sets forth the Company's  regulatory  assets and
liabilities:

At December 31,                                        1998         1997
Regulatory Assets (Debits):                            ----         ----
---------------------------                              (In Thousands)
Deferred finance charges -
  Nine Mile 2 Plant......................           $  67,326     $  68,470
Income taxes recoverable
  through future rates....................             35,221        49,220
Deferred Newburgh Gas Site (Note 9).......             22,679         2,195
Other.....................................             24,035        19,351
                                                     --------      --------
  Total Regulatory Assets.................          $ 149,261     $ 139,236
                                                     --------      --------
Regulatory Liabilities (Credits):
---------------------------------
Deferred finance charges -
  Nine Mile 2 Plant.......................          $  10,431     $  16,431
Income taxes refundable...................             17,574        28,516
Deferred Nine Mile 2 Plant costs..........             15,790        11,296
Deferred pension costs overcollection
 (Note 8).................................             11,693         8,306
Deferred OPEB costs overcollection
 (Note 8).................................              9,796         6,824
Customer benefits account.................              5,447          -
Other.....................................             10,334         9,898
                                                     --------      --------
  Total Regulatory Liabilities............             81,065        81,271
                                                     --------      --------
     Net Regulatory Assets................          $  68,196     $  57,965
                                                     ========      ========

            Some of the significant regulatory assets and liabilities include:

            Deferred   Finance   Charges  -  Nine  Mile  2  Plant:   During  the
construction of the Nine Mile 2 Plant,  the PSC authorized the inclusion in rate
base of  increasing  amounts of the  Company's  investment  in that  Plant.  The
Company did not accrue AFDC on any of the Nine Mile 2 Plant construction work in
progress  ("CWIP")  which was  included in rate base and for which a cash return
was being allowed;  however,  the PSC ordered,  effective  January 1, 1983, that
amounts be accumulated in deferred debit and credit accounts equal to the amount
of AFDC which was not being  accrued on the CWIP  included in rate base ("Mirror
CWIP"). The balance in the deferred credit account is available to reduce future
revenue  requirements  by  amortizing  portions of the deferred  credit to other
income or by the  elimination  through  writing off other  deferred  balances as
directed by the PSC. The Company expects such application of the deferred credit
will occur over a period substantially  shorter than the life of the Nine Mile 2
Plant. When amounts of such deferred credit are applied in order

                                      69


<PAGE>



to reduce  revenue  requirements,  amortization  is started for a  corresponding
amount of the deferred debit, which amortization continues on a level basis over
the  remaining  life of the Nine  Mile 2 Plant  resulting  in  recovery  of such
corresponding  amount through rates.  Mirror CWIP is expected to be exhausted by
the  end of the  useful  life  of the  Nine  Mile 2  Plant  either  through  the
amortization or write-off procedures described above or through the write-off of
the  remaining  debit and credit as directed by the PSC.  The net effect of this
procedure is that at the end of the amortization period for the deferred credit,
the accounting and rate-making  treatment will be the same as if the Nine Mile 2
Plant CWIP had not been included in rate base during the construction period.

            Pursuant to a PSC Order issued and  effective  February 11, 1994, in
an electric rate  proceeding,  the Company was authorized to amortize $6 million
annually of the deferred credit beginning in December 1993.

            The $6 million amortization of the deferred credit will be continued
unless  changed  by a future  PSC rate  order  or until it is  exhausted.  Under
provisions  of the  Agreement,  this  amortization  will be replaced  with other
deferred  credits to the extent necessary to provide for full replacement of the
expiring  Mirror  CWIP  credits.   The  current  level  of  the  deferred  debit
amortization of $1.1 million is based on the level of deferred credits that have
been  utilized  through  the most  recent  rate year.  Credit  amounts  utilized
subsequently are included in the deferred debit  amortization  level at the time
of the next PSC rate  order  for the new rate year  based on the then  remaining
life of the Nine Mile 2 Plant.

            Income  Taxes  Recoverable/refundable:  The  adoption of SFAS 109 in
1993 increased the Company's net deferred tax obligation. As it is probable that
the increase will be recovered  from  customers,  the Company  established a net
regulatory asset for the recoverable future taxes.

            Deferred Nine Mile 2 Plant Costs:  The existing  rate-making for the
Nine Mile 2 Plant,  as directed by the PSC in its Order on Nine Mile 2 Operating
and Capital Forecast for 1996 ("Supplement No. 5"), provides for the deferral of
the difference between actual and authorized  operating and maintenance expense.
Supplement  No. 5 continues in effect until changed by a subsequent  rate order.
For 1998 and 1997,  the Nine Mile 2 Plant  incurred  less  actual  expense  than
authorized,  and the Company's share has been recorded as a regulatory liability
in accordance with Supplement No. 5.

            Customer Benefits Account:  The Agreement  requires that the Company
set aside $10.0 million per calendar year in a Customer Benefits Account to fund
rate reductions and retail access options.  Funding sources include $3.0 million
from shareholder sources, $3.5 million from fuel cost savings

                                      70


<PAGE>



generated by the  installation of the Company's coal dock unloading  facility at
its  Danskammer  Plant and $3.5 million  from  deferred  credits  related to the
reconciliation  of pension and OPEB costs.  The Agreement also  stipulates  that
unused  funding  accumulated  to the end of the Agreement term is to be used for
offsetting strandable costs or providing other ratepayer benefits.

AUCTION OF FOSSIL GENERATION PLANTS

            Under the  Agreement,  the  Company is  required  to sell its fossil
generation  plants and transfer title by June 30, 2001. The Company has provided
for the necessary  internal and external resources to carry out the auction that
is called for in the Agreement.  An auction plan is being developed for approval
by the PSC. The plan is intended to maximize  the value  received for the assets
and provide for an orderly process and objective bid evaluation. Approval of the
auction plan is expected  during 1999 and selection of the winning  bidder(s) is
anticipated in 2000.

INDEPENDENT SYSTEM OPERATOR

            The  Company is a member of the New York Power Pool  ("NYPP")  whose
members,  major  investor-owned  State electric utility  companies,  Long Island
Lighting Company  ("LILCO"),  as a subsidiary of the Long Island Power Authority
("LIPA"),  and the  Power  Authority  of the  State  of New York  ("PASNY"),  by
agreement,  provide  for  coordinated  operation  of their bulk  power  electric
systems.  In a filing with the FERC,  dated January 31, 1997, the member systems
of the NYPP proposed a new market  structure that would include as a key element
the  establishment  of an Independent  System Operator ("ISO") and certain other
entities to supersede the NYPP. The ISO's principal mission would be to maintain
the  reliability  of the New  York  State  bulk  power  systems  and to  provide
transmission  service on a comparable and  non-discriminatory  basis.  By Order,
dated June 24, 1998, the FERC  conditionally  authorized the establishment of an
ISO by the member systems of the NYPP.  Said Order made an interim  finding that
the member  systems'  conditional  proposal to restructure the New York electric
wholesale  market satisfied the principles set forth in FERC Order 888. The FERC
deferred action on other aspects of such proposal including the rates, terms and
conditions of the ISO's open access tariff.  By order dated June 30, 1998,  FERC
conditionally authorized the establishment of the ISO and by order dated January
27, 1999, FERC  conditionally  accepted,  with  modifications,  the proposed ISO
tariff and the  proposed  market  rules of the ISO and  granted  the request for
market-based  rates.  The January 27, 1999,  order called for public hearings on
certain  aspects  of the  proposed  rates  and  provided  for  settlement  judge
proceedings.  Future  filings with FERC will be required to obtain FERC approval
of the transfer of

                                      71


<PAGE>



control of all  necessary  facilities  to the ISO; any such  transfer  would not
involve the transfer of ownership of such assets.

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

NOTE 3 - NINE MILE 2 PLANT

GENERAL

            The Nine Mile 2 Plant is located in Oswego County,  New York, and is
operated by Niagara Mohawk Power Corporation ("Niagara Mohawk"). The Nine Mile 2
Plant is owned as  tenants-  in- common by the Company  (9%  interest),  Niagara
Mohawk (41% interest), New York State Electric & Gas Corporation ("NYSE&G") (18%
interest),  LILCO, as a subsidiary of the LIPA (18% interest), and Rochester Gas
and Electric  Corporation  ("Rochester") (14% interest).  The output of the Nine
Mile 2 Plant,  which has a rated net  capability  of 1,143 MW, is shared and the
operating  expenses  of the Plant are  allocated  to the  cotenants  in the same
proportions  as the cotenants'  respective  ownership  interests.  The Company's
share of direct  operating  expense for the Nine Mile 2 Plant is included in the
appropriate expense  classifications in the accompanying  Consolidated Statement
of Income.

            Under the Operating Agreement entered into by the cotenants, Niagara
Mohawk acts as operator of the Nine Mile 2 Plant,  and all five cotenants  share
certain  policy,  budget  and  managerial  oversight  functions.  The  Operating
Agreement remains in effect subject to termination on six months notice.

RADIOACTIVE WASTE

            Niagara  Mohawk has  contracted  with the U.S.  Department of Energy
("DOE") for disposal of high-level  radioactive  waste  ("spent  fuel") from the
Nine Mile 2 Plant.  Despite a court order  reaffirming  the DOE's  obligation to
accept spent nuclear fuel by January 31, 1998,  the DOE has forecasted the start
of operations of its high-level  radioactive  waste  repository to be no earlier
than 2010.  The Company has been advised by Niagara  Mohawk that the Nine Mile 2
Plant  spent fuel  storage  pool has a capacity  for spent fuel that is adequate
until 2012. If DOE schedule  slippage  should occur,  facilities that extend the
on-site  storage  capability for spent fuel at the Nine Mile 2 Plant beyond 2012
would need to be acquired.

                                      72


<PAGE>



NUCLEAR PLANT DECOMMISSIONING COSTS

            The  Company's  9% share of costs to  decommission  the Nine  Mile 2
Plant is estimated to be  approximately  $209.6  million  ($80.4 million in 1998
dollars) and assumes that decommissioning will begin shortly after the operating
license  expires in the year 2026.  This estimate is based upon a  site-specific
study completed in December 1995.

            In order to assist  the  Company  in meeting  this  obligation,  the
Company  makes  annual   contributions  of  $868,000  to  a  qualified  external
decommissioning  trust  fund.  The  total  annual  amount  allowed  in  rates is
$999,000,  but the maximum annual tax deduction allowed is $868,000.  Currently,
the difference between the rate allowance  ($999,000) and the amount contributed
to the external  qualified  fund  ($868,000) is recorded as an internal  reserve
($131,000), and the funds are held by the Company.

            The qualified  external  decommissioning  trust fund at December 31,
1998  and  1997,  amounted  to  $13.9  million  and $11  million,  respectively,
including  net  reinvested  earnings  to  date of $6.4  million.  The  qualified
external  decommissioning trust fund is reflected in the Company's  Consolidated
Balance Sheet in "Investments and Other Assets-Other." At December 31, 1998, the
external decommissioning trust fund investments carrying value approximated fair
market value. The amount of accumulated  decommissioning costs recovered through
rates  and the net  earnings  of the  external  decommissioning  trust  fund are
reflected in  accumulated  depreciation  in the Company's  Consolidated  Balance
Sheet and amount to $15.6  million and $12.6  million at  December  31, 1998 and
1997, respectively.

            Reference is made to the subcaption  "New  Accounting  Standards and
Other FASB Projects - Plant Decommissioning" in Note 1 - "Summary of Significant
Accounting  Policies"  for details of the  proposed  changes in  accounting  for
nuclear decommissioning costs.

            The Company believes that if decommissioning  costs are greater than
currently  estimated,  such revised costs would be recovered in rates.  However,
future   developments  in  the  utility  industry,   including  the  effects  of
deregulation and increasing competition, could change this conclusion.

                                      73


<PAGE>



NOTE 4 - FEDERAL INCOME TAX

COMPONENTS OF FEDERAL INCOME TAX

            The following is a summary of the  components of federal  income tax
as reported in the Consolidated Statement of Income:

                                            1998       1997        1996
                                          -------     ------      ------
                                                (In Thousands)

Charged to operating expense:
  Federal income tax.................    $28,408      $19,004     $18,936
  Deferred income tax................      1,367       10,186      13,764
                                          ------       ------      ------
    Income tax charged to
      operating expense..............     29,775       29,190      32,700
                                          ------       ------      ------
 Charged (credited) to other
 income and deductions:
  Federal income tax.................        335       (6,844)     (5,716)
  Deferred income tax................     (1,483)       3,891       4,084
                                          ------       ------      ------
    Income tax (credited)
      to other income and
       deductions....................     (1,148)      (2,953)     (1,632)
                                          ------       ------      ------
    Total federal income tax.........    $28,627      $26,237     $31,068
                                          ======       ======      ======


                                      74


<PAGE>



RECONCILIATION:  The following is a reconciliation between the amount of federal
income tax computed on income before taxes at the statutory  rate and the amount
reported in the Consolidated Statement of Income:

                                        1998         1997        1996
                                      --------     --------    -------
                                             (In Thousands)

Net income.......................     $52,544      $55,086     $56,082
Federal income tax...............      28,743       12,160      13,220
Deferred income tax..............        (116)      14,077      17,848
                                       ------       ------      ------
  Income before taxes............     $81,171      $81,323     $87,150
                                       ======       ======      ======
Computed tax @ 35%
 statutory rate..................     $28,410      $28,463     $30,503
Increase (decrease) to computed
 tax due to:
  Pension expense................      (4,486)      (2,855)     (2,424)
  Deferred finance charges -
   Nine Mile 2 Plant.............      (1,700)      (1,699)     (1,699)
  Alternative minimum tax........      (1,048)      (7,350)     (2,262)
  Tax depreciation...............       4,248       (4,225)    (10,499)
  Customer Benefits Account......       1,906          -           -
  Nine Mile 2 settlement costs          1,282        1,567       1,043
  Deferred gas costs.............         375        1,216      (1,703)
  Deferred storm costs...........         -         (2,257)        -
  Other..........................        (244)        (700)        261
                                       ------       ------      ------
Federal income tax...............      28,743       12,160      13,220
Deferred income tax..............        (116)      14,077      17,848
                                       ------       ------      ------
  Total federal income tax.......     $28,627      $26,237     $31,068
                                       ======       ======      ======
 Effective tax rate..............       35.3%        32.3%       35.6%
                                       ======       ======      ======



                                      75


<PAGE>



            The following is a summary of the  components  of deferred  taxes at
December 31, 1998 and 1997, as reported in the Consolidated Balance Sheet:

                                                   1998          1997
                                                  ------        ------
                                                     (In Thousands)
Accumulated Deferred Income
   Tax Assets:
      Future tax benefits on
        investment tax credit basis
        difference...................             $ 14,033    $ 14,837
      Unbilled revenues..............                5,261       5,675
      Alternative minimum tax........                  -         1,048
      Other..........................               32,938      29,047
                                                   -------     -------
 Accumulated Deferred Income
   Tax Assets........................             $ 52,232    $ 50,607
                                                   -------     -------
Accumulated Deferred Income
   Tax Liabilities:
      Tax depreciation...............             $180,339    $181,314
      Accumulated deferred investment
        tax credit...................               26,062      27,555
      Future revenues - recovery of
        plant basis differences......               11,319      17,475
      Other..........................               37,186      29,656
                                                   -------     -------
 Accumulated Deferred Income
   Tax Liabilities...................              254,906     256,000
                                                   -------     -------
 Net Accumulated Deferred Income
   Tax Liability.....................             $202,674    $205,393
                                                   =======     =======

NOTE 5 - SHORT-TERM BORROWING ARRANGEMENTS

            The  Company has in effect a revolving  credit  agreement  with four
commercial banks which allows it to borrow up to $50 million through October 23,
2001,  ("Borrowing  Agreement").  The Borrowing  Agreement gives the Company the
option of  borrowing  at either  the  higher of the prime rate or the sum of the
federal  funds rate plus 1/2 of 1%, or three other money market  rates,  if such
rates are lower.  Compensating  balances  are not required  under the  Borrowing
Agreement. In addition, the Company maintains confirmed lines of credit totaling
$1.5 million with  regional  banks.  There were no  outstanding  loans under the
Borrowing Agreement or the line of credit at December 31, 1998 or 1997. In order
to diversify its sources of short-term  financing,  the Company has entered into
short-term  credit  facilities  agreements  with several  commercial  banks.  At
December 31, 1998, the Company had  outstanding  short-term  debt of $18 million
under such facilities with a weighted average interest rate of 5.5%. The Company
had no short-term debt outstanding at December 31, 1997.

                                      76


<PAGE>



            Authorization  from the PSC limits the amount the  Company  may have
outstanding,  at any time, under all of its short-term borrowing arrangements to
$52 million in the aggregate.

            As part of its establishing a holding company  structure,  CH Energy
Group,  Inc.,  the  proposed  holding  company,  has  established  a $50 million
revolving credit agreement with three commercial banks through December 4, 2001.
No  borrowings  are  permitted  under such  agreement  until the share  exchange
establishing CH Energy Group, Inc. as a holding company is effected.

                                      77


<PAGE>


<TABLE>

NOTE 6 - CAPITALIZATION  - CAPITAL STOCK COMMON STOCK, $5 par value;  30,000,000
shares authorized:
<CAPTION>
                                                                                                                Reacquired
                                                           Common Stock                     Paid-In              Capital
                                                    Shares            Amount                Capital               Stock
                                                  Outstanding         ($000)                ($000)                ($000)
                                                  -----------         ------               --------             ----------
<S>                                                <C>                <C>                  <C>                  <C>
January 1, 1996.....................               17,496,051         $87,480              $282,942             $    -
 Issued under dividend
  reinvestment plan("DRP")(a).......                   49,023             245                 1,278                  -
 Issued under customer stock
  purchase plan ("CSPP")(a).........                    9,913              50                   245                  -
                                                   ----------          ------               -------              -------
December 31, 1996...................               17,554,987          87,775               284,465                  -
 Repurchased under common
  stock repurchase plan.............                 (275,200)            -                     -                 (9,398)
                                                   ----------          ------               -------              -------
December 31, 1997...................               17,279,787          87,775               284,465               (9,398)
 Repurchase under common
  stock repurchase plan.............                 (417,700)            -                     -                (17,745)
                                                   ----------          ------               -------              -------
December 31, 1998...................               16,862,087         $87,775              $284,465             $(27,143)
                                                   ==========          ======               =======              =======

(a) In May 1996, the Company  converted its DRP and its CSPP from original issue
to open market purchase of common shares.
</TABLE>

                                      78


<PAGE>



CUMULATIVE PREFERRED STOCK, $100 par value; 1,200,000 shares authorized:

                         Final         Redemption        Shares Outstanding
                       Redemption        Price               December 31,
            Series       Date           12/31/98          1998         1997
            ------    ----------       ----------         ----         ----
Not Subject to Mandatory
 Redemption:

            4 1/2%                      $107.00          70,300       70,300
            4.75%                        106.75          20,000       20,000
            4.35%                        102.00          60,000       60,000
            4.96%                        101.00          60,000       60,000
                                                        -------      -------
                                                        210,300      210,300
                                                        -------      -------

Subject to Mandatory
 Redemption:

            6.20%       10/1/08 (a)                     200,000      200,000
            6.80%       10/1/27 (a)                     150,000      150,000
                                                        -------      -------
                                                        350,000      350,000
                                                        -------      -------
                    Total                               560,300      560,300
                                                        =======      =======

(a) Cannot be redeemed prior to October 1, 2003.

            The  Company  had  no  cumulative  preferred  stock  redemptions  or
issuances  during  1998 and 1997;  however,  on  January 1,  1996,  the  Company
optionally redeemed its 7.72% Series Cumulative  Preferred Stock (par value $100
per  share) at a  redemption  price of  $101.00  per  share.  The $13.1  million
redemption price paid and associated costs were funded through internal sources.

            Expenses  incurred on issuance of capital stock are  accumulated and
reported as a reduction in common  stock  equity.  These  expenses are not being
amortized,  except that, as directed by the PSC, certain issuance and redemption
costs and unamortized expenses associated with certain issues of preferred stock
that were redeemed have been deferred and are being amortized over the remaining
lives of the issues subject to mandatory redemptions.

            By Order,  issued and effective December 4, 1996, the PSC authorized
the issuance and sale of certain debt and equity securities of the Company.

            That Order authorizes the Company, through December 31, 1999, to: 1)
issue and sell up to $40 million of new  securities  comprised  of common  stock
and/or  medium  term notes,  2) acquire not more than 2.5 million  shares of its
issued and outstanding  common stock, of which the Company  repurchased  692,900
shares through December 31, 1998, and 3) effective January 1, 1997,  combine its
existing DRP, its CSPP and its Employee  Stock  Purchase Plan into a single plan
called the Stock Purchase Plan. The Stock Purchase Plan became effective January
1, 1997,  superseded  such other plans and operates as an original issue or open
market purchase plan.

                                      79


<PAGE>



NOTE 7 - CAPITALIZATION - LONG-TERM DEBT

  Details of long-term debt are as follows:

                                                          December 31,
                                                      --------------------
                                                      1998            1997
                                                      ----            ----
                                                         (In Thousands)
      Series                 Maturity Date
      ------                 -------------
First Mortgage Bonds:

 6.10% (a)                   April 28, 2000        $ 10,000         $ 10,000
 7.70% (a)                   June 12, 2000           25,000          25,000
 7.97% (a)                   June 11, 2003            8,000            8,000
 7.97% (a)                   June 13, 2003            8,000            8,000
 6.46% (a)                   August 11, 2003         10,000           10,000
 6 1/4%(b)                   June 1, 2007             4,325            4,415
 9 1/4%                      May 1, 2021             70,000           70,000
 8.12% (a)                   August 29, 2022         10,000           10,000
 8.14% (a)                   August 29, 2022         10,000           10,000
 8.375%(b)(d)                December 1, 2028        16,700           16,700
                                                    -------          -------
                                                    172,025          172,115

Promissory Notes:

1984 Series A (7 3/8%)(c)    Oct. 1, 2014            16,700           16,700
1984 Series B (7 3/8%)(c)    Oct. 1, 2014            16,700           16,700
1985 Series A (Var. rate)(c) Nov. 1, 2020            36,250           36,250
1985 Series B (Var. rate)(c) Nov. 1, 2020            36,000           36,000
1987 Series A (Var. rate)(c) June 1, 2027            33,700           33,700
1987 Series B (Var. rate)(c) June 1, 2027             9,900            9,900
1998 Series A (4.20%)(c)     Dec. 1, 2028            16,700             -
 5.38% (a)                   Jan. 15,1999            20,000           20,000
 5.93% (a)                   Sept.10,2001            15,000             -
 7.85% (a)                   July 2, 2004            15,000           15,000
                                                    -------          -------
                                                    215,950          184,250

Secured Notes Payable of Subsidiary                   9,023            7,379
Unamortized Discount on Debt                           (573)            (598)
                                                    -------          -------
                Total long-term debt                396,425          363,146
                                                    -------          -------
Less Current Portion                                (39,507)          (1,317)
                                                    -------          -------
                                                   $356,918         $361,829
                                                    =======          =======

(a)  Issued under the Company's Medium Term Note Program.
(b)  First  Mortgage  Bonds issued in  connection  with the sale by the New York
     State Energy Research and Development  Authority  ("NYSERDA") of tax-exempt
     pollution control revenue bonds.
(c)  Promissory  Notes  issued  in  connection  with  the  sale  by  NYSERDA  of
     tax-exempt pollution control revenue bonds.
(d)  To be redeemed March 1, 1999.

                                      80


<PAGE>



LONG-TERM DEBT MATURITIES

            The aggregate  principal  amounts of long-term debt maturing for the
next five years and  thereafter  are as follows:  $39.5  million in 1999,  $36.4
million in 2000,  $16.4 million in 2001, $1.1 million in 2002,  $26.7 million in
2003 and $276.3 million thereafter.

FIRST MORTGAGE BONDS

            The Company,  on December 2, 1998,  refinanced  the 8.375% series of
pollution  control  bonds,  issued  on its  behalf  by  NYSERDA  in  1988 in the
aggregate  principal  amount of $16.7 million,  which bonds are supported by the
Company's  First  Mortgage  Bonds of like  principle  amount.  Such  bonds  were
refinanced  with lower cost NYSERDA  pollution  control  bonds,  which bonds are
supported by the Company's  Promissory Note of like principal amount, at a fixed
rate of 4.20% for their initial term of five years and thereafter are subject to
repricing.  The 8.375%  series will be  redeemed  on March 1, 1999,  in order to
coordinate  with the Article XXI  Mortgage  Indenture  requirements  noted below
under the subcaption  "Mortgage Indenture  Covenant."  Accordingly,  these bonds
have  been  included  in the  "Current  Maturities  of  Long-Term  Debt"  on the
Company's  Balance Sheet. The Company did not issue or redeem any First Mortgage
Bonds during 1997;  however, on May 1, 1996, the Company redeemed $30 million of
its 8 3/4% Series due 2001 at a redemption  price of 102.07% of their  principal
amount.

MEDIUM TERM NOTES

            On  September  8, 1998,  the  Company  issued and sold a $15 million
tranche of its unsecured Medium-Term Notes, Series B, under its medium term note
program.  Such  notes  bear a fixed  annual  interest  rate of 5.93%,  mature on
September 10, 2001, and are not redeemable at the option of the Company prior to
maturity.  The net  proceeds  to the  Company  from the sale of such  notes were
$14,947,500 or 99.65% (before deducting expenses).

            On January  15,  1999,  the  Company  issued and sold a $20  million
tranche of its unsecured Medium-Term Notes, Series C, under its medium term note
program.  Such  notes  bear a fixed  annual  interest  rate of 6.00%,  mature on
January 15, 2009,  and are not  redeemable at the option of the Company prior to
maturity.  The net  proceeds  to the  Company  from the sale of such  notes were
$19,875,000 or 99.875% (before deducting  expenses).  Such proceeds were applied
to the payment at maturity on January 15, 1999, of a $20,000,000  tranche of the
Company's  unsecured  Medium-Term Notes, Series A, that bore interest at a fixed
annual interest rate of 5.38%.

                                      81


<PAGE>



AMENDED SETTLEMENT AGREEMENT

            Under the terms of the  Agreement  described  in Note 2  "Regulatory
Matters," the Company may transfer up to $100 million from its regulated utility
business to its unregulated  businesses  prior to completing the holding company
restructuring.  As of December 31, 1998,  approximately  $25.5  million has been
transferred.  The Company may, pursuant to this authorization,  issue up to $100
million of new securities  prior to June 30, 2001. The Company  expects to issue
medium term notes;  however,  the amount and timing of any such  issuance is not
determinable at this time.

NYSERDA

            The NYSERDA Pollution Control Revenue Bonds issued in 1985 (Series A
and B) and 1987  (Series A and B)  (collectively,  the  "1985  and 1987  NYSERDA
Bonds") are variable rate  obligations  subject to weekly repricing and investor
tender.  The Company has the right,  exercisable  independently  with respect to
each series of the 1985 and 1987 NYSERDA  Bonds,  to convert those Bonds of each
such series to a fixed rate for the remainder of their term. In its rate orders,
the  PSC has  authorized  deferred  accounting  for the  interest  costs  on the
Company's  1985 and 1987  Series A and B  Promissory  Notes which were issued in
connection with the sale of the 1985 and 1987 NYSERDA Bonds.  The  authorization
provides for full  recovery of the  variance  between that portion of the actual
interest costs supporting  utility  operations and the interest costs allowed in
rates. The percent of interest costs supporting  utility  operations  represents
approximately  95%  of  the  total  costs.  The  deferred  balances  under  such
accounting  were $4.9  million and $3.8  million at December  31, 1998 and 1997,
respectively,  and  were  included  in  "Regulatory  Assets"  in  the  Company's
Consolidated Balance Sheet. Such deferred balances are to be addressed in future
rate cases. By Order,  issued and effective December 4, 1996, the PSC authorized
the  Company to issue up to  $132.55  million of  tax-exempt  NYSERDA  Pollution
Control Revenue Bonds for refunding  purposes or for the purpose of refinancing,
if economical, a like amount of such bonds presently outstanding.

LETTERS OF CREDIT

            The Company has in place irrevocable letters of credit which support
certain  payments  required to be made on the 1985 and 1987 NYSERDA Bonds.  Such
letters  of credit,  which  expire in 1999 and 2000,  will be  renewed  prior to
expiration.  The Company anticipates being able to extend such letters of credit
if the interest  rate on the related  series of such Bonds is not converted to a
fixed  interest  rate. If the Company were unable to extend the letter of credit
that is related to a particular

                                      82


<PAGE>



series of such Bonds,  that series would have to be redeemed unless a fixed rate
of  interest  became  effective.  Payments  made under the  letters of credit in
connection  with  purchases of tendered  1985 and 1987 NYSERDA  Bonds are repaid
with the proceeds from the remarketing of such Bonds. To the extent the proceeds
are not  sufficient,  the Company  would be required to reimburse  the bank that
issued  the letter of credit  for the  amount of any  resulting  draw under that
letter prior to its expiration date.

DEBT EXPENSE

            Expenses incurred on debt issues and any discount or premium on debt
are  deferred  and  amortized  over the lives of the  related  issues.  Expenses
incurred  on debt  redemptions  prior to  maturity  have been  deferred  and are
generally being amortized over the shorter of the remaining lives of the related
extinguished issues or the new issues as directed by the PSC.

DEBT COVENANTS

            Certain debt  agreements  require the  maintenance by the Company of
certain financial ratios and contain other restrictive covenants.

MORTGAGE INDENTURE COVENANT

            Article XXI of the  Company's  Indenture  of  Mortgage,  pursuant to
which the Company's  first  mortgage  bonds are  outstanding  (the  "Mortgage"),
requires  generally that, to the extent that the cost of property  additions (as
defined in the Mortgage)  acquired by the Company during a calendar year is less
than  the  allowance  for  depreciation  on  property  subject  to the  Mortgage
(calculated  pursuant to the Mortgage) for such calendar  year, the Company must
deposit cash with the Mortgage  Trustee in the amount of such  deficiency,  less
certain  credits  available to the Company  under the Mortgage (the "Article XXI
Deficiency").

            Any cash  deposited  with the  Mortgage  Trustee  as a result  of an
Article XXI Deficiency may be withdrawn by the Company in an amount equal to the
cost of property  additions  acquired by the Company subsequent to such calendar
year, or may be applied by the Mortgage Trustee,  at the request of the Company,
to  redeem  or  purchase  outstanding  mortgage  bonds  in  accordance  with the
provisions of the  Mortgage.  If any such cash left on deposit with the Mortgage
Trustee for 12 consecutive  months or more is in excess of $350,000,  the amount
of such cash in excess of $250,000  must be applied by the  Mortgage  Trustee to
redeem or purchase  mortgage bonds,  subject to certain  exceptions set forth in
the  Mortgage.  Article XXI of the Mortgage will remain in effect so long as any
of the  Company's  mortgage  bonds  of any  series  created  prior  to 1994  are
outstanding under the Mortgage.

                                      83


<PAGE>



            For  calendar  year 1997,  the  Company  experienced  an Article XXI
Deficiency in the amount of $722,226,  in  satisfaction  of which,  on March 24,
1998, it deposited with the Mortgage  Trustee cash in that amount.  For calendar
year 1998, the Company  experienced an Article XXI Deficiency in the approximate
amount of $16.3 million, in satisfaction of which it deposited with the Mortgage
Trustee  cash in that amount  received by the Company  from the  proceeds of the
1998 NYSERDA Bonds. Such cash deposited will be applied by the Mortgage Trustee,
at the  request of the  Company,  to the  redemption,  on March 1, 1999,  of the
Company's First Mortgage Bonds, 8.375% Series due 2028.

NOTE 8 - POSTEMPLOYMENT BENEFITS

PENSION BENEFITS

            The  Company   has  a   non-contributory   retirement   income  plan
("Retirement Plan") covering substantially all of its employees.  The Retirement
Plan provides pension benefits that are based on the employee's compensation and
years of service. It has been the Company's practice to provide periodic updates
to the benefit formula stated in the Retirement Plan.

            The Company's funding policy is to make annual  contributions  equal
to the amount of net  periodic  pension  cost,  but not in excess of the maximum
allowable tax-deductible  contribution under the federal income tax law nor less
than the minimum  requirement under the Employee  Retirement Income Security Act
of 1974.

            The 1998 and 1997 accounting for pension benefits  reflects adoption
of  PSC-prescribed  provisions  which,  among other  things,  requires  ten-year
amortization of actuarial  gains and losses and deferral of differences  between
actual pension expense and rate allowances.

            In  addition  to  the  Retirement   Plan,  the  Company  sponsors  a
non-qualified  plan for  eligible  officers  (the  "EDCP")  and a  non-qualified
pension restoration plan.

OTHER POSTRETIREMENT BENEFITS

            The Company provides certain health care and life insurance benefits
for retired employees through its post-retirement benefit plan ("Benefit Plan").
Substantially  all of the  Company's  employees  may become  eligible  for these
benefits if they reach  retirement age while working for the Company.  These and
similar benefits for active employees are provided through  insurance  companies
whose  premiums  are based on the  benefits  paid  during the year.  In order to
reduce the total costs of these  benefits,  the Company  requires  employees who
retired  on or after  October  1, 1994,  to  contribute  toward the cost of such
benefits.

          The Company is fully recovering its net periodic  postretirement costs
in accordance with PSC guidelines. Under

                                      84


<PAGE>



these guidelines, the difference between the amounts of post-retirement benefits
recoverable in rates and the amounts of post-retirement  benefits  determined by
the actuary under SFAS 106,  "Employers  Accounting for Postretirement  Benefits
Other Than Pensions," are deferred as either a regulatory asset or liability, as
appropriate.

            Reconciliations of Pension and OPEB Plans' benefit obligation,  plan
assets and funded status, as well as the components of net periodic pension cost
and the weighted average assumptions are as follows:
<TABLE>
<CAPTION>

                                    Pension Benefits                  Other Benefits
                                 ----------------------           -------------------------
                                   1998           1997             1998              1997
                                   ----           ----             ----              ----
                                       In Thousands                     In Thousands
                                       ------------                     ------------
<S>                              <C>            <C>               <C>             <C>
Change in Benefit
 Obligation:
  Benefit obligation
   at beginning of
   year                          $225,038       $201,779          $78,953         $ 71,481
    Service cost                    5,205          4,578            2,076            1,745
    Interest cost                  16,234         15,504            5,610            5,264
    Plan amendments                14,439           -                -                -
    Benefits paid                 (12,433)       (11,750)          (2,973)          (2,606)
    Actuarial (gain)
     or loss                       22,021         14,927            9,805            3,069
                                 --------       --------          -------         --------
  Benefit Obligation
   at End of Year                $270,504       $225,038          $93,471         $ 78,953
                                 --------       --------          -------         --------
Change in Plan
Assets:
  Fair value of plan
   assets at begin-
   ning of year                  $316,852       $268,615          $45,109         $ 31,402

    Actual return on
     plan assets                    6,040         60,842           10,607           10,004
    Employer
     contributions                     72             48            5,489            6,431
    Benefits paid                 (12,433)       (11,750)          (3,569)          (2,606)
    Administrative
     Expenses                      (1,494)          (903)            (456)            (122)
                                 --------       --------          -------         --------
  Fair Value of Plan
   Assets at End of
   Year                          $309,037       $316,852          $ 57,180        $ 45,109
                                 --------       --------          -------         --------
</TABLE>




<PAGE>
<TABLE>
<CAPTION>

                                    Pension Benefits                  Other Benefits
                                 ----------------------           -------------------------
                                   1998           1997             1998              1997
                                   ----           ----             ----              ----
                                       In Thousands                     In Thousands
                                       ------------                     ------------
<S>                              <C>            <C>               <C>             <C>
Reconciliation of
 Funded status
  Funded status                  $ 38,533       $ 91,814          $(36,291)      $(33,844)
   Unrecognized
   actuarial (gain)               (18,985)       (73,949)           (9,800)       (14,716)
  Unrecognized
   transition (asset)
   or obligation                   (2,065)        (2,700)           43,579         46,693
  Unamortized prior
   service cost                    20,179          6,292              (129)          (139)
                                 --------       --------          --------       --------
Accrued Benefit Cost             $ 37,662       $ 21,457          $ (2,641)      $ (2,006)
                                 --------       --------          --------       --------
Components of Net
 Periodic Benefit
 Cost
  Service cost                   $  5,205       $  4,578          $  2,076       $  1,745
  Interest cost                    16,234         15,504             5,610          5,264
  Expected return on
   plan assets                    (27,325)       (24,373)           (2,867)        (1,886)
  Amortization of
   prior service cost                 552            355               (10)           (10)
  Amortization of
   transitional
   (asset) or
   obligation                        (635)          (635)            3,114          3,114
  Recognized
   actuarial
   (gain) or loss                 (10,162)        (7,846)           (1,789)        (1,504)
                                 --------       --------          --------       --------
Net Periodic Benefit
 Cost                            $(16,131)      $(12,417)         $  6,134       $  6,723
                                 --------       --------          --------       --------
Weighted-average
 assumptions as of
 December 31
  Discount rate                      6.50%          7.25%             6.50%         7.25%
  Expected long-term
   rate of return on
   plan assets                       8.50%          9.25%             6.80%         6.80%
  Rate of compen-
  sation increase                    4.00%          4.50%             4.00%         4.50%
</TABLE>




                                      86


<PAGE>



            For measurement purposes, a 9.5% (9.9% for participants over age 65)
annual rate of increase  in the per capita  cost of covered  health  benefits is
assumed for 1999. The rate is assumed to decrease gradually to 5.5% for 2008 and
remain at that level thereafter.

            Assumed  health care cost trend rates have a  significant  effect on
the amounts reported for the health care plan. A one- percentage-point change in
assumed health care cost trend rates would have the following effects:

                                   One-Percentage-         One-Percentage-
                                   Point Decrease          Point Increase
                                   --------------          --------------

Effect on total of service
 and interest cost compo-
 nents for 1998                     $ 1,138,000             $  (987,000)

Effect on year-end 1998
 postretirement benefit
 obligation                         $12,245,000             $(10,826,000)

NOTE 9 - COMMITMENTS AND CONTINGENCIES

NUCLEAR LIABILITY INSURANCE

            The  Price-Anderson  Act is a federal  law which  limits  the public
liability which can be imposed with respect to a nuclear  incident at a licensed
nuclear electric generating  facility.  Such Act also provides for assessment of
owners of all licensed  nuclear  units in the United States for losses in excess
of certain limits in the event of a nuclear  incident at any such licensed unit.
Under  the  provisions  of  the  Price-Anderson  Act,  the  Company's  potential
assessment  (based  on its 9%  ownership  interest  in the Nine Mile 2 Plant and
assuming that the other Nine Mile 2 Plant  cotenants  were to  contribute  their
proportionate  shares  of the  potential  assessments)  would  be  $7.6  million
(subject to adjustment for inflation) and the Company could be assessed $378,000
(subject to adjustment for inflation) as an additional  surcharge,  but would be
limited to a maximum  assessment  of  $900,000  in any year with  respect to any
nuclear  incident.  The public  liability  insurance  coverage  of $200  million
required  under the  Price-Anderson  Act for the Nine  Mile 2 Plant is  provided
through Niagara Mohawk.

            The Company also carries  insurance to cover the additional costs of
replacement power (under a Business  Interruption and/or Extra Expense Insurance
Policy) incurred by the Company in the event of a prolonged accidental outage of
the Nine Mile 2 Plant. This insurance arrangement provides for payments of up to
$276,000 per week if the Nine Mile 2 Plant

                                      87


<PAGE>



experiences a continuous  accidental  outage which extends beyond 21 weeks. Such
payments will continue for 52 weeks after  expiration of the 21-week  deductible
period,  and thereafter the insurer shall pay 80% of the weekly  indemnity for a
second and third 52-week period. Subject to certain limitations, the Company may
request prepayment,  in a lump sum amount, of the insurance payments which would
otherwise be paid to it with respect to said third 52-week period, calculated on
a net present value basis.

            The  Company is insured as to its  respective  interest  in the Nine
Mile 2 Plant under property damage  insurance  provided  through Niagara Mohawk.
The insurance coverage provides $500 million of primary property damage coverage
for both  Units of the Nine Mile  Point  Nuclear  Station  and $2.25  billion of
excess  property  damage  coverage  solely  for  Unit 2 of  that  station.  Such
insurance  covers  decontamination  costs,  debris  removal  and  repair  and/or
replacement of property.

            The  Company  intends  to  maintain,  or  cause  to  be  maintained,
insurance  against such risks at the Nine Mile 2 Plant,  provided  such coverage
can be obtained at an acceptable cost.

ENVIRONMENTAL MATTERS

           General:  On an ongoing  basis,  the  Company  assesses environmental
issues which could impact the Company and its customers.

           Clean  Water  Act  Compliance:  In 1992 the  Company  filed  renewal
applications  for the State Pollution  Discharge  Elimination  System  ("SPDES")
permits for its Roseton and  Danskammer  Plants.  Such  permits are  required to
operate the Plants' cooling water systems and wastewater  treatment systems. The
Company is a party to an active  proceeding before the New York State Department
of  Environmental  Conservation  ("NYSDEC")  related  to the  processing  of the
application  for the Roseton Plant.  The utility  participants in the proceeding
agreed to prepare  and submit a revised  Draft  Environmental  Impact  Statement
("DEIS")  with a target date of December 31,  1999.  NYSDEC has  indicated  that
draft SPDES  permits  will be issued  after the revised  DEIS is filed.  At this
stage of the proceeding, the Company can make no determination as to the outcome
of the proceeding or the impact, if any, on the Company's financial position.

          Clean Air Act Amendments: The Clean Air Act Amendments of 1990 ("CAA
Amendments") added several new programs which address attainment and maintenance
of national  ambient air quality  standards.  These include control of emissions
from fossil-fueled electric generating plants that affect "acid rain" and ozone.
At December 15, 1998, the Company believes it was in

                                      88


<PAGE>



full compliance with  regulations  promulgated to date under the CAA Amendments.
Ongoing  federal  and state  clean air  initiatives  may  require the Company to
reduce its emissions in the future.

            The Company's  emissions of nitrogen  oxides ("NOx") were subject to
additional  controls,  effective  May  31,  1995,  under  Title  I  of  the  CAA
Amendments.  The Company has installed  appropriate  controls in compliance with
this requirement. The Northeast Ozone Transport Commission ("OTC"), of which New
York State is a member,  has agreed that additional  reductions of NOx emissions
will be  required  in 1999 and,  possibly,  in the year  2003.  The  NYSDEC  has
proposed regulations intended to implement the 1999-2002 NOx emissions reduction
contemplated  by OTC. The Company is developing  plans to comply with the NYSDEC
proposal and believes  that it can do so by fuels and operation  management  not
requiring the use of additional back-end emissions controls.

            In  July  1997,   the   Environmental   Protection   Agency  ("EPA")
promulgated proposed revisions to the National Ambient Air Quality Standards for
ozone and particulates.  These regulations may result in the need for additional
reductions  of sulfur  dioxide and NOx  emissions,  depending  on the results of
ongoing  ambient air  monitoring  programs.  Should  monitoring  determine  that
counties in the vicinity of the Company's  electric  generating  stations exceed
the new standards,  emissions reductions could be required. However, ambient air
monitoring for particulates  will not be completed until 2002, at which time the
EPA also  intends to complete a  reassessment  of health risks  associated  with
particulate emissions.  Additional controls of NOx emissions that are associated
with ozone formation are required in 2003 under rules  promulgated by the EPA in
September  1998.  EPA has  established  limits on NOx  emissions  for each of 22
states in the midwest, southeast and northeast.

            While it is not  presently  possible  to  determine  the  additional
emissions  reductions,  if any, required at the Company's  facilities under this
EPA rule, the Company expects that they can be achieved by conventional  control
technologies, in combination with prudent operational management.

            Beginning in 1997 the NYSDEC,  began an initiative seeking penalties
from all New York electric  utilities  for past opacity  variances and requiring
various  opacity  reduction   measures  and  stipulated   penalties  for  future
excursions  after  execution of a consent  order.  Each New York State  electric
utility,  including  the  Company,  is in the  process  of  negotiating,  or has
negotiated,  the various terms and  conditions of a draft consent order with the
NYSDEC. The Company's  facilities,  which are the subject of these negotiations,
are in its Danskammer Plant and its Roseton Plant. The outcome of this matter is
uncertain at this time;  however,  the Company  believes  that the amount of any
civil penalty payment and implementation of an opacity reduction program, in the
aggregate, will not be material.

                                      89


<PAGE>



FORMER MANUFACTURED GAS PLANT FACILITIES

            In October 1995, the Company and the NYSDEC entered into an Order on
Consent  regarding the development and  implementation  of an investigation  and
remediation  program for the Company's former coal gasification  plant ("Central
Hudson Site"),  the City of Newburgh,  New York's  ("City")  adjacent and nearby
property and the adjoining  areas of the Hudson River.  Remedial  investigations
were  completed in September  1997.  A draft  report on the  investigations  was
provided  to the  NYSDEC for its review and  comment on October  31,  1997.  The
investigations  revealed the presence of contaminants in the soil in portions of
the study area. In the majority of the study area  contaminants  were found deep
within the ground and are not a threat to the public.  Contaminated ground water
is associated with the contaminated  soil but it is not used as a drinking water
supply. Impacted sediments were also present within the Hudson River adjacent to
the City's property which is the location of its sewage treatment  plant.  There
are several  possible  sources of the  contaminants  due to the long  industrial
history and current uses of the area.

            The Company is conducting additional studies as part of the remedial
investigation required by the Order on Consent with NYSDEC. The results of these
studies  will be  provided  as part of a revised  final  report on the  remedial
investigation to the NYSDEC in early 1999.

            Following  NYSDEC's  approval  of the report  and its  determination
whether  or  not  the  contaminants  found  in  the  investigation  may  pose  a
significant threat to human health or the environment, a risk assessment will be
completed by the Company,  if required.  Remedial  alternatives  addressing  any
unacceptable  risks  identified in the risk assessment will be evaluated.  It is
currently  anticipated that the risk assessment and remedial alternatives report
will be completed in 1999.

            In May 1995,  the City filed suit  against the Company in the United
States  District  Court for the Southern  District of New York. The City alleges
that the Company has released certain allegedly  hazardous  substances without a
permit from the Central Hudson Site in Newburgh, New York into the ground at the
Central  Hudson  Site and into  adjacent  and nearby  property  of the City,  in
violation of the federal Comprehensive Environmental Response,  Compensation and
Liability Act ("CERCLA"),  the federal  Resource  Conservation  and Recovery Act
("RCRA")  and the federal  Emergency  Planning and  Community  Right to Know Act
("EPCRA").  The City also  alleges a number of  nuisance,  trespass,  damage and
indemnification claims pursuant to New York State law.

            The City seeks  injunctive  relief  against such  alleged  disposal,
storage  or  release  of  hazardous  substances  at  the  Central  Hudson  Site,
remediation  and abatement of the conditions  alleged to lead to endangerment of
the City's  property,  payment of  restitution  of clean-up  costs and  monetary
damages of at least

                                      90


<PAGE>



$70 million, assessment of certain civil penalties under RCRA, CERCLA and EPCRA,
and recovery of the City's costs and attorneys' fees in such action.

            The trial on this matter began  November  30, 1998,  and on December
18, 1998, the jury made its determination  that the proper cost of environmental
remediation on the City's property is $20 million and the Company's share is 80%
(or $16 million). In addition, the jury awarded the City $435,000 of damages for
increased costs of future operations of the City's sewage treatment plant due to
the existence of contamination.

            The Court reserved to itself decision on the City's allegations that
the Company violated  certain  provisions of the federal RCRA and the EPCRA. The
extent of exposure to the Company under these  allegations  cannot be estimated.
In addition,  the City's request for attorney's and consultant's fees (estimated
to be approximately $5 million) also is yet to be determined by the Court.

            The Court is expected to issue a decision on the matters referred to
in the immediately  preceding  paragraph in the Spring of 1999. Upon issuance of
such  decision  either  party will have 30 days to appeal  the  jury's  decision
and/or the Court's decision.

            The  Company  and the City  have  stipulated  that the  damages  for
clean-up  costs  awarded  by the jury  will be  deposited  by the  City  into an
interest earning account ("Clean-up Fund") which, upon Court approval,  shall be
applied to the costs of the  environmental  clean-up  of the  City's  properties
pursuant to the said Order on Consent.  Any excess  funds in the  Clean-up  Fund
shall be retained by the City.  Within 45 days after any appeals become final in
this matter, the City may apply to the NYSDEC to assume the  responsibilities of
the  Company  under  said  Order on  Consent.  If the City  does not so apply to
NYSDEC,  or does apply and is not accepted for  substitution by the NYSDEC,  the
Company shall  continue to be  responsible  for the clean-up under said Order on
Consent.  In the event the  amount in the  Clean-up  Fund is not  sufficient  to
satisfy the  clean-up  responsibilities  under said Order on Consent,  the party
responsible  for the clean-up  will be  responsible  for any excess  required to
comply with said Order on Consent.

            In July 1998,  the City and the Company  entered  into an  agreement
("Newburgh Agreement") which allowed the City to recommence  construction at its
sewage  treatment  plant.  The  Newburgh  Agreement  provides  for  the  City to
construct a clarifier at the sewage  treatment  plant and to deal  appropriately
with any contaminants that may be encountered during the construction activities
and for the  Company to fund these  construction  and  related  activities.  The
Company  estimates that the cost of such construction and other related activity
is  approximately  $2.8 million.  The Company's  obligation to fund the costs of
constructing  the clarifier at the City's sewage  treatment plant is in addition
to the jury award, discussed above.

                                      91


<PAGE>



            As of December 31, 1998, the Company  recorded  liabilities of $16.4
million and $2.4 million  regarding  this matter which are included in "Deferred
Credits  and Other  Liabilities  - Other"  and  "Current  Liabilities  - Other,"
respectively, in the Company's Consolidated Balance Sheet.

            By letter  dated June 3, 1997,  the Company  received  authorization
from the PSC to defer costs  related to this  matter,  including  legal  defense
costs,  but  excluding  the  Company's  labor,  related  to  environmental  site
investigation and remediation  actions.  The Company has deferred costs expended
to date that it expects to be recovered in future rates. The cumulative deferred
costs  for  1998  amounted  to $22.7  million  and were  included  in  "Deferred
Charges-Regulatory Assets" in the Company's Consolidated Balance Sheet.

            The Company can make no prediction as to the full  financial  effect
this  matter  will  have on it,  including  the  extent,  if any,  of  insurance
reimbursement and including  implementation of environmental clean-up under said
Order on Consent.

ASBESTOS LITIGATION

            Since 1987,  the Company,  along with many other  parties,  has been
joined as a  defendant  or  third-party  defendant  in 1,576  asbestos  lawsuits
commenced in New York State and federal courts. The plaintiffs in these lawsuits
have each sought millions of dollars in compensatory  and punitive  damages from
all  defendants.  The cases were brought by or on behalf of individuals who have
allegedly  suffered injury from exposure to asbestos,  including  exposure which
allegedly occurred at Company facilities.

            To date,  of the  1,576  cases  that had been  brought  against  the
Company,  642 remained  pending against the Company.  The 934 cases that were no
longer pending  against the Company,  as of December 31, 1998,  were resolved as
follows:  (i) the Company negotiated  voluntary  dismissals in 685 cases and won
summary  judgement  dismissals  in 10 cases;  (ii) 113  third-party  claims were
extinguished  with respect to the Company when the third party plaintiff,  Owens
Corning Fiberglas  settled the cases with the plaintiffs;  and (iii) the Company
settled 126 cases. The Company is presently unable to assess the validity of the
remaining  asbestos  lawsuits;  accordingly,  it cannot  determine  the ultimate
liability  relating to these cases. Based on information known to the Company at
this time,  including its experience in settling asbestos cases and in obtaining
dismissals of asbestos cases,  the Company believes that the cost to be incurred
in  connection  with the  remaining  lawsuits  will not have a material  adverse
effect on the Company's financial position or results of operations.

                                      92


<PAGE>



            The  Company  is  insured  under  successive  comprehensive  general
liability  policies  issued by a number of  insurers,  has put such  insurers on
notice of the asbestos  lawsuits and has demanded  reimbursement for its defense
costs and liability.

PURCHASED POWER COMMITMENTS

            Under federal and New York State laws and  regulations,  the Company
is  required to  purchase  the  electrical  output of  unregulated  cogeneration
facilities  ("IPPs") which meet certain criteria for Qualifying  Facilities,  as
such term is defined in the  appropriate  legislation.  Purchases are made under
long-term  contracts  which  require  payment at rates  higher  than what can be
purchased on the wholesale  market.  These costs are currently fully recoverable
through the Company's electric fuel adjustment clause,  with one exception,  for
which the impaired portion of the contract has been recognized as a reduction to
income.  IPPs with which the Company has contracts represent 6% of the Company's
energy purchases in 1998.

OTHER MATTERS

            The Company is involved  in various  other legal and  administrative
proceedings  incidental to its business which are in various stages. While these
matters   collectively  involve  substantial  amounts,  it  is  the  opinion  of
management  that their  ultimate  resolution  will not have a  material  adverse
effect on the Company's financial position or results of operations.

            Included  in such  proceedings  are  lawsuits  against  the  Company
arising from a November 1992 explosion in a dwelling in Catskill,  New York. One
lawsuit in this matter alleging personal injuries, the death of an occupant, and
property  damage and  recovery  of an  unspecified  amount of  compensatory  and
punitive  damages was settled in January  1999 in an amount that is not material
to the Company; and one lawsuit remains, alleging personal injuries and property
damage and compensatory and punitive damages in the sum of $4 million.

            In  addition  to the above,  on  February  12,  1994,  a fire and an
explosion destroyed a residence in the Village of Wappingers Falls, New York, in
the Company's service territory. A short time later, a second explosion and fire
destroyed a nearby commercial  facility.  Lawsuits commenced against the Company
arising out of the  Wappingers  Falls  incident  include one  alleging  property
damage and seeking recovery of $250,000 in compensatory damages and one alleging
personal  injuries  and  property  damage and seeking an  unspecified  amount of
damages against the Company. All such lawsuits have been consolidated;  however,
no trial date has been set.

          The  Company  is  investigating  the above  claims and  presently  has
insufficient information on which to predict their

                                      93


<PAGE>



outcome.  The  Company  believes  that it has  adequate  insurance  to cover any
compensatory damages that might be awarded.  The Company's  insurance,  however,
does not extend to punitive  damages  which,  if awarded,  could have a material
adverse effect on the Company's financial position.

NOTE 10 - SEGMENTS AND RELATED INFORMATION

            The Company adopted SFAS No. 131,  "Disclosures about Segments of an
Enterprise and Related Information," during the fourth quarter of 1998. SFAS No.
131 established  standards for reporting information about operating segments in
annual financial  statements and requires  selected  information about operating
segments  in  interim  financial   reports  issued  to  stockholders.   It  also
established  standards for related disclosures about products and services,  and
geographic areas.  Operating segments are defined as components of an enterprise
about which  separate  financial  information  is  available  that is  evaluated
regularly by the chief operating  decision maker, or  decision-making  group, in
deciding how to allocate resources and in assessing  performance.  The Company's
chief operating decision-making group includes the senior executive officers.

            The Company's reportable operating segments are its electric and gas
operations.  The Company's "Other Segment" consists  primarily of Central Hudson
Enterprises Corporation and CH Resources,  Inc., both of which are non-regulated
energy businesses. All of the segments currently operate in the northeast region
of the United States.

            Certain additional information regarding these segments is set forth
in the following  table.  General  corporate  expenses,  property common to both
segments and  depreciation  of such common  property have been  allocated to the
segments in accordance with practice established for regulatory purposes.

                                      94


<PAGE>



                         Central Hudson Gas & Electric
                         Segment Disclosure - FAS 132
                            Year Ended December 31,

                                                      1998
                                -----------------------------------------------
                                Electric      Gas          Other         Total
                                --------      ---          -----         -----

Net revenues from
 external customers          $  418,426     $ 84,898      $  -        $  503,324
Intersegment net
 revenues                            80           65         -               145
                             ----------     --------      -------     ----------
   Total net revenues           418,506       84,963         -           503,469
                             ----------     --------      -------     ----------
Depreciation and
 amortization                    40,996        4,564         -            45,560
Interest expense                 23,803        3,875         -            27,678
Interest income                     695           87         -               782
Income tax (credit)
 expense                         24,646        3,981         -            28,627
Earnings per share                 2.51         0.35         0.04           2.90
Segment assets                1,093,455      169,587       52,996      1,316,038
Construction
 Expenditures                    39,183        6,478         -            45,661


                                                      1997
                                -----------------------------------------------
                                Electric      Gas          Other         Total
                                --------      ---          -----         -----
Net revenues from
 external customers          $  416,346     $103,835      $  -        $  520,181
Intersegment net
 revenues                            83           13         -                96
                             ----------     --------      -------     ----------
   Total net revenues           416,429      103,848         -           520,277
                             ----------     --------      -------     ----------
Depreciation and
 amortization                    39,480        4,384         -            43,864
Interest expense                 23,186        3,464         -            26,650
Interest income                   1,970          290         -             2,260
Income tax (credit)
 expense                         21,405        4,832         -            26,237
Earnings per share                 2.58         0.37         0.02           2.97
Segment assets                1,067,042      163,021       22,027      1,252,090
Construction
 Expenditures                    36,685        7,183         -            43,868


                                      95


<PAGE>



                    Central Hudson Gas & Electric (Cont'd)
                         Segment Disclosure - FAS 132
                            Year Ended December 31,

                                                      1996
                                -----------------------------------------------
                                Electric      Gas          Other         Total
                                --------      ---          -----         -----
Net revenues from
 external customers         $  418,673      $ 95,228      $  -        $  513,901
Intersegment net                                             -
 revenues                          88            (18)                         70
                             ----------     --------      -------     ----------
  Total net revenues           418,761        95,210         -           513,971
                             ----------     --------      -------     ----------
Depreciation and
 amortization                   38,401         4,179         -            42,580
Interest expense                23,649         3,534         -            27,183
Interest income                263,426        36,748         -           300,174
Income tax (credit)
 expense                        27,103         3,965         -            31,068
Earnings per share                2.67          0.27         0.05           2.99
Segment assets               1,066,185       160,764       22,157      1,249,106
Construction
 Expenditures                   43,359         6,501         -            49,860


NOTE 11 - FINANCIAL INSTRUMENTS

          The following methods and assumptions were used to estimate the fair
value of each class of  financial  instruments  for which it is  practicable  to
estimate that value:

          Cash and Temporary Cash Investments:  The carrying amount approximates
fair value because of the short maturity of those instruments.

          Cumulative Preferred Stock Subject to Mandatory  Redemption:  The fair
value is estimated based on the quoted market price of similar instruments.

          Long-term Debt: The fair value is estimated based on the quoted market
prices for the same or similar  issues or on the  current  rates  offered to the
Company for debt of the same remaining maturities and quality.

          Notes Payable:  The carrying amount approximates fair value because of
the short maturity of those instruments.

                                      96


<PAGE>



            The estimated fair values of the Company's financial instruments are
as follows:

                                                   December 31, 1998
                                                ------------------------
                                                Carrying           Fair
                                                 Amount            Value
                                                --------           -----
                                                     (In Thousands)

Cumulative preferred stock subject
  to mandatory redemption.............          $ (35,000)       $ (37,083)
Long-term debt (including
  current maturities).................           (396,425)        (413,905)


                                                   December 31, 1997
                                                ------------------------
                                                Carrying           Fair
                                                 Amount            Value
                                                --------           -----
Cumulative preferred stock subject
  to mandatory redemption.............          $ (35,000)       $ (39,100)
Long-term debt (including
  current maturities).................           (363,146)        (382,837)



                                      97


<PAGE>


<TABLE>

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

            Selected  financial data for each  quarterly  period within 1998 and
1997 are presented below:
<CAPTION>

                                                                                 Earnings Per
                                                                   Income           Average
                                                                 Available          Share of
                                                                    for             Common
                               Operating        Operating          Common            Stock
                               Revenues          Income            Stock         Outstanding
                               --------         ---------        ---------       ------------
                                              (In Thousands)                       (Dollars)
                               -------------------------------------------       ------------
Quarter Ended:

       1998
       ----

<S>                           <C>               <C>               <C>               <C>
  March 31............        $143,882          $24,003           $18,360           $1.06
  June 30.............         112,106           14,404             9,234             .54
  September 30........         125,723           18,350            13,003             .77
  December 31.........         121,758           14,543             8,717             .53

       1997
       ----

  March 31............        $151,875          $25,802           $20,678           $1.18
  June 30.............         118,604           14,842             9,657            .55
  September 30........         123,507           17,911            12,561            .72
  December 31.........         126,291           11,501             8,963            .52

</TABLE>


                                      98


<PAGE>


<TABLE>

SCHEDULE II  - RESERVES

                                                            Additions
                                                   ----------------------------
                                                                                    Payments          Balance
                                    Balance At     Charged to        Charged to     Charged           At End
                                    Beginning      Cost and            Other           to               of
Description                         of Period      Expenses          Accounts       Reserves          Period
-----------                         ---------      --------          --------       --------          ------
<S>                                 <C>            <C>              <C>            <C>             <C>
YEAR ENDED DECEMBER 31, 1998

Operating Reserves........          $6,581,614     $7,474,979       $  103,700     $8,165,693      $5,994,600
                                     =========      =========        =========      =========       =========
Reserve for Uncollectible
 Accounts.................          $2,800,000     $2,638,719       $    -         $3,038,719      $2,400,000
                                     =========      =========        =========      =========       =========

YEAR ENDED DECEMBER 31, 1997

Operating Reserves........          $4,755,264     $2,142,391       $  334,700     $  650,741      $6,581,614
                                     =========      =========        =========      =========       =========
Reserve for Uncollectible
 Accounts.................          $3,200,000     $3,493,405       $    -         $3,893,405      $2,800,000
                                     =========      =========        =========      =========       =========

YEAR ENDED DECEMBER 31, 1996

Operating Reserves........          $6,024,101     $2,665,136       $  195,608     $4,129,581      $4,755,264
                                     =========      =========        =========      =========       =========
Reserve for Uncollectible
 Accounts.................          $2,500,000     $4,335,676       $    -         $3,635,676      $3,200,000
                                     =========      =========        =========      =========       =========

</TABLE>


                                      99


<PAGE>



      ITEM 9 -    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                  ACCOUNTING AND FINANCIAL DISCLOSURE
      ------------------------------------------------------------

      None.

                                   PART III
                                   --------

      ITEM 10 -   DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
      -----------------------------------------------------------

            The  information  with  respect  to the  Directors  of  the  Company
required  hereunder is  incorporated  by  reference to the caption  "Election of
Directors" in the Company's  definitive  proxy  statement,  to be dated March 1,
1999, and to be used in connection with its Annual Meeting of Shareholders to be
held  on  April  27,  1999,  which  proxy  statement  will be  submitted  to the
Securities and Exchange Commission pursuant to that Commission's Regulation S-T.

            The  information  with  respect  to the  executive  officers  of the
Company required hereunder is incorporated by reference to Item 1 herein,  under
the caption "Executive Officers of the Company."

      ITEM 11 -   EXECUTIVE COMPENSATION
      ----------------------------------

            The information  required  hereunder is incorporated by reference to
the  caption  "Executive   Compensation"  in  the  Company's   definitive  proxy
statement,  to be dated  March 1, 1999,  and to be used in  connection  with its
Annual Meeting of Shareholders to be held on April 27, 1999.

      ITEM 12 -   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
                  AND MANAGEMENT
      -----------------------------------------------------------

            The information  required  hereunder is incorporated by reference to
the caption "Security Ownership" in the Company's definitive proxy statement, to
be dated March 1, 1999, and to be used in connection  with its Annual Meeting of
Shareholders to be held on April 27, 1999.

      ITEM 13 -   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
      ----------------------------------------------------------

            There were no  relationships or transactions of the type required to
be described by this Item.

                                     100


<PAGE>



                                    PART IV

      ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND
                REPORTS ON FORM 8-K
      -----------------------------------------------------

(a)   DOCUMENTS FILED AS PART OF THIS REPORT

      1. and 2. All Financial Statements and Financial Statement Schedules filed
      as part of this  Report  are  included  in Item 8 of this  Form  10-K  and
      reference is made thereto.

      3. Exhibits

      Incorporated  herein by  reference  to the Exhibit  Index for this Report.
      Such Exhibits include the following  management  contracts or compensatory
      plans or arrangements  required to be filed as an Exhibit pursuant to Item
      14(c) hereof:

      Description in the Exhibit List and Exhibit Nos. for this
      ---------------------------------------------------------
      Report
      ------

      Directors' Deferred Compensation Plan, effective October 1, 1980. (Exhibit
      (10)(iii)1)

      Executive  Deferred  Compensation Plan of the Company,  effective March 1,
      1992,  together with Amendments  thereto  effective  December 17, 1993 and
      December 1, 1998. (Exhibits (10)(iii)2, 5 and 17)

      Retirement Benefit Restoration Plan of the Company, effective May 1, 1993,
      together with Amendments thereto effective July 23, 1993 and December 1,
      1998. (Exhibits (10)(iii)3, 4 and 18)

      Agreement, made March 14, 1994, by and between Registrant and Mellon Bank,
      N.A.,  amending  and  restating,  effective  April 1,  1994,  Registrant's
      Savings  Incentive  Plan and related Trust  Agreement with The Bank of New
      York, together with amendments dated July 22, 1994, and December 16, 1994.
      (Exhibits (10)(iii)7, 8 and 9)

      Executive Incentive Compensation Plan of the Company, effective January 3,
      1993,  as  amended  and  restated,  effective  April  4,  1995.  (Exhibits
      (10)(iii)6 and 10)

      Stock Plan for Outside Directors of the Company, dated November 17, 1995.
      (Exhibit (10)(iii)11)

      Management  Incentive  Program of the  Company,  effective  April 1, 1994,
      together with Amendment thereto dated July 25, 1997. (Exhibits (10)(iii)12
      and 13)

                                     101


<PAGE>



      Change-of-Control  Severance Policy, as approved by the Board of Directors
      October  23, 1998 and,  effective  December  1, 1998,  for all  management
      employees of the Company.

      Form of Employment  Agreement,  dated October 23, 1998, effective December
      1, 1998, for all officers of the Company.

      Employment Agreement,  dated October 23, 1998, effective December 1, 1998,
      for the President and Chief Executive Officer of the Company.

(b)   REPORTS ON FORM 8-K

      During the last quarter of the period covered by this Report and including
      the  period to the date  hereof,  the  following  Reports on Form 8-K were
      filed by the Company:

      1)    Report  dated  October 9, 1998,  relating to a special  shareholders
            meeting held on September  25, 1998, at which more than the required
            two-thirds of outstanding  shares of the Company were voted in favor
            of  establishing a holding  company,  CH Energy Group,  Inc.,  which
            holding   company  is  more  fully   described   under  the  caption
            "Competition/Deregulation" in Item 7 of Part I of this Annual Report
            on Form 10-K and the Company's Registration  Statement, on Form S-4,
            Registration No. 333-52797 filed with the SEC.

      2)    Report dated December 22, 1998, relating to the jury decision in the
            lawsuit  filed  by the  City of  Newburgh  against  the  Company  as
            reported   under  the  caption   "Former   Manufactured   Gas  Plant
            Facilities"  in  Note 9 -  "Commitments  and  Contingencies"  to the
            Company's  Consolidated  Financial  Statements  made a part  of this
            Annual Report on Form 10-K.

      3)    Report dated January 15, 1999,  relating to the Company's  sale of a
            tranche of Medium Term Notes in the  aggregate  principal  amount of
            $20 million,  such sale being  authorized  under the Company's shelf
            registration  statement on Form S-3  (Registration No. 333-65597) as
            filed with the SEC.

(c) EXHIBITS REQUIRED BY ITEM 601 OF REGULATION S-K

      Incorporated herein by reference to subpart (a)-3 of Item 14, above.

                                     102


<PAGE>


(d)   Financial  Statement Schedule required by Regulation S-X which is excluded
      --------------------------------------------------------------------------
      from the Company's Annual Report to Shareholders for the fiscal year ended
      --------------------------------------------------------------------------
      December 31, 1998
      -----------------

      Not applicable, see Item 8 hereof.

                                  SIGNATURES
                                  ----------

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

                        CENTRAL HUDSON GAS & ELECTRIC CORPORATION

                        By (SGD.) John E. Mack III
                        --------------------------
                             (John E. Mack III,
                             Chairman of the Board

Dated:  March 1, 1999

                                     103


<PAGE>



            Pursuant to the requirements of the Securities Exchange Act of 1934,
this  Report  has been  signed  below by the  following  person on behalf of the
Company and in the capacities and on the date indicated:

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

(a) Principal Executive
      Officer or Officers:

(SGD.) John E. Mack III
-----------------------
(John E. Mack III)                   Chairman of
                                     the Board            March 1, 1999

(SGD.) Paul J. Ganci
-----------------------
(Paul J. Ganci)                      President and
                                     Chief Executive
                                     Officer              March 1, 1999

(b) Principal Accounting
      Officer:

(SGD.) Donna S. Doyle
-----------------------
(Donna S. Doyle)                     Controller           March 1, 1999

(c) Chief Financial
      Officer:

(SGD.) Steven V. Lant
-----------------------
(Steven V. Lant)                    Chief Financial
                                    Officer, Treasurer
                                    and Corporate
                                    Secretary             March 1, 1999

(d) A majority of Directors:

Jack Effron*, Frances D. Fergusson*,
Heinz K. Fridrich*, Edward F.X.Gallagher*,
Paul J. Ganci*, Charles LaForge* and
John E. Mack III*, Directors

By  (SGD.) John E. Mack III
---------------------------
          (John E. Mack III)                              March 1, 1999




                                     104


<PAGE>


-----------------
*John E. Mack III, by signing his name hereto,  does thereby sign this  document
for himself and on behalf of the persons named above after whose printed name an
asterisk  appears,  pursuant to powers of attorney duly executed by such persons
and filed with the Securities and Exchange Commission as Exhibit 24 hereof.

                                     105


<PAGE>