<PAGE>                                                            EXHIBIT 13

                             FINANCIAL HIGHLIGHTS



Earnings Per Share: (Page 18)

      Earnings per share of common stock were $2.74 in 1995
compared to $2.68 in 1994.  This $.06 or 2% increase in earnings
per share resulted primarily from decreased operation and
maintenance costs, decreased interest expense and a gain from the
sale of long-term stock investments.  Partially offsetting these
increases in earnings in 1995 were decreases in electric and gas
net operating revenues due to decreased sales attributable
largely to the warmer winter weather experienced in the first
quarter of 1995 and decreased sales to IBM.

Dividends Per Share: (Page 29)

      The quarterly dividend rate was increased to $.525 per
share, effective June 23, 1995.  This represented an increase of
1% over the previous quarterly rate of $.52 per share.  Dividends
paid to shareholders in 1995 were $2.09 per share as compared to
$2.07 per share in 1994.  No portion of the 1995 dividend
constitutes a return of capital.

Economy:

      The past year proved to be a period of growth and recovery
for the Company's service area.  The Company's economic
development efforts coupled with State and local government
efforts helped to attract over 4,300 value-added jobs throughout
the region since the spring of 1993.  Included in these value-
added jobs are 900 positions brought to the area in the last two
years by a semi-conductor manufacturing company.

Electric Sales: (Page 21)

      Sales of electricity within the Company's service territory
decreased 2% in 1995.  Sales of electricity to residential
customers decreased 2% due to a decrease 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.  Electric sales to industrial customers decreased
6% due primarily to an 18% decline in usage by IBM.  





 
                                    - 1 -
<PAGE>
Gas Sales: (Page 21)

      Firm sales of natural gas decreased 5% in 1995.  Sales of
gas to residential customers decreased 10% due to a decrease in
usage per customer.  Commercial sales decreased 1% due largely to
a decrease in usage per customer.  Firm gas sales to industrial
customers remained stable when compared to 1994.  When normalized
for effects of weather, firm gas sales increased 3% in 1995. 
Interruptible gas sales increased 70% due to a significant
increase in the boiler gas usage at the Company's fossil-fueled
generating plants.

Rate Proceeding - Electric: (Page 16)

      The Company has no pending electric rate case filed with the
Public Service Commission (PSC) and cannot predict with certainty
the date of its next filing.
      The last rate increase was issued and effective February 11,
1994 which increased base rates by $5.133 million (or
approximately 1.3% on an annual basis), based on a 10.6% return
on common equity, and an 8.58% return on total invested capital.

Rate Proceeding - Gas: (Page 17)

      The Company filed a request with the PSC on November 10,
1995 to increase its base rates for firm natural gas.  The
request, if accepted by the PSC, would effectively produce a net
increase in firm gas revenues of $2.422 million, an 11.50% return
on common equity and a 9.22% return on total invested capital. 
The Company can make no prediction as to what further action the
PSC will take on this gas rate increase request.

Common Stock: (Note 5)

      Issuances under the Automatic Dividend Reinvestment and
Stock Purchase Plan and Customer Stock Purchase Plan increased
the number of common shares outstanding by 257,587 shares to a
total of 17,496,051 as of December 31, 1995.  At the end of 1995,
a share of common stock was selling at $30.875 while the book
value per share was $25.96.  

Financing Program: (Notes 5 & 6)

      On October 1, 1995, the Company optionally redeemed all of
its outstanding 7.44% Cumulative Preferred Stock at a price of
$101.22 per share.  The associated cash requirements were
financed from internal funds and from net proceeds of $7.0
million realized from the issuance of 257,587 shares of common 



                                    - 2 - 
<PAGE>
stock in 1995 through the Company's Automatic Dividend
Reinvestment and Stock Purchase Plan and its Customer Stock
Purchase Plan.  

Taxes: (Page 26)

      In 1995, the Company incurred $95.7 million for operating
taxes levied by federal, state and local governments,
representing 19 cents of every dollar of revenues.










































                                    - 3 -
<PAGE>
<TABLE>
FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA*  
(Thousands of Dollars)
<CAPTION> <S>                                            1995          1994            1993           1992          1991
Operating Revenues                                   <C>           <C>            <C>            <C>           <C>
  Electric.................................          $  409,445    $  411,082      $  422,925     $  427,436    $  424,121
  Gas......................................             102,770       104,586          94,448         96,121        70,615
    Total..................................             512,215       515,668         517,373        523,557       494,736

Operating Expenses
  Operations...............................             274,665       274,497         274,477        283,787       267,339
  Maintenance..............................              29,440        32,716          34,486         34,226        31,504
  Depreciation and amortization............              41,467        40,380          39,682         39,596        37,230
  Taxes, other than income tax.............              66,709        66,899          65,564         66,339        60,554
  Federal income tax.......................              29,040        28,043          28,603         25,111        22,613
    Total..................................             441,321       442,535         442,812        449,059       419,240
Operating Income...........................              70,894        73,133          74,561         74,498        75,496
Other Income and Deductions
  Allowance for equity funds
   used during construction................                 986           866             934            596           921
  Federal income tax.......................                 353         1,237           1,445            748         1,252
  Other - net..............................               8,886         6,296           5,167          4,427           854
    Total..................................              10,225         8,399           7,546          5,771         3,027
Income before Interest Charges.............              81,119        81,532          82,107         80,269        78,523
Interest Charges...........................              28,397        30,603          31,717         32,581        35,582
Net Income.................................              52,722        50,929          50,390         47,688        42,941
Premium on Preferred Stock Redemption-Net..                 169          -               -              -              -
Dividends Declared on 
 Cumulative Preferred Stock................               4,903         5,127           5,562          5,544         5,659
Income Available for Common Stock..........              47,650        45,802          44,828         42,144        37,282
Dividends Declared on Common Stock.........              36,459        35,541          34,497         31,545        29,800
Amount Retained in the Business............              11,191        10,261          10,331         10,599         7,482
Retained Earnings - beginning of year......              79,284        69,023          58,692         48,093        40,611
Retained Earnings - end of year............          $   90,475    $   79,284      $   69,023     $   58,692    $   48,093

</TABLE>                                                           - 4 -
<PAGE>
<TABLE>
FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA* (CON'T)
(Thousands of Dollars)
<CAPTION>                                                             
                                                         1995          1994            1993           1992          1991
<S>                                                  <C>           <C>            <C>            <C>           <C>
Common Stock
  Average shares outstanding (000s)........              17,380        17,102         16,725         15,901        15,530
  Earnings per share on 
   average shares outstanding..............               $2.74         $2.68          $2.68          $2.65         $2.40
  Dividends declared per share.............              $2.095        $2.075         $2.045          $1.98         $1.90
  Book value per share (at year-end).......              $25.96        $25.34         $24.65         $23.60        $22.84

Total Assets...............................          $1,250,092    $1,250,781     $1,264,240     $1,167,124    $1,141,128
Long-term Debt.............................             389,245       389,364        391,810        441,096       416,030
Cumulative Preferred Stock.................              56,030        81,030         81,030         81,030        81,030
Common Equity..............................             454,239       436,731        417,846        378,214       360,203





* This summary should be read in conjunction with the Consolidated Financial Statements and Notes 
  thereto included in the "Financial Section" of this Annual Report.












                                                                      - 5 -
</TABLE>
<PAGE>
                    MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                 FINANCIAL CONDITION AND RESULTS OF OPERATIONS


COMPETITION  

General

      The Company is subject to regulation by the Public Service
Commission of the State of New York (PSC) and by the Federal
Energy Regulatory Commission (FERC).  As a result, the Company is
substantially free from direct competition at the retail level,
at this time.  The enactment of the Energy Policy Act of 1992 and
the FERC's rules providing open-access to interstate gas
pipelines, as well as federal and state proposals to introduce
competition to the utility market, will expose the electric and
gas industry to additional risks and uncertainties.  The
introduction of increased competition and related regulatory and
legislative requirements may unfavorably impact the position of a
utility as a franchised monopoly.  The Company cannot predict the
scope, timing and consequences of these changes; however, such
changes could result in a write-off of utility assets.  See the
following subcaption entitled "Continuing Applicability of SFAS
No. 71."

Recent Developments

            FERC Notice of Proposed Rulemaking (NOPR):  On 
March 29, 1995, FERC issued a NOPR on generic requirements for
electric transmission tariffs.  FERC proposes to require all
jurisdictional utilities (including the Company) to offer
comparable service, open-access transmission tariffs for network
and point-to-point service.  Such utilities would also be
required to take transmission service under the same tariffs and
each ancillary service they offer in their rates and to effect
functional unbundling of their transmission operations.  Included
with the open-access NOPR is a supplementary NOPR on stranded
costs, in which FERC endorses the principle of stranded cost
recovery.  Stranded costs are prudently incurred utility costs
which would be recoverable under the current system of
regulation, but which might not be recoverable in a more
competitive electric industry environment.

            New York - Electric 

            Competitive Opportunities Proceeding:  In 1993, the PSC
initiated a proceeding to address numerous issues related to
competition in the electric energy markets in New York State. 
Two phases of this proceeding have been established to address
the issues to be considered.  

                                    - 6 -
<PAGE>
      Phase I of such proceeding, which was completed in the
Summer of 1994, resulted in the approval by the PSC of "flexible
rates" that would allow electric utility companies to negotiate
individual contracts with certain large industrial and commercial
customers to provide electricity at prices lower than currently
offered.  
      Phase II of such proceeding, which is now underway, has an
overall objective of identifying regulatory and rate-making
practices that will assist in the transition to a more competi-
tive electric industry designed to increase efficiency in the
provision of electricity while maintaining safety, environmental,
affordability and service priority goals.  Issues related to both
wholesale and retail competition also are being examined in Phase
II of this proceeding.
      By Opinion and Order, issued and effective June 7, 1995, the
PSC adopted principles to guide the transition to competition
which included a reasonable opportunity to recover stranded
investments and called for further investigation of whether
vertically integrated utility corporate structures would impede
or obstruct development of effective wholesale or retail
competition.  The PSC next directed a review of certain
alternative models for competition within New York State's
electric industry.  The parties to such proceeding filed their
comments with the PSC, including the following:
      The Energy Association of New York State (Energy
Association), which is a group comprised of the eight major
investor-owned gas and electric utilities serving New York State
(including the Company), recommended a wholesale poolco model. 
The key elements of this model include, among others, the
following which assumes full recovery of stranded costs: 

                  (i) setting up an unregulated market for
                  competitively selling wholesale bulk power into a
                  pool, regardless of whether that power is provided
                  by investor-owned utilities, non-utility
                  generators, power marketers, cooperatives or on-
                  site generators and

                  (ii) creating an Independent System Operator to
                  direct the operation of the State's transmission
                  system so that bulk power will be delivered safely
                  and reliably.

      The New York State Power Authority (NYPA) recommended a
retail bilateral contract model under which all customers would
have the choice to select their electricity suppliers according
to individually negotiated arrangements.  The bilateral model
supported by NYPA Staff would incorporate a power exchange that
would accommodate the development of a spot market and a single 


                                    - 7 -
<PAGE>
transmission system operator that would have the ultimate
responsibility for the reliable operation of the system.  NYPA
recommended that it assume the role of the single owner and
operator of the bulk power transmission system in New York State. 
      The Staff of the PSC filed a recommendation for a flexible
poolco model of competition that provides a full range of
competitive alternatives, including retail and wholesale
competition, market-clearing spot prices for electricity
purchases and physical bilateral contracts.  The PSC Staff model
includes divestiture of utility generation assets through sale or
spin-off.  The PSC Staff proposed that shareholders absorb a
portion of stranded costs.  The Staff's plan calls for testing
the new market structure in the wholesale market in late 1997 and
beginning the transition to a competitive retail market by early
1998.
      On December 21, 1995, the Administrative Law Judge and the
Deputy Director, Energy and Water Division of the Department of
Public Service issued a recommended decision in Phase II.  In
summary, this decision recommended that the PSC adopt a
transitional plan leading to a flexible retail poolco model.  The
first stage would be a wholesale poolco model with an independent
system operator and market mechanisms to allow an orderly
movement to full retail access.  Under their recommended
decision, reliability of the bulk power system is recognized to
be critical and should not be compromised to achieve lower prices
from retail access.  Stranded costs would be recovered by non-
bypassable access charges or wire charges, and must be determined
to be prudent, verifiable and non-mitigable.  A utility would be
entitled to present a case as to why it would be reasonable to
allow recovery of its stranded costs, subject to allowing
consumers a reasonable opportunity to realize savings and receive
reasonable prices; thus, a careful balance of interest and
expectations is required and may vary utility by utility. 
Utilities would be required to individually file for PSC
approval, within six months of the PSC's order, a long-term
proposal addressing, among other things, (i) recoverable stranded
costs, (ii) the separation of generation from transmission and
distribution, either functionally, structurally or by
divestiture, (iii) phasing in retail access for all customers,
and (iv) the utility's proposed relationship with an independent
system operator.
      The Company is considering the impact the recommended
decision would have on its business and can make no prediction as
to what action the PSC will take with respect to Phase II, except
that if the PSC were to adopt the stranded cost recommendations
in such decision, the Company's ability to recover its plant
costs and regulatory assets in rates would be at risk.  Action by
the PSC is expected by July 1, 1996.  



                                    - 8 -
<PAGE>
            Niagara Mohawk Proposal:  On October 6, 1995, as
publicly reported by Niagara Mohawk Power Corporation (Niagara
Mohawk), Niagara Mohawk filed a proposal with the PSC which
provides for a corporate restructuring designed to create an
open, competitive retail electricity market, deregulate
electricity generation in Niagara Mohawk's service area, allow
its customers, by year 2000, to choose their electricity supplier
and freeze or reduce electricity prices over the next five years. 
The restructuring would place Niagara Mohawk's power plants
(which would include Niagara Mohawk's interest in the Nine Mile 2
Plant and Niagara Mohawk's interest in the Roseton Plant) and
unregulated generator contracts in a separate generating company,
with the remaining business being separated into a holding
company with regulated subsidiaries that would transmit and
distribute electricity and natural gas and supply energy services
to core customers.  This holding company would also have
unregulated subsidiaries that would engage in marketing,
brokering and service activities.  In addition, Niagara Mohawk
also put forth in its proposal a request for "relief from
overpriced unregulated generator contracts that were mandated by
public policy."  In its proposal, Niagara Mohawk indicated that
if it were unable to negotiate new contracts with unregulated
generators, Niagara Mohawk would propose to take possession of
the unregulated generator projects and compensate their owners
through Niagara Mohawk's power of eminent domain.  Niagara Mohawk
would then resell the projects, allowing the projects to sell
electricity into the competitive pool at market prices.  Niagara
Mohawk has indicated that its proposals are offered as an
integrated package, and not piecemeal.
      Niagara Mohawk has stated that if it appears that such a
proposal were unachieveable, Niagara Mohawk could not rule out
the possibility of a restructuring under Chapter 11 of the United
States Bankruptcy Code.  
      The Company has intervened in the proceeding but cannot
predict whether Niagara Mohawk's proposal will be effected or, if
effected, what impact, if any, Niagara Mohawk's proposal would
have on the gas and electric utility business in New York State,
including the Company's franchise area, or what effect Niagara
Mohawk's proposal and/or a restructuring under Chapter 11 of the
United States Bankruptcy Code would have on the Company's
interest in the Nine Mile 2 Plant or the Company's interest in
the Roseton Plant.

            New York - Natural Gas  

      In October 1993, the PSC initiated a proceeding to address
issues associated with the restructuring of the emerging
competitive natural gas market, a process which had been set in
motion by Order 636 of FERC, which requires pipeline gas 


                                    - 9 -
<PAGE>
suppliers to separate natural gas sales service from
transportation and storage service, and which allows Local
Distribution Companies (LDCs), such as the Company and other end
users, open access to the interstate pipeline system for the
purpose of transporting their gas from gas producing areas to the
customer.  This PSC proceeding examined such issues to determine
how best to implement changes in the services provided by the
LDCs' segment of the gas industry, so that the benefits of the
increased competition fostered by federal actions are fully
realized by customers.  By Opinion and Order, issued and
effective December 20, 1994, the PSC set forth the policy
framework to guide the transition of New York's gas distribution
industry in the post-FERC Order 636 environment.  Such PSC Order
essentially extends a number of the FERC "unbundling" concepts,
found in said Order 636 to the retail gas business.  In
compliance with such Order, the Company and other LDCs filed
proposed open-access compliance tariffs with the PSC on 
November 9, 1995.  At this time, the Company can make no
prediction as to whether or when the PSC will take action on
these filings.

            Mergers in the Electric Industry

      In response to the increasingly competitive environment,
utilities across the country have been reorganizing to better
position themselves financially and territorially for the future. 
Thus, mergers and possible mergers have been reported in business
publications throughout the past year.  The Company cannot
predict at this time what effect these mergers or future mergers
will have on the utility industry in New York State.

Continuing Applicability of SFAS No. 71

      The Company's electric and gas rates, currently subject to
approval by the PSC, are designed to recover the Company's costs
of providing electric and gas services to its customers.  A
primary difference between a rate regulated entity and an
unregulated entity is the timing of recognizing certain assets
and expenses for financial reporting purposes.  The Statement of
Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS No. 71), prescribes
the method to be used to record the financial transactions of a
regulated entity.  If the Company were to determine that its
business fails to meet the criteria of SFAS No. 71, it would have
to eliminate from its financial statements all transactions
prescribed by the regulators that would not have been recognized
if it had been a non-regulated company which could result in a
write-down or write-off of utility assets.  Currently, such
transactions are included in the Company's consolidated financial


                                    - 10 -
<PAGE>
statements as regulatory assets and liabilities, as described in
Note 1 of the Notes to the Company's Consolidated Financial
Statements for the year ended December 31, 1995 (Notes).  An
unfavorable impact on the financial results of the Company would
occur if the Company determined that it could no longer apply
SFAS No. 71.  The Company believes, however, that it meets the
criteria for operating as a rate regulated entity, as prescribed
by SFAS No. 71, at this time, but cannot predict whether it will
continue to meet such criteria, in whole or in part, in the
future.

Company's Response  

      Currently, the Company is the lowest cost electric provider
in New York State and, through strategies and cost-reduction
measures such as those described below, will strive to remain in
that position.
      The Company's goal is to be the energy supplier of
competitive choice to its customers.  In order to achieve this
goal, the Company has implemented, and will continue to implement
appropriate cost-reduction measures.  Measures which have been
put into place to improve the Company's position in a competitive
marketplace include:  the operation of certain of its generating
units on alternating six-month intervals and/or the placement of
certain of its generating units on "ready reserve"; satisfying a
portion of its power requirements with purchased power from
energy providers outside the Company's service territory at a
lower cost than if such power were generated by the Company;
reduction of contractor costs by redeploying its own workforce;
redeeming or refinancing debt or preferred stock at lower
interest rates; and a continued reduction of its workforce
through attrition.
      Due to the rapid change in the utility industry, the Company
has considered and will continue to consider various strategies
designed to enhance its competitive position and to adapt to
anticipated changes in its business.  In November of 1995, the
Company entered into a five-year agreement with the Boston Edison
Company to transport natural gas to one of the electric
generating plants of the Massachusetts-based utility for a demand
charge.  The demand charge being received for this service will
result in an estimated 4% savings to our natural gas customers. 
Another strategy implemented to prepare the Company for future
changes in the industry is capacity brokering.  LDCs, such as the
Company, are permitted to offer their unutilized firm
transportation service to others for a fee.  This program, which
was used at various times in 1995 and 1994, gives the Company an
opportunity to defray some or all of the monthly fixed charges
when its firm gas transportation capacity is not fully utilized
and, as a result, reduces the costs billed to the Company's firm
gas customers.  

                                    - 11 -
<PAGE>
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 $49.3 million in 1995, a $7.9 million decrease from
the $57.2 million expended in 1994.  As shown in the table below,
cash construction expenditures for 1996 are estimated to be $61.3 
million, an increase of $12.0 million compared to 1995
expenditures.  Internal sources funded 100% of the 1995 cash
construction expenditures and are presently estimated to fund
100% of the forecasted cash construction expenditures for 1996.
      In 1996, the Company expects to fund any external funding
requirements through issuances of common stock pursuant to its
Automatic Dividend Reinvestment and Stock Purchase Plan and its
Customer Stock Purchase Plan and by issuing additional debt
securities.


































                                    - 12 -
<PAGE>
<TABLE>
      Estimates of construction expenditures, internal funds available, mandatory and optional redemption of long-term
securities, and working capital requirements for the five-year period 1996-2000 are set forth by year in the following
table:
<CAPTION>                                                                                                         Total
                                                   1996        1997         1998        1999          2000      1996-2000
                                                                          (Thousands of Dollars)
<S>                                              <C>         <C>          <C>         <C>           <C>         <C>
Construction Expenditures*:
  Electric............................           $39,200     $36,400      $42,900     $36,500       $39,100     $194,100
  Gas.................................             7,300       7,700        7,900       8,200         8,500       39,600       
  Common..............................             9,500       8,200        8,400       8,600         7,600       42,300       
  Nuclear fuel........................             5,300        -           5,800        -            5,900       17,000
      Total...........................            61,300      52,300       65,000      53,300        61,100      293,000

Internal Funds Available:                         64,900      55,600       56,600      59,800        62,100      299,000

Excess of Construction
 Expenditures over Internal Funds.....            (3,600)     (3,300)       8,400      (6,500)       (1,000)      (6,000)

Mandatory Redemption of Long-term 
 Securities:
 Long-term debt.......................              -            100          100      20,100        35,100       55,400 

Optional Redemption of Long-term
 Securities:
 Long-term debt.......................            30,000        -            -           -             -          30,000
 Preferred stock......................            13,000        -            -           -             -          13,000

Working Capital Requirements..........            (2,900)      3,000        3,000       3,000         3,000        9,100

Total Cash Requirements...............           $36,500     $  (200)     $11,500     $16,600       $37,100     $101,500

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

                                                                     - 13 -
</TABLE>
<PAGE>
      Estimates of construction expenditures are subject to
continuous review and adjustment, and actual expenditures may
vary from such estimates.  These construction expenditures
include capitalized overheads, nuclear fuel and the debt portion
of AFDC.  
      Included in the construction expenditures are expenditures
which are required to comply with the Clean Air Act Amendments of
1990.  The Company estimates such required expenditures will cost
approximately $6.1 million.  A discussion of the Clean Air Act
Amendments is included in Note 8 of the Notes under the caption
entitled "Environmental Matters - Clean Air Act Amendments."
      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 for the five-year period
1996-2000.  During this same five-year period, total external
financing requirements are projected to amount to $101.5 million,
of which $55.4 million is related to the mandatory redemption of
long-term securities and $43.0 million is related to the optional
redemption of long-term securities. 

CAPITAL STRUCTURE 

      Over the past few years, the Company has substantially
increased its common equity ratio through retention of a portion
of its earnings, offerings of its common stock to the public, 
issuances of its common stock under its Automatic Dividend
Reinvestment and Stock Purchase Plan and its Customer Stock
Purchase Plan and redemption of debt and preferred stock.  One
result of these recent increases in its common equity ratio has
been a significant improvement in its interest coverage ratios
(as shown under "Financial Indices" on page 30 of this Report)
which have also been improved by 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 its bond ratings since 1991.  The
Company's bond ratings, which were recently reaffirmed during
1995, are "A-" or equivalent by Standard & Poor's Corporation,
Moody's Investors Service, Inc. and Duff & Phelps Credit Rating
Co., and "A" by Fitch Investors Service.  Standard & Poor's
Corporation has revised its outlook on the Company from "stable"
to "positive" in August 1995, citing the Company's "expectation
of sustainable and modest financial improvement based on gradual
economic growth and lower capital spending requirements."  The
Company's long-term goal is to achieve and maintain bond ratings
at the "A" level.






                                    - 14 -
<PAGE>
      Set forth below is certain information with respect to the
Company's capital structure at the end of 1995, 1994 and 1993:

                                          Year-end Capital Structure   
                                     1995              1994             1993
Long-term debt ..........            42.8%             43.0%           47.0%
Short-term debt .........              -                 .3              - 
Preferred stock .........             7.5               8.9             8.6
Common equity ...........            49.7              47.8            44.4
                                    100.0%            100.0%          100.0%

FINANCING PROGRAM 

      On December 1, 1995, the Company paid in full at maturity
its 4.85% Promissory Notes.  The $2.6 million principal amount
was funded through internal sources.
      The Company redeemed all of its outstanding shares of 7.44%
Cumulative Preferred Stock (par value $100 per share) on 
October 1, 1995 at a redemption price of $101.22 per share.  The
$12.1 million total redemption price paid and associated costs
were funded through internal sources and from the issuance of
257,587 additional shares of common stock during 1995 through the
Company's Automatic Dividend Reinvestment and Stock Purchase Plan
and its Customer Stock Purchase Plan.
      On September 1, 1994, the Company retired at maturity its 
8 1/8% Series First Mortgage Bonds, of which $50 million
principal amount was issued and outstanding.  The associated cash
requirements were financed from internal funds and from the
issuance of 285,317 additional shares of common stock during 1994
through the Company's Automatic Dividend Reinvestment and Stock
Purchase Plan and its Customer Stock Purchase Plan.  
      In 1993, the Company optionally redeemed two series of First
Mortgage Bonds totaling $40 million and two series of preferred
stock totaling $34.2 million.  These securities were refunded
with similar securities bearing lower interest or dividend rates. 
In March 1993, the Company issued 700,000 additional shares of
common stock through a public offering.  These funds were used to
reduce short-term debt outstanding and to fund working capital
requirements.  
      The Company optionally redeemed on January 1, 1996 all of
its outstanding shares of 7.72% 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.  Financial markets will continue
to be monitored throughout 1996 by the Company for opportunities
to refinance debt or preferred stock at lower cost.
      By an Order issued and effective October 17, 1994, the PSC
granted the Company authorization to issue and sell through
December 31, 1996 up to an additional $80 million of securities. 
This $80 million can be composed of Medium Term Notes solely or a


                                    - 15 -
<PAGE>
combination of Medium Term Notes and up to $40 million of Common
Stock.  For more information with respect to such Order and the
Company's financing program in general, see Notes 5 and 6 of the
Notes.

SHORT-TERM DEBT  

      As more fully discussed in Note 4 of the Notes, the Company
has a revolving credit agreement with four commercial banks for
borrowing up to $50.0 million through December 14, 1997.  In
addition, the Company continues to maintain confirmed lines of
credit totaling $1.5 million with two regional banks.  Also, the
Company has short-term credit agreements with four commercial
banks totaling $130.0 million in the aggregate.  Such agreements
give the Company competitive options to minimize its cost of
short-term debt 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 $52.0 million in the
aggregate.

RATE PROCEEDINGS 

            ELECTRIC:  The Company has no pending electric rate
case filed with the PSC and cannot predict with certainty the
date of its next filing.  The Company's most recent electric rate
case was filed November 12, 1992 and, by Order Determining
Revenue Requirement and Rate Design issued and effective February
11, 1994, the PSC permitted the Company to increase its electric
base rates by $5.133 million (or approximately 1.3% on an annual
basis), based on a 10.6% return on common equity, and an 8.58%
return on total invested capital.  
      The Company's electric fuel cost adjustment clause also
provides for a partial sharing of fuel cost variations, pursuant
to an incentive/penalty formula.  The PSC requires a sharing
between the customers and the Company of variations in actual
fuel costs from the forecasted amounts which have been approved
by the PSC for a specific twelve-month period, whereby the
Company bears 20% of the first $10 million of variation and 10%
of the second $10 million of variation.  Any variations in excess
of $20 million are credited or charged, as appropriate, in total
to the customers.  In addition, the Company credits to customers
the net revenue (gross revenue less incremental costs,
principally fuel) from sales of electricity to other utilities
after adjusting for an 80%/20% sharing between customers and the
Company, respectively, of any variations from forecasted amounts
which have been approved by the PSC for a specific twelve-month
period.  See subcaption "Deferred Electric Fuel Costs" of Note 1
of the Notes.



                                    - 16 -
<PAGE>
            GAS:  On November 10, 1995, the Company filed a request
with the PSC to increase its base rates for firm natural gas
service to produce a net increase in firm gas revenues of $2.422
million based on projected operations during the rate year
comprised of the period November 1, 1996 through 
October 31, 1997.  This would represent an overall increase in
firm gas revenues of 3%.
      The higher rates have been requested to cover increases in
capital and operating costs that are projected for the rate year
that are not adequately provided for in present rates and will
not be provided for by increased sales.
      In its filing, the Company requested an 11.50% return on
common equity and a 9.22% return on total invested capital.  It
is not expected that any new gas rates, which may result from
this filing, will become effective before October 1, 1996.
      Based on the Company's proposed allocation between firm
customer classes, the proposed increase would be approximately
4.9% for residential customers and 1.0% for commercial/industrial
customers.  By Order issued and effective December 4, 1995, the
PSC suspended the rate increase through April 7, 1996.
      The Company can make no prediction as to what further action
the PSC will take on its request, including the amount of any gas
rate increase which may be authorized by the PSC.

OTHER DEVELOPMENTS

      Electric Sales to IBM: The Company's largest customer is
International Business Machines Corporation (IBM), which
accounted for approximately 10%, 12% and 14% of the Company's
total electric revenues for the years ended December 31, 1995,
1994 and 1993, respectively.  Published reports indicate that IBM
reduced its employment in the Company's service territory by
approximately 400 employees in 1995, 2,600 employees in 1994 and
8,400 employees in 1993 to remain competitive in a challenging
marketplace.  These reductions bring the total number employed in
the Company's service territory to 10,100, as compared to the
peak level of IBM employment in excess of 30,000 in 1985.  In
1995, IBM closed its facility in Kingston, New York and relocated
1,500 of its workers to its facility in Poughkeepsie, New York. 
Both facilities are in the Company's service territory.  During
1993, IBM phased out its semiconductor manufacturing operations
at its East Fishkill, New York facility, which is also in the
Company's service territory.  This downsizing of IBM is the main
contributor to a decline in 1995 of 18% in industrial electric
sales.  This is in addition to the 1994 and 1993 declines in
electric sales to IBM of 17% and 20%, respectively.
      New Accounting Standards: The Company is currently reviewing
the accounting implications of SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets To Be
Disposed Of," which is effective for its 1996 financial 

                                    - 17 -
<PAGE>
statements.  As discussed in more detail in Note 1 of the Notes,
the Company does not expect that the adoption of this standard
will have a material impact on the Company. 
      Environmental Issues: On an ongoing basis, the Company
assesses environmental issues which could impact the Company and
its ratepayers.  Notes 1, 2 and 8 of the Notes, discuss current
environmental issues affecting the Company, including (i) the
recent decommissioning study of the Nine Mile 2 Plant, (ii) the
Clean Water Act and Clean Air Act Amendments of 1990, 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 after that City discovered allegedly hazardous
coal-tar material on its property, in 1994, allegedly migrating
from a former manufactured gas plant facility of the Company
located in Newburgh, New York.

RESULTS OF OPERATIONS

      The following discussion and analysis includes an
explanation of the significant changes in revenues and expenses
when comparing 1995 to 1994 and 1994 to 1993.  Additional
information relating to changes between these years is provided
in the Notes on pages 36 through 52 of this Report.

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:
                                                1995       1994       1993
Average shares outstanding (000s)..            17,380     17,102      16,725
Earnings per share.................            $ 2.74     $ 2.68      $ 2.68
Return earned on common equity 
 per books*........................             10.5%      10.7%       11.1%

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

     Earnings per share in 1995 increased $.06 per share over
1994 results primarily because of a decrease in maintenance costs
of the Company's electric generating plants and gas distribution
and transmission system in 1995.  A decrease in the operation and
maintenance costs associated with the Nine Mile 2 Plant
contributed to the total decrease in operation and maintenance
costs as well.  Also contributing to the increase in 1995
earnings was reduced interest expense in 1995 resulting primarily
from the 1994 retirement at maturity of $50 million 8 1/8% Series

                                   - 18 -
<PAGE>
First Mortgage Bonds, increased earnings related to PSC incentive
programs related to fuel costs and energy efficiency, and an $.08
per share gain from the sale of long-term stock investments in
June and December 1995.
     Partially offsetting these increases to earnings were
significant decreases in electric and gas net operating revenues
attributable primarily to decreased sales from the warmer winter
weather experienced in the first quarter of 1995, as compared to
the same period of 1994, as well as decreased sales to a large
industrial customer (IBM) in 1995.  The earnings per share in
1995 were also unfavorably impacted by increased depreciation
expense on the Company's plant and equipment, increased property
taxes and an increase in the number of shares of common stock
outstanding. 
     In 1994, earnings per share remained unchanged from 1993, 
although earnings from normal operations increased $.03 per
share.  Earnings in 1993 included a $.03 per share gain from the
sale of long-term stock investments.  The $.03 per share increase
in earnings from normal operations in 1994 was due primarily to
lower interest charges on the Company's outstanding debt,
resulting in large part from retirement at maturity on 
September 1, 1994 of $50 million principal amount of 8 1/8%
Series First Mortgage Bonds, the refinancing of high interest
rate debt and preferred stock in 1993, and increased gas net
operating revenues.
     These 1994 increases were partially offset, however, by
reduced earnings from PSC incentive programs related to fuel
costs and energy efficiency programs, decreased electric net
operating revenues attributable primarily to decreased sales to
large industrial customers, an increase in the number of shares
of common stock outstanding, and decreased earnings of non-
regulated subsidiary companies.



















                                   - 19 -
<PAGE>
<TABLE>
OPERATING REVENUES

     Total operating revenues decreased $3.5 million (.7%) in 1995, as compared to 1994,
and $1.7 million (.3%) in 1994, as compared to 1993.

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

                                            Increase or (Decrease) from Prior Year 
                                               1995                          1994                          
                                    Electric   Gas       Total     Electric    Gas      Total             
                                                      (Thousands of Dollars)
<S>                           <C>           <C>        <C>      <C>      <C>      <C>
Customer sales............. $(7,711)   $ 4,779   $(2,932)   $ (6,105)  $ 4,555   $(1,550) 
Sales to other utilities...   2,017        -       2,017        (831)      -        (831)
Increase in base rates.....     -          -         -         4,704       -       4,704                 
Fuel cost adjustment.......   3,346     (6,564)   (3,218)     (7,534)    6,234    (1,300)
Deferred revenues..........   1,374         21     1,395      (3,405)     (881)   (4,286)
Miscellaneous..............    (663)       (52)     (715)      1,328       230     1,558 
       Total............... $(1,637)   $(1,816)  $(3,453)   $(11,843)  $10,138   $(1,705)














                                                       - 20 -
</TABLE>
<PAGE>
SALES

     Sales of electricity within the Company's service territory 
decreased 2% and 3% in 1995 and 1994, respectively.  The decline
in sales experienced in 1995 was primarily the result of unusual
warm winter weather experienced in the first quarter of 1995 when
compared to the same period in 1994.  This 1995 sales decrease
was also impacted by the continued declining usage by IBM.  The
decrease in 1994 sales largely occurred due to a decline in usage
by IBM, as described under the above caption entitled "Other
Developments."  
     Firm sales of natural gas decreased 5% in 1995 largely
because of a decrease in usage by residential and commercial
customers.  In 1994, firm sales of natural gas increased 4%
primarily due to an increase in the usage by residential and
commercial customers.  Changes in sales by major customer
classification are set forth below:

                                                 % Increase (Decrease)
                                                    from Prior Year  
                                                       Electric       
                                                    1995          1994  
Residential.........................                ( 2)            1
Commercial..........................                  1             3 
Industrial..........................                ( 6)          (13) 

                                                          Gas             
                                                   1995           1994  
Residential.........................               (10)             3 
Commercial..........................               ( 1)             7 
Industrial..........................                 -             (4) 

     Residential Electric Sales:  Residential electric sales are
primarily affected by the growth in the number of customers and
the change in kWh. usage per customer.  Customer usage is also
sensitive to weather.  Changes in these components are set forth
in the table below:                                
                                                 % Increase (Decrease)
                                                    from Prior Year   
                                                  1995            1994 
Growth in number of customers............            -              -
Change in average usage 
 per customer............................           (2)             1  

      The decreased customer usage in 1995 was primarily due to
the warmer winter weather experienced in the Company's service
territory in the first quarter of 1995.  Heating degree days were
22% lower in this quarter of 1995 than in the same quarter in
1994.  For the twelve months of 1995, heating degree days
decreased 12% when compared to the results for the year 1994.

                                    - 21 -
<PAGE>
      In 1994, the increased usage per customer was largely
attributable to hotter summer weather as cooling degree days
increased 10% over 1993.

      Commercial Electric Sales:   The components of the changes
in commercial electric sales are set forth in the table below:

                                                 % Increase (Decrease)
                                                   from Prior Year   
                                                     1995      1994 
Growth in number of customers..............            2          1     
Change in average usage
 per customer..............................           (1)        2      

      Industrial Electric Sales:  In 1995, as compared to 1994,
and 1994, as compared to 1993, industrial electric sales
decreased 6% and 13%, respectively, due primarily to a decline in
usage by a large industrial customer (IBM) of 18% in 1995 and 16%
in 1994.  

      Gas Sales - Firm:  The following tables set forth customer
growth, changes in customer usage and heating degree days for the
residential and commercial classifications.  Changes in
residential and commercial gas sales are affected by weather
conditions.

                                                 % Increase (Decrease)
                                                     from Prior Year  
                                                  Residential Sales
                                                      1995     1994     
Growth in number of customers...........                -        -      
Change in average usage per 
 customer...............................              (10)       3       

                                                   Commercial Sales
                                                      1995     1994           
Growth in number of customers...........                3        2      
Change in average usage per 
 customer...............................              ( 7)       5       

                                                       Degree Days 
                                                      1995     1994
Bimonthly billing cycle.................              (12)      (1)
Calendar year...........................              ( 4)      (3)

      Firm gas sales to industrial customers for 1995 remained
stable when compared to the prior year.  In 1994, firm gas sales
to industrial customers decreased 4% primarily due to the shift
of two large industrial customers from firm service to gas
transportation service.  

                                    - 22 -
<PAGE>
      Gas Sales - Interruptible:  Interruptible gas sales
increased 70% in 1995, as compared to 1994, and 33% in 1994, as
compared to 1993.  The 1995 and 1994 increases were due primarily
to the sale of natural gas to the other cotenant owners of the
Roseton Plant for use as a boiler fuel.  


NUCLEAR OPERATIONS

      The Company owns a 9% interest as one of the five tenants-
in-common of the Nine Mile 2 Plant, which is discussed in Note 2
of the Notes under the caption entitled "Nine Mile 2 Plant."  The
operations of this Plant have continued to improve.  The actual
capacity factor of 76.5% for 1995 exceeded the targeted capacity
factor of 73.2% included in the Company's electric fuel
adjustment clause.  The actual cost of operation for 1995 was
less than the amounts provided in the Company's rates.  Both of
these factors contributed to a favorable impact on earnings.  In
1994, the actual cost of operation approximated the amount
provided for in the rate-making process.  
      The Company has continued to participate actively on the
management, operations and accounting committees for the Nine
Mile 2 Plant and expects to continue to do so in the future.
      The Nine Mile 2 Plant is scheduled to commence its fifth
refueling outage in September 1996, with a targeted 37-day
duration.
      Decommissioning of nuclear plants such as the Nine Mile 2
Plant was an important part of the Energy Policy Act of 1992. 
Through this act, the Uranium Enrichment Decontamination and
Decommissioning Fund was established.  For further information on
this enactment, refer to Note 2 of the Notes.  With respect to
its interest in the Nine Mile 2 Plant, the Company based its 1995
decommissioning cost estimates on the decommissioning study
completed in 1989.  As more fully discussed in Note 2 of the
Notes, a recent decommissioning study was completed in December
1995.  The Company believes that decommissioning costs, if higher
than currently estimated, will ultimately be recovered in the
rate-making process, although no such assurance can be given.

SHARING ARRANGEMENTS

      Pursuant to certain incentive formulas approved by the PSC,
the Company shares, with its customers, certain revenues and/or
cost savings exceeding defined predetermined levels.  These
incentive formulas, in some cases, include penalty provisions for
shortfalls from the targeted levels as well.
      Incentive formulas are in place for fuel cost variations,
sales of electricity to other utilities and interruptible gas
sales.


                                    - 23 -
<PAGE>
      The net effect of these incentive formulas was to increase
pretax earnings by $4.0, $2.1 and $2.0 million during 1995, 1994
and 1993, respectively.

OPERATING EXPENSES

      As a result of the Company's continuing efforts to reduce
costs of operation, the Company experienced a significant
reduction in its operating expenses, especially in the operation
and maintenance costs of its generating and nuclear plants, when
comparing 1995 to 1994 results.  Changes from the prior year in
the components of the Company's operating expenses are listed
below:

                                           Increase or (Decrease)
                                               from Prior Year         

                                           1995                 1994   
                                      Amount      %        Amount    % 

                                           (Dollars in Thousands)     
Operating Expenses:
  Fuel and purchased
   electricity...............        $ 1,279        1      $(10,266)     (8)
Purchased natural gas......            1,751        3         6,688      12  
  Other expenses of 
   operation.................         (2,354)     ( 3)        3,436       4
  Maintenance................         (2,905)     (10)       (2,381)     (8)  
  Nine Mile 2 Plant operation
   and maintenance...........           (879)     ( 6)          773       5
  Depreciation and 
   amortization..............          1,087        3           698       2  
  Taxes, other than 
   income tax................           (190)       -         1,335       2   
  Federal income tax.........            997        4          (560)     (2)
       Total.................        $(1,214)       -      $   (277)      -  

      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 department. 
Approximately 28% in 1995 and 27% in 1994 of every revenue dollar
billed in 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 61% and 58%,
respectively.  
      In 1995, the combined cost of fuel used in electric
generation and purchased electricity increased $1.3 million (1%)
primarily due to a 1% increase in total system sales which 


                                    - 24 -
<PAGE>
included sales to other utilities.  In 1994, the combined cost of
fuel used in electric generation and purchased electricity
decreased $10.3 million (8%) resulting primarily from lower per
unit costs and decreased sales of electricity.  
      In an effort to keep the cost of electricity at the lowest
reasonable level, the Company purchases energy from other member
companies of the New York Power Pool, whenever such 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 increased $1.8 million (3%) in 1995
largely because of higher interruptible gas sales including gas
used as a boiler fuel at the Roseton Plant.  The 1994 $6.7
million (12%) increase in gas purchased was due primarily to
increased sales of natural gas to the other cotenant owners for
use as a boiler fuel at the Roseton Plant and increased sales of
natural gas to residential and commercial customers.  As
discussed in Note 8 of the Notes, competitively bid contracts
that the Company has in place for a majority of its gas supply
will expire in 1996 after the 1995-1996 winter heating season and
are expected to be replaced with competitively bid contracts with
third-party gas suppliers.
      Other expenses of operation decreased $2.4 million (3%) in
1995 primarily because of decreased costs of the Company's
electric distribution and transmission system.  The 1994 increase
of $3.4 million (4%) in other expenses of operation was primarily
due to higher employee wages and associated fringe benefits.
      Maintenance expenses decreased $2.9 million (10%) in 1995
due largely to a $3.5 million decrease in costs associated with
the Company's electric generating plants and a $1.6 million
decrease in leak repair costs on the Company's gas distribution
and transmission system.  These decreases were partially offset
by a $2.0 million increase in the Company's electric distribution
and transmission system costs largely resulting from increases to
storm costs and tree trimming expenses in 1995.  The 1994
decrease of $2.4 million (8%) in maintenance expenses was due
primarily to $4.1 million of higher costs incurred in 1993 for
the scheduled major overhauls of Units 3 and 4 at the Danskammer
Plant with no comparable overhauls in 1994.  These costs were
partially offset by a $1.9 million increase in maintenance costs
related to the Company's gas transmission and distribution system
in 1994.  
      The Company's portion of operating expenses, taxes and
depreciation pertaining to the operation of the Nine Mile 2 Plant 
are included in the Company's financial results.  In 1995, the
Company's portion of the costs of the Nine Mile 2 Plant decreased
$879,000 (6%) due primarily to a decrease in the nuclear plant's
operation and maintenance costs.  The Company's portion of the
1994 costs of the Nine Mile 2 Plant increased $773,000 (5%) due
to the inclusion of approximately $1.7 million of non-recurring 


                                    - 25 -
<PAGE>
expenses largely attributable to Niagara Mohawk's corporate
restructuring efforts at the Nine Mile 2 Plant.
      The Company's composite rate for depreciation amounted to   
3.14% in 1995, 3.15% in 1994 and 3.17% in 1993 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 35.3% in 1995, 34.5% in 1994 and 32.8% in 1993.
      Property taxes, including school taxes, increased $1.2
million and $1.5 million in 1995 and 1994, respectively. 
      State and local taxes levied on gross revenues decreased
$1.2 million and $406,000 in 1995 and 1994, respectively.  The
1995 decrease in revenue taxes was largely due to a change in New
York State tax law, reducing the surcharge tax rate for utility
service from 12.5% to 7.5% effective June 1, 1995.  In 1994, the
revenue taxes decreased due to the reduced rate of the New York
State Surcharge Tax for utility service from 15% to 12.5%
effective June 1, 1994.  
      With the enactment in August 1993 of the Omnibus Budget
Reconciliation Act of 1993 (OBRA), the corporate federal income
tax rate increased from 34% to 35%, effective January 1, 1993. 
The PSC authorized deferral of the resultant increase in the
corporate federal income tax rate in 1993 until its disposition
is determined in the next rate case.
      See Note 3 of the Notes for an additional analysis and
reconciliation of the federal income tax.

OTHER INCOME AND INTEREST CHARGES

      Other income (excluding AFDC) increased $1.7 million (23%)
in 1995 and $921,000 (14%) in 1994.  The increase was
substantially due to the gain on the sale of long-term stock
investments in June and December 1995 which is more fully
discussed in Note 10 of the Notes.  Other income increased in
1994 primarily because of an increase in the amount of Mirror
CWIP which flowed through the income statement as a rate
moderator, prescribed by the Order of the PSC issued and
effective February 11, 1994, as referred to above under the
caption entitled "Rate Proceedings - Electric."













                                    - 26 -
<PAGE>
      Total interest charges (excluding AFDC) decreased $2.2 
million (7%) in 1995 and $1.2 million (4%) in 1994.  The
following table sets forth some of the pertinent data on the
Company's outstanding debt:   


                                            1995       1994        1993
                                             (Thousands of Dollars)     
Long-term debt:
  New debt issued.............           $   -       $   -       $ 40,000   
  Debt retired................              2,562      50,000      40,000
  Outstanding at year-end*:  
    Amount (including current
    portion)..................            391,715     393,853     443,897 
    Effective rate............              7.00%       6.71%       6.75%
Short-term debt:
  Average daily amount 
   outstanding ...............           $    103    $     16    $    330
  Weighted average
    interest rate ............              6.16%       6.69%       3.94%


*Including debt of subsidiaries of $5.3 million in 1995 and $4.8
million in 1994 and 1993.

See Notes 4 and 6 of the Notes for additional information on
short-term and long-term debt of the Company.
























                                    - 27 -
<PAGE>
<TABLE>
FINANCIAL INDICES

<CAPTION<
      Selected financial indices for the last five years are set forth in the following
table:

                                                                     1995    1994    1993    1992    1991  
<S>                                                                  <C>     <C>     <C>     <C>     <C>
Pretax coverage of 
 total interest charges:
     Including AFDC.....................................             3.68x   3.38x   3.29x   3.07x   2.70x 

     Excluding AFDC.....................................             3.43x   3.15x   3.15x   2.95x   2.62x 

Pretax coverage of total interest 
 charges and preferred stock dividends..................             2.97x   2.74x   2.65x   2.49x   2.22x 

Percent of construction expenditures 
 financed from internal funds...........................              100%    100%    100%    100%     88% 

AFDC and Mirror CWIP* as a percentage 
 of income available for common stock...................               16%     16%     11%     10%      8% 

Effective tax rate......................................               35%     35%     35%     34%     33% 


* Refer to Note 1 of the Notes entitled "Summary of Significant Accounting Policies" under 
  subcaptions "Rates, Revenues and Regulatory Matters" and "Deferred Finance Charges -     
  Nine Mile 2 Plant" for a definition of Mirror CWIP.





                                                - 28 -
</TABLE>
<PAGE>
COMMON STOCK DIVIDENDS AND PRICE RANGES


      The Company and its principal predecessors have paid
dividends on its common stock in each year commencing 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:


                            1995                       1994        
                 High         Low     Dividend  High         Low    Dividend

1st Quarter       $27 5/8     $26       $.52     $30 1/8    $27 7/8     $.515
2nd Quarter        27 1/2      25 1/2     .52     29 3/4     25 3/4      .515
3rd Quarter        30 1/2      26 1/4     .525    27 5/8     23          .52 
4th Quarter        31 7/8      29 7/8     .525    26 1/2     22 7/8      .52 



     On June 25, 1993, the Company increased the quarterly
dividend rate on its common stock to $.515 per share and on
June 24, 1994 increased such quarterly dividend rate to $.52 per
share.  On June 23, 1995, the Company further increased such
quarterly dividend rate to $.525 per share.  The Company
presently intends to increase future common stock dividends by a
modest amount if and to the extent supported by sustained
earnings growth, while at the same time gradually reducing the
Company's payout ratio; however, any determination of future
dividend declarations, and the amounts and dates of such
dividends, will depend on the circumstances at the time of
consideration of such declaration.
     The number of registered holders of common stock as of
December 31, 1995 was 25,422.  Of these, 24,725 were accounts in
the names of individuals with total holdings of 6,225,354 
shares, or an average of 252 shares per account.  The 697 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.
     The Company's 4.85% Promissory Notes became due and were
retired on December 1, 1995.  Therefore, the limitations
contained in these notes, upon the right of the Company to
declare or pay any dividend or make any other distribution on or
acquire, for a consideration, any shares of its common stock, no
longer apply.  Thus, at December 31, 1995 the amount of retained
earnings available for dividends on the Company's common stock is
100% of the amount reported in the Consolidated Balance Sheet.



                              - 29 -
<PAGE>
Report of Independent Accountants

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

In our opinion, the accompanying consolidated balance sheet and
the related consolidated statements of income, of retained
earnings and of cash flows present fairly, in all material
respects, the financial position of Central Hudson Gas & Electric
Corporation and its subsidiaries at December 31, 1995 and 1994,
and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1995, 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.










PRICE WATERHOUSE LLP

New York, New York
January 26, 1996











                              - 30 -
<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 Annual 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, 1995. 

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 the Annual Report. 
















                              - 31 -
 <PAGE>
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 and                    Controller
Chief Executive Officer  




                                        January 26, 1996





















                              - 32 -
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<CAPTION>                                                                            December 31,
                         ASSETS                                                    1995             1994

<S>                                                                             <C>             <C>
Utility Plant                                                                                   
  Electric.....................................................                 $1,149,233      $1,114,574
  Gas..........................................................                    140,341         131,830
  Common.......................................................                     83,220          80,652
  Nuclear fuel.................................................                     32,541          31,525
                                                                                 1,405,335       1,358,581
  Less: Accumulated depreciation...............................                    490,576         462,105
        Nuclear fuel amortization..............................                     26,435          23,655
                                                                                   888,324         872,821
  Construction work in progress................................                     48,770          58,252

    Net Utility Plant..........................................                    937,094         931,073

Other Property and Investments.................................                     11,332          10,948










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


                                                   - 33 -                       
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEET  (CON'T)
(Thousands of Dollars)
<CAPTION>                                                                             December 31,    
                         ASSETS                                                     1995            1994

<S>                                                                             <C>             <C>
Current Assets
  Cash and cash equivalents......................................                   15,478           5,792
  Accounts receivable from customers - net of allowance for
    doubtful accounts; $2.5 million in 1995 and $2.0 million
    in 1994......................................................                   44,536          43,908
  Accrued unbilled utility revenues..............................                   15,806          15,076
  Other receivables..............................................                    4,674           5,953
  Materials and supplies, at average cost:
    Fuel.........................................................                   13,319          19,293
    Construction and operating...................................                   14,271          14,096
  Special deposits and prepayments...............................                   12,659          12,092
    Total Current Assets.........................................                  120,743         116,210

Deferred Charges                                                                 
  Regulatory assets (Note 1)....................................                   159,907         169,808
  Unamortized debt expense......................................                     6,080           6,527
  Other.........................................................                    14,936          16,215
    Total Deferred Charges......................................                   180,923         192,550

                         Total Assets                                           $1,250,092      $1,250,781


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





                                                   - 34 -
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEET  (CON'T)                                                  
(Thousands of Dollars)                                                              December 31,
              CAPITALIZATION AND LIABILITIES                                      1995          1994
<CAPTION>
Capitalization
<S>                                                                             <C>           <C>
  Common Stock Equity
    Common stock, $5 par value (Note 5).........................                $  87,480     $  86,192
    Paid-in capital (Note 5)....................................                  282,942       277,205
    Retained earnings...........................................                   90,475        79,284
    Capital stock expense.......................................                   (6,658)       (6,773)
    Unrealized gain on investment (Note 10).....................                     -              823
      Total Common Stock Equity.................................                  454,239       436,731

  Cumulative Preferred Stock (Note 5)
    Not subject to mandatory redemption.........................                   21,030        46,030
    Subject to mandatory redemption.............................                   35,000        35,000
      Total Cumulative Preferred Stock..........................                   56,030        81,030
  Long-term Debt (Note 6).......................................                  389,245       389,364
      Total Capitalization......................................                  899,514       907,125

Current Liabilities
  Current redemption of preferred stock.........................                   13,000          -   
  Current maturities of long-term debt..........................                    1,577         3,525
  Notes payable.................................................                     -            3,000
  Accounts payable..............................................                   24,433        29,441
  Dividends payable.............................................                   10,244        10,246
  Accrued taxes and interest....................................                    7,824         6,829
  Accrued vacation (Note 1).....................................                    4,157         4,081
  Customer deposits.............................................                    4,021         3,763
  Other.........................................................                    6,166         5,556
      Total Current Liabilities.................................                   71,422        66,441

                 The Notes to Consolidated Financial Statements are an integral part hereof.
                                                   - 35 -
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEET  (CON'T)                                                    
(Thousands of Dollars)                                                                 December 31,
<CAPTION>     CAPITALIZATION AND LIABILITIES                                         1995          1994
<S>                                                                             <C>           <C>
Deferred Credits and Other Liabilities
  Regulatory liabilities (Note 1)...............................                    74,132        72,134
  Operating reserves............................................                     6,024         5,663
  Other.........................................................                     9,659        19,463
      Total Deferred Credits and Other Liabilities..............                    89,815        97,260

Accumulated Deferred Income Tax (Note 3)........................                   189,341       179,955

Commitments and Contingencies (Notes 2 and 8)...................                                        

              Total Capitalization and Liabilities                              $1,250,092    $1,250,781












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






                                                   - 36 -
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
<CAPTION>
                                                                   Year ended December 31,
<S>                                                            1995              1994             1993
Operating Revenues                                          <C>               <C>               <C>
  Electric...................................               $396,673           $400,327         $411,339
  Gas........................................                102,770            104,586           94,448
    Total - own territory....................                499,443            504,913          505,787
  Electric sales to other utilities..........                 12,772             10,755           11,586
    Total Operating Revenues.................                512,215            515,668          517,373

Operating Expenses                                                         
  Operation:                                                               
    Fuel used in electric generation.........                 60,940             67,899           72,291
    Purchased electricity....................                 52,323             44,085           49,959
    Purchased natural gas....................                 62,339             60,588           53,900
    Other expenses of operation..............                 99,063            101,925           98,327
  Maintenance................................                 29,440             32,716           34,486
  Depreciation and amortization (Note 1).....                 41,467             40,380           39,682
  Taxes, other than income tax...............                 66,709             66,899           65,564
  Federal income tax (Note 3)................                 29,040             28,043           28,603
    Total Operating Expenses.................                441,321            442,535          442,812
                                                                           
Operating Income.............................                 70,894             73,133           74,561
Other Income and Deductions 
  Allowance for equity funds used during 
   construction (Note 1).....................                    986                866              934
  Federal income tax (Note 3)................                    353              1,237            1,445
  Other - net................................                  8,886              6,296            5,167
    Total Other Income and Deduction.........                 10,225              8,399            7,546
Income before Interest Charges...............                 81,119             81,532           82,107
       
        The Notes to Consolidated Financial Statements are an integral part hereof.
                                                   - 37 -
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENT OF INCOME (CON'T)                       
(Thousands of Dollars)
<CAPTION>                                                           Year ended December 31,
                                                              1995               1994             1993
<S>                                                         <C>               <C>               <C>
Interest Charges
  Interest on long-term debt.................                 25,925            27,541            28,877
  Other interest.............................                  1,917             1,784             1,204
  Allowance for borrowed funds used
   during construction (Note 1)..............                   (514)             (515)             (611)
  Amortization of expense on debt............                  1,069             1,793             2,247
    Total Interest Charges...................                 28,397            30,603            31,717

Net Income...................................                 52,722            50,929            50,390

Premium on Preferred Stock Redemption-Net....                    169              -                 -
Dividends Declared on Cumulative
 Preferred Stock.............................                  4,903             5,127             5,562

Income Available for Common Stock............               $ 47,650          $ 45,802          $ 44,828

Common Stock:
  Average shares outstanding (000s)..........                 17,380            17,102            16,725
  Earnings per share on
   average shares outstanding................                  $2.74             $2.68             $2.68




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




                                                   - 38 -
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENT OF RETAINED EARNINGS                    
(Thousands of Dollars)
<CAPTION>                                                           Year ended December 31,
                                                              1995               1994             1993


<S>                                                         <C>               <C>               <C>

Balance at beginning of year.................               $ 79,284           $ 69,023         $ 58,692 
Net Income...................................                 52,722             50,929           50,390
                                                             132,006            119,952          109,082

Premium on Preferred Stock Redemption-Net....                    169               _                _
Dividends declared:
  On cumulative preferred stock..............                  4,903              5,127            5,562
  On common stock ($2.095 per share 1995; 
   $2.075 per share 1994; $2.045 per share
   1993).....................................                 36,459             35,541           34,497
                                                              41,362             40,668           40,059
Balance at end of year.......................               $ 90,475           $ 79,284         $ 69,023









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




                                                   - 39 -
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
<CAPTION>
                                                                         Year ended December 31,
<S>                                                                  1995           1994          1993
Operating Activities                                              <C>           <C>           <C>
  Net Income..........................................            $  52,722      $ 50,929    $ 50,390
  Adjustments to reconcile net income to net cash 
   provided by operating activities:  
     Depreciation and amortization including nuclear  
      fuel amortization...............................               45,388        44,616        43,887
     Deferred income taxes, net.......................               14,146        12,970        15,593
     Allowance for equity funds used during
      construction....................................                 (986)         (866)         (934)
     Nine Mile 2 Plant deferred finance charges, net..               (4,855)       (4,855)       (7,987)
     Provisions for uncollectibles....................                3,220         3,306         3,431
     Accrued pension costs............................              (10,627)       (2,028)       (2,562)
     Gain on sale of long-term investment.............               (2,104)         -             (670)
     Deferred gas costs...............................                5,302         3,256        (2,974)
     Deferred gas refunds.............................               (1,784)        2,616           416
     Other - net......................................               11,466         4,376         3,807
     Changes in current assets and
      liabilities, net:
        Accounts receivable and unbilled utility
         revenues.....................................               (3,300)       (2,604)       (3,701)
        Materials and supplies........................                5,799         2,028         2,623
        Special deposits and prepayments..............                 (567)         (724)          444
        Accounts payable..............................               (5,008)          887           668
        Accrued taxes and interest....................                  995           219        (4,561)
        Other current liabilities.....................                  944         1,396             7
  Net cash provided by operating activities...........              110,751       115,522        97,877

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

                                                   - 40 -
</TABLE>
<PAGE>
<TABLE> <CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS (CON'T)
(Thousands of Dollars)                                                 1995          1994        1993
Investing Activities <S>                                          <C>           <C>           <C>
  Additions to plant..................................               (50,269)      (58,045)     (54,037)
  Allowance for equity funds used during construction.                   986           866          934
  Net additions to plant..............................               (49,283)      (57,179)     (53,103)
  Roseton Plant restoration costs related to fire.....
   damage                                                               -             (853)      (9,454)
  Insurance recoveries related to 
   Roseton Plant restoration..........................                  -            4,371         5,936
  Nine Mile 2 Plant decommissioning trust fund........                (1,895)         (895)      (942)
  Proceeds from sale of long-term investments.........                 2,879          -            2,212
  Other - net.........................................                (1,161)       (2,648)         (215)
  Net cash used in investing activities...............               (49,460)      (57,204)      (55,566)
Financing Activities
  Proceeds from issuance of:
    Long-term debt....................................                 1,000           230        41,722
    Common stock......................................                 7,064         7,783        30,122
    Cumulative preferred stock........................                  -             -           35,000
  Net borrowings (repayments) of short-term debt......                (3,000)        3,000       (15,000)
  Retirement and redemption of long-term debt.........                (3,139)      (50,273)      (41,443)
  Retirement and redemption of cumulative preferred
   stock..............................................               (12,000)         -          (35,000)
  Premium on preferred stock redemption...............                  (146)         -             -
  Dividends paid on cumulative preferred and common 
   stock..............................................               (41,364)      (40,328)      (39,527)
  Issuance and redemption costs.......................                   (20)         (110)       (2,271)
  Net cash used in financing activities...............               (51,605)      (79,698)      (26,397)
Net Change in Cash and Cash Equivalents...............                 9,686       (21,380)       15,914
Cash and Cash Equivalents at Beginning of Year........                 5,792        27,172        11,258
Cash and Cash Equivalents at End of Year..............             $  15,478     $   5,792     $  27,172
Supplemental Disclosure of Cash Flow Information
    Interest paid (net of amounts capitalized)........             $  26,738     $  28,681     $  30,287
    Federal income taxes paid.........................                14,100        12,100        13,000
The Notes to Consolidated Financial Statements are an integral part hereof.
                                                   - 41 -
/TABLE
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:

      The Company is subject to regulation by the Public Service
Commission of the State of New York (PSC) and the Federal Energy
Regulatory Commission (FERC) with respect to its rates for
service and the maintenance of its accounting records.  The
Company's accounting policies conform to generally accepted
accounting principles as applied to regulated public utilities
and are in accordance with the accounting requirements and rate-
making practices of the regulatory authorities having
jurisdiction.
      Certain amounts from prior years have been reclassified on
the consolidated financial statements to conform with the 1995
presentation.  Preparation of the financial statements includes
the use of estimates.


Principles of Consolidation:

      The consolidated financial statements include the accounts
of the Company and its subsidiaries.  All intercompany balances
and transactions have been eliminated.
      The Company's subsidiaries are each wholly owned, and
consist of landholding, cogeneration 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.


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 $169.3 million which was
recorded in 1987.  Costs include labor, materials and supplies,
indirect charges for such items as transportation, certain taxes,
pension and other employee benefits and an allowance for the cost
of funds used during construction (AFDC).  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.



                                    - 42 -
<PAGE>
Jointly Owned Facilities:

      The Company has a 9%, or 102.9 MW, undivided interest in the
1,143 MW Nine Mile 2 Plant (see Note 2) and a 35%, or 420 MW,
undivided interest in the 1,200 MW Roseton Steam Electric
Generating Plant (Roseton Plant) (see Note 8 caption "Roseton
Plant").
      The Company's pro rata shares of the investments in the Nine
Mile 2 Plant and the Roseton Plant, as included in its
Consolidated Balance Sheet at December 31, 1995 and 1994, were:

                                                 1995            1994
                                              (Thousands of Dollars)
      Nine Mile 2 Plant
       Plant in service                       $ 315,423        $309,893
       Construction work in progress                594           3,941
       Accumulated depreciation                 (55,319)        (48,248)
     Roseton Plant
       Plant in service                       $ 133,741        $130,310
       Construction work in progress              1,872           3,740
       Accumulated depreciation                 (71,880)        (70,525)


Allowance For Funds Used During Construction:

      The Company includes in plant costs AFDC approximately
equivalent to the cost of funds used to finance construction
expenditures.  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 8.50% in 1995, 8.50% in 1994
and 8.75% in 1993.

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 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.  Reference is
made to the caption "Operating Expenses" in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" for the ratio of the total provision for depreciation
to the original cost of average depreciable property.  The 


                                    - 43 -
<PAGE>
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 most recent study
was performed in 1993.  The provision for depreciation of
transportation equipment is charged indirectly to various asset
and expense accounts.
      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.

Amortization of Nuclear Fuel:

      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. 
Niagara Mohawk Power Corporation (Niagara Mohawk), on behalf of
the Nine Mile 2 Plant cotenants, has entered into an agreement
with the U.S. Department of Energy (DOE) for the ultimate
disposal and storage of spent nuclear fuel.  The cotenants are
assessed a fee for such disposal based upon the kilowatt-hours
generated by the Nine Mile 2 Plant.  These costs are charged to
operating expense and recovered from customers through base rates
or through the electric fuel cost adjustment clause described
below.  The Company cannot now determine whether such
arrangements with the DOE will ultimately provide for the
satisfactory permanent disposal of such waste products. 

Cash and Cash Equivalents:

      For purposes of the Consolidated Statement of Cash Flows,
the Company considers temporary cash investments with an original
maturity 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."  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.




                                    - 44 -
<PAGE>
Rates, Revenues and Regulatory Matters:

      Electric and gas retail rates, including fuel and gas cost
adjustment clauses, applicable to intrastate service (other than
contractually established rates for service to municipalities and
governmental bodies) are regulated by the PSC.  Transmission
rates, facilities charges and rates for electricity sold for
resale in interstate commerce are regulated by the 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 and
certain costs of manufactured gas.

      Regulatory Assets and Liabilities:  Certain utility expenses
and credits normally reflected currently in income are deferred
on the balance sheet as regulatory assets and liabilities and are
recognized in income as the related amounts are included in
service rates and recovered from or refunded to customers in
utility revenues.

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

At December 31,                              1995        1994 

Regulatory Assets (Debits):                 (In thousands)
Deferred finance charges - 
  Nine Mile 2 Plant.....................            $ 70,760      $ 71,904
Income taxes recoverable
  through future rates..................              65,723        69,331
Deferred energy efficiency cost.........              11,046         9,583
Other...................................              12,378        18,990
  Total Regulatory Assets...............            $159,907      $169,808

Regulatory Liabilities (Credits):                       
Deferred finance charges - 
  Nine Mile 2 Plant.....................            $ 28,431      $ 34,431
Income taxes refundable.................              29,093        28,383
Deferred unbilled gas revenues..........               4,030         3,754
Deferred OPEB costs over collection.....               3,600           -  
Other...................................               8,978         5,566
  Total Regulatory Liabilities..........            $ 74,132      $ 72,134

                                    - 45 -
<PAGE>
      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 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 the PSC's Opinion and Order Determining Revenue
Requirement and Rate Design, issued and effective February 11,
1994 (1993 Rate Order) the Company was authorized to offset $5.5
million of the deferred credit against other deferred balances
and to amortize $6.0 million annually beginning in December 1993. 
In 1995, 1994 and 1993, the Company amortized $6.0 million, $6.0
million and $3.3 million, respectively, of this deferred credit. 
      The $6.0 million amortization of the deferred credit will be
continued until changed in a future PSC rate order.  The level of
the deferred debit amortization is based on the level of deferred
credits that have been utilized in setting revenue requirements
for a rate year.  Any amounts of deferred credits that are
utilized in the period between the end of the rate year and the
setting of new rates are included in the amortization level for
the deferred debit over the then remaining life of the Nine Mile
2 Plant.  The deferred debit amortization level is currently set
at $1.145 million per year.




                                    - 46 -
<PAGE>
      Deferred Energy Efficiency Costs:  The PSC has required
utilities to adopt comprehensive long-range planning which
includes demand side management and energy conservation (Energy
Efficiency Program).  The Company's 1995 Energy Efficiency
Program was approved by the PSC.  The Energy Efficiency Program
costs are deferred and amortized over either five or ten years,
as directed by the PSC.
      In addition to the deferral of Energy Efficiency Program
costs, the Company recovers lost net revenues that result from
the Program.  Incentive earnings related to the achievement of
energy efficiency goals are recovered through the electric fuel
cost adjustment clause as discussed below.

      Deferred and Accrued Vacation:  The Company's employees
begin accruing vacation in July of each year for use in the
following year; the monthly accrual of days is based on the
number of years of service for each employee.  However, for rate-
making purposes, vacation pay is recognized as an allowable
expense only when paid.  Accordingly, the Company records a
current liability for earned vacation pay and an equivalent
regulatory asset representing the future recoverability of the
difference between costs incurred and costs recovered in the
rate-making process.

      Deferred Electric Fuel Costs:  The provisions of the
electric fuel cost adjustment clause are such that changes in
fuel costs incurred in the current month are not billed or
credited to customers until subsequent months.  Therefore, in
order to match costs and revenues, the Company defers that
portion of such costs incurred in the current month which will
result in a cost adjustment in subsequent months.
      Pursuant to a 1985 Order of the PSC, the Company's electric
fuel cost adjustment clause provides for a partial sharing of
variations in fuel costs from the levels of fuel costs projected
in rate proceedings.  The Company bears 20% of the first $10
million of variation and 10% of the second $10 million of
variation.  The partial sharing applies to variations in actual
fuel costs either above or below the projected levels;
accordingly, the Company's maximum annual exposure, or benefit,
is $3 million, before taxes.
      As a result of the adoption of the partial sharing electric
fuel adjustment clause, the PSC adopted a symmetrical sharing
arrangement for net revenues from sales to other utilities. 
Shortfalls below the targeted amount, as well as amounts above
the targeted amount, will be shared 80% by the customers and 20%
by the Company.  
      Reference is made to the caption "Sharing Arrangements" in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" for results of both sharing arrangements
mentioned above.

                                    - 47 -
<PAGE>
      Deferred Gas Costs:  In accordance with requirements of the
PSC applicable to all New York State regulated gas utilities, the
Company defers each month any difference between the amount of
gas costs incurred which is recoverable through the gas cost
adjustment clause (GAC) and GAC revenues.  The net deferral
remaining at August 31 of each year is amortized over a
subsequent twelve-month period for both billing and accounting
purposes.  See Note 8 captions "Natural Gas Supply" and "Take-or-
Pay Gas Costs" as to deferral of certain contract take-or-pay
costs charged by pipeline suppliers.


New Accounting Standards:

      Impairment:  In March 1995, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121). 
SFAS 121 requires companies, including utilities, to assess the
need to recognize a loss whenever events or circumstances occur
which indicate that the carrying amount of an asset may not be
fully recoverable.  SFAS 121 also amends SFAS 71, "Accounting for
the Effects of Certain Types of Regulation," to require the
write-off of a regulatory asset if it is no longer probable that
future revenues will recover the cost of the asset.  SFAS 121,
which is applicable to the Company starting in 1996, may have
consequences for a number of utilities, especially those which
have relatively high-cost nuclear generating assets, including
the Company, which are facing growing competitive pressures that
may erode prices for future utility services.  The Company does
not expect that the adoption of SFAS 121 will have a material
impact on the financial position or results of operations of the
Company in 1996 based on the current regulatory treatment of its
long-lived and regulatory assets.  However, future developments
in the utility industry including the effects of deregulation and
increasing competition could change this conclusion.

      Plant Decommissioning:  Because diverse accounting practices
have developed for recognizing the cost of closure and removal of
long-lived assets in the financial statements, including the cost
of decommissioning utility generating plants, the FASB has agreed
to review the accounting for this topic.  The FASB is considering
when a liability for plant decommissioning or other asset
retirement should be recognized, how any such liability should be
measured, and whether a corresponding asset is created.  In a
preballot draft SFAS, issued December 1995, FASB has tentatively
concluded that a liability should be recognized for legal or
unavoidable constructive obligations for closure and removal of
facilities such as the Nine Mile 2 Plant as the obligation is 


                                    - 48 -
<PAGE>
incurred.  The liability recognized for those closure and removal
obligations shall reflect the present value of estimated future
cash outflows currently expected to be required to satisfy those
obligations.  Initial recognition of a liability for closure and
removal obligations increases the cost of the related asset
because incurrence of the obligation is integral to or a
prerequisite for operating the asset.  Further, if securities or
other assets have been dedicated for future settlement of closure
and removal obligations, the liability for those obligations
shall, generally, not be offset by those dedicated assets.  The
proposed statement, when issued, may be effective as early as the
1997 financial statements of the Company.  The Company does not
believe that such changes, if required, would have an adverse
effect on results of operations due to its current belief that
decommissioning costs will continue to be recovered in rates.


NOTE 2 - NINE MILE 2 PLANT

General:

     The Nine Mile 2 Plant is located in Oswego County, New York,
and is operated by 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
(18% interest), Long Island Lighting Company (18% interest) and
Rochester Gas and Electric Corporation (14% interest).  The
output of the Nine Mile 2 Plant, which has a rated net capability
of 1,143 MW, (as reported by Niagara Mohawk) 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:

      An agreement for interim storage of the Nine Mile 2 Plant
low-level radioactive waste has been agreed to between Niagara
Mohawk and the cotenants that will provide for the storage of the
Nine Mile 2 Plant low-level radioactive waste at Unit No. 1 of
the Nine Mile Point Nuclear Station (Nine Mile 1 Plant) until 


                                    - 49 -
<PAGE>
June 30, 2010.  It is expected that all low-level radioactive
waste stored at Nine Mile 1 Plant (owned 100% by Niagara Mohawk)
will have been transferred to a low-level radioactive waste
repository operating within New York State by this date.  Niagara
Mohawk has contracted with the DOE for disposal of high-level
radioactive waste (spent fuel) from the Nine Mile 2 Plant (see
Note 1 - Summary of Significant Accounting Policies -
"Amortization of Nuclear Fuel").  The DOE has forecasted the
start of operations of its high-level radioactive waste
repository to be no sooner 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
2014.  If DOE schedule slippage should occur, facilities that
extend the on-site storage capability for spent fuel at the Nine
Mile 2 Plant beyond 2014 would need to be acquired.


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
($72.6 million in 1995 dollars) and assumes that decommissioning
will begin in the year 2028.  This estimate is based upon a site
specific study completed in December 1995.
      The annual decommissioning allowance reflected in ratemaking
is based upon a 1989 study as filed with the Nuclear Regulatory
Commission (NRC).  The 1989 study included amounts for
radioactive and non-radioactive dismantlement costs and is
charged to operations through depreciation recovery.  The 1989
study estimated the Company's 9% share of costs of
decommissioning to be $118.5 million ($26.4 million in 1995
dollars).  The PSC authorized recovery, on an annual basis, of
$212,000 for internal decommissioning funding (i.e., funds held
by the Company) and $787,000 for external decommissioning funding
(i.e., funds held in trust).  Total recoveries authorized by the
PSC for the internal decommissioning fund from August 1988
through December 31, 1995 amounted to $1.4 million.  The external
decommissioning trust fund at December 31, 1995 and 1994 amounted
to $6.4 million and $4.5 million, respectively. The net earnings
from inception through December 31, 1995 amounted to $1.6
million.  The external decommissioning trust fund is reflected in
the Company's Consolidated Balance Sheet in "Other Property and
Investments."  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 Consolidated Balance Sheet and amount to $7.9
million and $5.7 million at December 31, 1995 and 1994,
respectively.  NRC regulations require the direct funding of
eventual decommissioning costs of nuclear facilities.  The 


                                    - 50 -
<PAGE>
Company, in 1990, established a master trust in order to comply
with these NRC requirements.  The Company has estimated that its
share of the minimum funding requirements will be approximately
$38.8 million in 1995 dollars.
      There is no assurance that the decommissioning allowance
recovered in rates will ultimately aggregate a sufficient amount
to decommission the unit.
      Reference is made to the caption "New Accounting Standards -
Plant Decommissioning" in Note 1 above for details of the
proposed changes in accounting for nuclear decommissioning costs.
      The Company believes that if decommissioning costs are
higher than currently estimated, such higher costs would be
recovered in rates.

Decontamination and Decommissioning Fund:

      The Energy Policy Act of 1992, signed into law in October
1992, established a Uranium Enrichment Decontamination and
Decommissioning Fund (Fund) for the decommissioning of the DOE's
enrichment facilities.  Special annual assessments to utilities
with nuclear power plants, which began in 1993 and continue until
2006, and government appropriations for such purpose will be
deposited into the Fund.  The Energy Policy Act of 1992 also
provides that such assessments shall be considered a cost of fuel
and shall be recoverable in rates.  
      The unamortized portion of the Company's share of this
assessment at December 31, 1995 and 1994 of approximately
$630,000 and $664,000, respectively and a corresponding
regulatory asset are reflected in the Consolidated Balance Sheet. 
Payments to the Fund are made to Niagara Mohawk by the cotenants
of the Nine Mile 2 Plant.




















                                    - 51 -
<PAGE>
NOTE 3 - 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:

                                         1995       1994        1993 
                                          (Thousands of Dollars)
Charged to operating expense:                                 
  Federal income tax..........         $19,245    $18,190     $14,502
  Deferred income tax.........           9,795      9,853      14,101
    Income tax charged to
      operating expense.......          29,040     28,043      28,603

Charged (credited) to other 
 income and deductions:
  Federal income tax..........          (4,704)    (4,354)     (2,937)
  Deferred income tax.........           4,351      3,117       1,492 
    Income tax charged
      (credited) to other
      income and deductions...            (353)    (1,237)     (1,445)
    Total federal income tax..         $28,687    $26,806     $27,158




























                                      - 52 -
<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:


                                        1995        1994        1993 
                                         (Thousands of Dollars)

Net income....................         $52,722     $50,929    $50,390
Federal income tax............          14,541      13,836     11,565
Deferred income tax...........          14,146      12,970     15,593
  Income before taxes.........         $81,409     $77,735    $77,548

Computed tax @ 35%
 statutory rate...............         $28,493     $27,207    $27,142
Increase (decrease) to computed 
 tax due to:
  Tax depreciation............         (10,096)     (9,597)   (10,796)
  Deferred finance charges -
   Nine Mile 2 Plant..........          (1,701)     (1,700)      (862)
  Deferred gas costs..........           2,286       1,149       (844)
  Deferred OPEB expense.......            (223)        713     (1,617)
  Pension expense.............          (1,738)     (1,471)      (893)
  Alternative minimum tax.....          (2,958)     (1,544)       (59)
  Other.......................             478        (921)      (506)
Federal income tax............          14,541      13,836     11,565
Deferred income tax...........          14,146      12,970     15,593
  Total federal income tax....         $28,687     $26,806    $27,158

 Effective tax rate...........           35.2%       34.5%      35.0%



















                                      - 53 -
<PAGE>
      The following is a summary of the components of accumulated
deferred income taxes at December 31, 1995 and 1994, as reported
in the Consolidated Balance Sheet:

                                                   1995          1994 
                                               (Thousands of Dollars)
Accumulated Deferred Income
  Tax Assets:
 Future tax benefits on
   investment tax credit basis
   difference.....................                $ 16,073    $ 16,829
 Alternative minimum tax..........                  10,530      12,989
 Tax depreciation - Nine Mile 2
   Plant disallowed investment....                   3,077       6,155
 Unbilled revenues................                   5,434       5,045
 Other............................                  22,444      17,611 
Accumulated Deferred Income Tax
 Assets...........................                $ 57,558    $ 58,629

Accumulated Deferred Income 
  Tax Liabilities:
 Tax depreciation.................                $172,033    $162,734
 Accumulated deferred investment
   tax credit.....................                  29,850      31,254 
 Future revenues - recovery of
   plant basis differences........                  22,971      24,269 
 Other............................                  22,045      20,327
Accumulated Deferred Income Tax
 Liabilities......................                $246,899    $238,584

Net Accumulated Deferred Income 
 Tax Liability....................                $189,341    $179,955


NOTE 4 - SHORT-TERM BORROWING ARRANGEMENTS

      The Company has in effect a revolving credit agreement with
four commercial banks which allows it to borrow up to $50.0
million through December 14, 1997 (Agreement).  The Agreement
gives the Company the option of borrowing at either the
prime/federal funds rate, or three other money market rates if
such rates are lower.  The Agreement also provides for the
payment of an annual commitment fee of 1/16 of 1% per annum on
the unborrowed amount and a facility fee of 1/8 of 1% per annum
on the total amount of the facility.  Compensating balances are
not required under the Agreement.  In addition, the Company
continues to maintain confirmed lines of credit totaling $1.5
million with two regional banks.  There were no outstanding loans
under these Agreements at December 31, 1995 or 1994.  In order to


                                    - 54 -
<PAGE>
diversify its sources of short-term financing, during 1994 the
Company entered into short-term credit facilities agreements with
four commercial banks totaling $130.0 million in the aggregate.
There was no outstanding short-term debt at December 31, 1995. 
There was $3.0 million outstanding at December 31, 1994 related
to these credit facilities with a weighted average interest rate
of 6.69%.
      Authorization from the PSC limits the amount the Company may
have outstanding, at any time, under all of its short-term
borrowing arrangements to $52.0 million in the aggregate.

NOTE 5 - CAPITALIZATION - CAPITAL STOCK

Common Stock, $5 par value; 30,000,000 shares authorized:
Paid-In Capital:
                                        Common Stock              Paid-In
                                     Shares         Amount        Capital
                                   Outstanding      ($000)         ($000)
January 1, 1993                     16,028,569     $80,143       $245,349
 Issued through public
  offering..................           700,000       3,500         19,299
 Issued under dividend 
  reinvestment plan.........           185,101         926          5,124
 Issued under customer stock
  purchase plan.............            39,477         197          1,076
December 31, 1993                   16,953,147      84,766        270,848
 Issued under dividend
  reinvestment plan.........           227,772       1,139          5,104
 Issued under customer stock
  purchase plan.............            57,545         287          1,253
December 31, 1994                   17,238,464      86,192        277,205 
 Issued under dividend
  reinvestment plan.........           218,610       1,093          4,897
 Issued under customer stock
  purchase plan.............            38,977         195            879
 Redemption of preferred
  stock.....................             -            -               (39)
December 31, 1995                   17,496,051    $ 87,480       $282,942 













                                    - 55 -
<PAGE>
Cumulative Preferred Stock, $100 par value; 1,200,000 shares
authorized:
                       Final       Redemption        Shares Outstanding  
                     Redemption      Price               December 31,
            Series      Date        12/31/95          1995         1994
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
            7.72%         (a)           101.00      130,000       130,000
            7.44%                                      -          120,000
                                                    340,300       460,300
Subject to
 Mandatory
 Redemption:
            6.20%     10/1/08 (b)                   200,000       200,000
            6.80%     10/1/27 (b)                   150,000       150,000
                                                    350,000       350,000
                     Total                          690,300       810,300


(a) Redeemed January 1, 1996 at a redemption price of $101.00 per 
      share.
(b) Cannot be redeemed prior to October 1, 2003.  

      Reference is made to the caption "Financing Program" in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" for details on issuances and redemptions
of capital stock.
      The Cumulative Preferred Stock not subject to mandatory
redemption is redeemable only at the option of the Company. Upon
redemption, the sum payable per share is the then current
redemption price plus accrued dividends thereon.  In the event of
an involuntary liquidation of the Company, the redemption price
is $100 per share plus accrued dividends.
      The Company optionally redeemed all of its outstanding 7.44%
Cumulative Preferred Stock, at the $101.22 redemption price on
October 1, 1995.  Costs associated with this redemption were
charged directly to retained earnings.
      The Company optionally redeemed all of its outstanding 7.72%
Cumulative Preferred Stock at the $101.00 redemption price on
January 1, 1996.  Costs associated with this redemption will be
charged directly to retained earnings in 1996.
      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 


                                    - 56 -
<PAGE>
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.  
      The PSC has authorized the issuance and sale of certain debt
and equity securities of the Company.  Accordingly, a
registration statement became effective in April, 1995 under
which the Company registered with the Securities and Exchange
Commission (SEC) the following securities:  (i) Debt Securities
and Common Stock, $5.00 par value, but not in excess of $80.0
million in aggregate, and not in excess of $40.0 million initial
public offering price of such Common Stock and (ii) Cumulative
Preferred Stock, not in excess of $25.0 million, par value $100
per share, which may be issued as Depositary Preferred Shares,
each representing 1/4 of a share of such Cumulative Preferred
Stock, each evidenced by Depositary Receipts.  



































                                    - 57 -
<PAGE>
NOTE 6 - CAPITALIZATION - LONG-TERM DEBT

  Details of long-term debt are shown below:

                                                        December 31, 
                                                       1995       1994
                                                (Thousands of Dollars)
      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
 8 3/4%              May 1, 2001                       30,000    30,000
 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                       4,500     4,500
 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)           December 1, 2028                  16,700    16,700
                                                      202,200   202,200

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
 5.38% (a)                   Jan. 15, 1999             20,000    20,000
 7.85% (a)                   July 2, 2004              15,000    15,000
                                                      184,250   184,250

Secured Notes Payable of Subsidiary                     3,688     3,878
Unamortized Discount on Debt                             (893)    (964)
               Total long-term debt                  $389,245  $389,364  

(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.

     Medium Term Notes:  Authorization by the PSC to issue Medium
Term Notes under the Company's Medium Term Note Program expired
on December 31, 1994.  Of the $125.0 million of Medium Term Notes
authorized under such program, $116.0 million were issued.  By
Order effective October 17, 1994, the PSC authorized the Company 

                                    - 58 -
<PAGE>
to issue and sell not later than December 31, 1996, new debt
securities and common stock totaling not more than $80.0 million
in the aggregate.  Such Order also authorized the issuance of up
to $115.0 million of tax exempt NYSERDA Pollution Control Revenue
Bonds for the purpose of refinancing, if economical, a like
amount of such bonds presently outstanding.

      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 the Bonds of each
such series to a fixed rate for the remainder of their term.  In
its rate orders, the PSC has provided for full recovery of 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.  Deferred accounting has been
granted by the PSC for any variation between actual interest
rates and those interest rates allowed for rate-making purposes. 
The deferred balance under such accounting at December 31, 1995
was a regulatory asset of $1.3 million and the deferred balance
under such accounting at December 31, 1994 was a regulatory
liability of $488,000.  Such deferred balances are to be disposed
of in future rate cases.

      Interest Rate Cap:  In 1995, the Company entered into a
three-year interest rate cap agreement with a bank to manage
exposure to upward changes in interest rates on the 1985 and 1987
NYSERDA Bonds.  Under this agreement, in the event a nationally
recognized tax-exempt bond interest rate index exceeds 8%, the
Company will receive a payment from such bank equal to the amount
by which the actual interest costs on such bonds exceeds 8% per
annum.  This agreement has the effect of limiting the interest
rate the Company must pay on such bonds (on a $115.9 million
notional amount) to the lesser of their actual rate or 8% per
annum.  In the event such bank failed to make any required
payment under such interest rate cap agreement, the Company's
exposure would be limited to a maximum interest rate of 15% per
annum under the terms of such bonds.

      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
expire on various dates.  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 series of such bonds, that series would 


                                    - 59 -
<PAGE>
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 the letter of
credit by the expiration date of the letter of credit.  The
letter of credit expiration date for the letters of credit
supporting the 1985 NYSERDA Bonds is November 16, 1998, and the
letter of credit expiration date for the letters of credit
supporting the 1987 NYSERDA Bonds is September 16, 1998.  The
cost of these letters of credit is $584,400 for 1995.  

     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.

      Subsidiary Debt:  Secured notes payable of a subsidiary of
the Company consist of term loans to finance the installation of
energy conservation equipment at various host facilities, located
primarily in the Northeastern United States.  The majority of
such loans accrue interest at the prime lending rate.  Interest
and principal are amortized over the term of each respective
contract.  Such loans are secured principally by certain power
purchase agreements and project assets.


NOTE 7 - POSTEMPLOYMENT BENEFITS

Retirement Income Plan:

      The Company has a noncontributory 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.
                                    - 60 -
<PAGE>
      Net periodic pension costs were allocated 73%, 73% and 71%
to expense for the years 1995, 1994 and 1993, respectively, with
remaining costs allocated to capital projects.  The allocation of
net periodic pension costs between capital and expense follows
the payroll distribution.
      Net periodic pension (income) costs for 1995, 1994 and 1993
include the following components: 
                                      1995         1994         1993
                                        (Thousands of Dollars)
Service cost - benefits earned
 during the period...........       $  3,877     $  5,876     $  4,518
Interest cost on projected
 benefit obligation..........         14,449       13,256       13,148
Actual return on Retirement 
 Plan assets.................        (38,849)      (6,947)     (34,022)
Net amortization and deferral          9,896      (14,213)      13,794
   Net periodic pension
    (income) costs...........       $(10,627)    $ (2,028)    $ (2,562)

      The net periodic pension income for 1995 and 1994 was
determined using a weighted average discount rate of 8.5% and
6.25%, respectively, and a rate of increase in future
compensation levels of 5.5% for 1995 and 1994.  The expected
long-term rate of return on Retirement Plan assets used in
determining the net periodic pension (income) costs was 10.5% for
1995 and 8.5% for 1994.  
     The following table sets forth the Retirement Plan's funded
status at October 1, 1995 and 1994 and amounts recognized in the
Company's Consolidated Balance Sheet at December 31, 1995 and
1994:

                                                   1995          1994
                                         (Thousands of Dollars)
Actuarial present value of benefit
 obligations:
 Accumulated benefit obligation,
  including vested benefits 
  of $170,039 and $146,779.............          $173,281     $148,854

Projected benefit obligation for
 service rendered to date..............          $196,038     $171,713
Retirement Plan assets at market value.           250,246      223,376
Excess of Retirement Plan assets over
 projected benefit obligation..........            54,208       51,663
Unrecognized net gain..................           (52,846)     (60,551)
Prior service cost not yet recognized 
 in net periodic pension cost..........             3,531        3,789
Unrecognized net asset being amortized 
 over 15 years.........................            (3,971)      (4,606)
Pension asset (liability) recognized  
 in the Consolidated Balance Sheet.....          $    922     $ (9,705)
                                    - 61 -
<PAGE>
      Retirement Plan assets consist primarily of equities and
fixed income securities.  The Retirement Plan is deemed to be
fully funded for federal income tax purposes, therefore, the
Company did not make any contributions to the Retirement Plan
during 1995 or 1994.
      The actuarial present value of projected benefit obligations
for October 1, 1995 and 1994 was determined using a weighted
average discount rate of 7.5% and 8.5%, respectively, and an
assumed rate of increase in compensation of 4.5% and 5.5% for
1995 and 1994, respectively.  
      Pursuant to the PSC Statement of Policy and Order Concerning
the Accounting and Rate-making Treatment for Pensions and
Postretirement Benefits Other than Pensions (OPEB), issued
September 7, 1993 (Pension and OPEB Order), effective January 1,
1993 the Company began amortizing each year's experienced gain or
loss over ten years.  
      Pursuant to the Pension and OPEB Order, deferred accounting
has been granted by the PSC for any variation (above or below)
between actual costs of the Company's pension plans and those
costs allowed for rate-making purposes.































                                    - 62 -
<PAGE>
Other Postretirement Benefits:

       The Company provides certain health care and life insurance
benefits for retired employees through its postretirement 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 recover a portion of the costs of these
benefits, the Company requires employees who retire on or after
October 1, 1994 to contribute toward the cost of such benefits.
      Net periodic postretirement benefit cost for 1995 and 1994
includes the following components:

                                               1995                1994  
                                              (Thousands of Dollars)
  Service cost - benefits 
   attributed to the period.......          $  1,384            $  2,392

  Interest cost on accumulated
   postretirement benefit 
   obligation.....................             4,613               4,654

  Actual return on Benefit Plan
   assets.........................              (875)               (426)

  Amortization of Transition 
   Obligation.....................             3,114               3,114

  Net amortization and deferral...            (1,837)                928

  Net periodic postretirement 
   benefit cost...................          $  6,399            $ 10,662


     The Company is amortizing the unfunded accumulated
postretirement benefit obligation (Transition Obligation) at
January 1, 1993 over a 20-year period.  
     The net periodic postretirement benefit cost of the Benefit
Plan for 1995 and 1994 was determined using a weighted average
discount rate of 8.50% and 6.25%, respectively, and a rate of
increase in future compensation levels of 5.5% for both periods. 
The expected long-term rate of return of Benefit Plan assets used
in determining the net periodic postretirement benefit cost was
6.7% for 1995 and 6.6% for 1994.





                                    - 63 -
<PAGE>
     The Benefit Plan's funded status reconciled with the
Company's Consolidated Balance Sheet is as follows:

                                                    December 31,  
                                               1995               1994   
                                              (Thousands of Dollars)
  Accumulated postretirement 
   benefit obligation:
    Retirees......................           $(31,899)          $(27,526)
    Fully eligible employees......             (4,706)            (4,537)
    Other employees...............            (31,495)           (25,532)
                                              (68,100)           (57,595)
  Benefit Plan assets at fair
   value..........................             22,899             14,051

  Excess of accumulated post-
   retirement benefit obligation 
   over Benefit Plan assets.......            (45,201)           (43,544)
  Unrecognized net (gain) loss....             (8,922)           (14,489)

  Prior service cost not yet 
   recognized in net periodic 
   postretirement benefit cost....               (160)              -

  Unrecognized Transition 
   Obligation.....................             52,921             56,035

  Postretirement benefit liability 
   recognized in the
   Consolidated Balance Sheet.....           $ (1,362)          $ (1,998)

     The accumulated postretirement benefit obligation under the
Benefit Plan at December 31, 1995 and 1994 was determined using a
weighted average discount rate of 7.5% and 8.5%, respectively and
a rate of increase in future compensation levels of 4.5% and 5.5%
for 1995 and 1994, respectively.  The expected long-term rate of
return of Benefit Plan assets used in determining the net
periodic postretirement benefit cost was 6.7% for 1995 and 6.6%
for 1994.
     The assumed health care cost trend is 12% in the early years
and trends down to an ultimate rate of 5.5% by the year 2010.  A
1% increase in health care cost trend rate assumptions would
produce an increase in the accumulated postretirement benefit
obligation at December 31, 1995 and 1994 of $8.921 and $7.545
million, respectively and an increase in the aggregate service
and interest cost of the net periodic postretirement benefit cost
of $873,000 and $1.076 million for 1995 and 1994, respectively.
     The Company has established a qualified funding vehicle
for such retirement benefits for collective bargaining employees
and a similar vehicle for management employees in the form of 

                                    - 64 -
<PAGE>
qualified Voluntary Employee Beneficiary Association (VEBA)
trusts.  The Company funded the VEBA trusts in 1995 and 1994 with
tax-deductible contributions totaling $7.2 million and $8.3
million, respectively.  
      Pursuant to the 1993 Rate Order, an estimated annual level
of OPEB costs is included in the Company's electric and gas
rates, effective November 22, 1993.  In the Pension and OPEB
Order, deferred accounting has been granted by the PSC for any
variation between actual OPEB costs and those allowed for rate-
making purposes.  Such amounts are included in "Regulatory
liabilities" on the Consolidated Balance Sheet.  


NOTE 8 - COMMITMENTS AND CONTINGENCIES

Construction Program:

      Reference is made to "Management's Discussion and Analysis
of Financial Condition and Results of Operations" for information
regarding the Company's construction program for the five-year
period 1996-2000.

Roseton Plant:

      The Company is acting as agent for the cotenant owners with
respect to operation of the Roseton Plant.  Generally, the owners
share the costs and expenses of the operation of the Roseton
Plant in accordance with their respective ownership interests. 
The Company's share of direct operating expense for the Roseton
Plant is included in the appropriate expense classification in
the accompanying Consolidated Statement of Income.
      The Company, under a 1968 Agreement (Basic Agreement), has
the option to purchase the interests of Niagara Mohawk (25%) and
of Consolidated Edison Company of New York, Inc. (Con Edison)
(40%) in the Roseton Plant in December 2004.  The exercise of
this option is subject to PSC approval.  
      On March 30, 1994, Niagara Mohawk and the Company entered
into a Letter of Understanding which, among other things,
provides for:
      (1)  consideration by the Company, Niagara Mohawk and Con
Edison for staggering the operation of the two units of the
Roseton Plant in order to take advantage of current market costs
for energy and capacity; and
      (2)  the purchase by the Company of up to 100 MW of energy
and capacity during peak periods from Niagara Mohawk during the
period May 1, 1994 through April 30, 1995.  During the period May
1995 through April 2004, the Company may from time to time issue
requests for proposals to purchase energy and capacity on the
open market.  Niagara Mohawk, among others, will be requested by
the Company to bid on these future purchases.

                                    - 65 -
<PAGE>
      (3)  Subject to regulatory approval, Niagara Mohawk and the
Company intend to enter into agreements, which would cover (i)
the purchase by the Company of the following electric capacity
and associated energy from Niagara Mohawk if needed: 15 MW each
year, subject to a reservation charge, commencing in 1998 through
2004, up to a total of 75 MW, and up to an additional 150 MW in
the period 2001 through 2004 not subject to a reservation charge;
(ii) the option of Niagara Mohawk to bid competitively for the
Company's long-term purchases of capacity and energy during the
period May 1995 through April 2004 as indicated in Item (2) and
(iii) a revision in the Company's 1968 option to purchase Niagara
Mohawk's 25% interest in the Roseton Plant in 2004 which would
give Niagara Mohawk an option to retain said 25% interest.
      Entering into the agreements contemplated by the Letter of
Understanding will result in capital and operating and
maintenance cost savings.  The Company's option to buy Con
Edison's interest in the Roseton Plant is not affected by the
Letter of Understanding.  


Nuclear Liability and 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 due to 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 $6.8
million (subject to adjustment for inflation) and the Company
could be assessed $339,800 (subject to adjustment for inflation)
in respect to 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
$233,200 per week if the Nine Mile 2 Plant 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% 

                                    - 66 -
<PAGE>
of the weekly indemnity for a second 52-week period and 80% for a
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 Units 1 and 2 of
the Nine Mile Point Nuclear Station and $2.25 billion of excess
property damage coverage for the Nine Mile 2 Plant.  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.

Natural Gas Supply:

      The Company presently has in place five firm contracts
(Contracts) for the supply of an aggregate of 10,497,708 Mcf. of
natural gas, all of which are with third-party gas suppliers
(Suppliers).  Under the Contracts, the Suppliers deliver the gas
to interstate pipeline companies (Pipelines) and the Pipelines
deliver the gas to the Company's gas transmission system under
separate firm transportation contracts which the Company has in
place with such Pipelines.  With the exception of 20,000 Mcf. per
day of gas purchased from Canadian sources under contracts which
expire in January 2012, or approximately 30% of total gas
purchases, all of the above gas supply contracts will terminate
in 1996 after the 1995-1996 winter heating season and will be
replaced before the next winter heating season.
      The Company has in aggregate, gas storage capability of
39,604 Mcf. per day, under long-term contracts.  The Company has
a firm gas peaking service, under contract, for the supply of
9,804 Mcf. per day for 15 days during the period November 1-
March 31.  This contract became effective November 1, 1995 and
will remain in effect through March 31, 1998.  
      In addition to the above, the Company has in place an
interim contract for the supply of up to 100,000 Mcf. per day of
gas during April through October of each year for use as boiler
gas at the Roseton Plant.  This interim contract expires on March
31, 1996.  The Company expects to replace the interim contract
with a long-term contract which will expire in October 2006.
      In April 1992, FERC issued its final rule (Order 636)
regarding the unbundling of natural gas supply services from
transportation and storage services.  These changes will require
the Company to pay a share of certain transition costs incurred
by the Pipelines as a result of Order 636.  

                                    - 67 -
<PAGE>
     The Company has been billed $3.4 million of transition costs
through December 31, 1995 by the Pipelines.  Transition costs are
currently being recovered by the Company through its gas cost
adjustment clause.  The aggregate amount that the Company will
ultimately be billed will depend on the outcome of FERC
proceedings, the outcome of which the Company is not able to
predict.  Depending on the outcome of such proceedings, the
Company projects the aggregate amount of such transition costs
could range between $4.0 million and $6.0 million over the next
several years.  The Company expects to continue to recover such
costs through its gas cost adjustment clause.
      The Company received $2.765 million in gas supplier refunds
during 1995, resulting from settlements approved by FERC.  Gas
supplier refunds are distributed to firm gas customers through
the Company's gas cost adjustment clause over a subsequent
twelve-month period as authorized by the PSC.  


Take-or-Pay Gas Costs:

      In prior years, many interstate gas pipeline companies had
entered into contracts with gas producers which required the
pipeline companies to pay for a minimum amount of gas whether or
not the gas is actually taken from the producer (take-or-pay
costs).  Pursuant to the FERC authorization, the Company's gas
suppliers have included certain amounts of their take-or-pay
costs in the rates charged to the Company.  
      In October 1988, the PSC commenced a proceeding to
determine, among other things, the recoverability and allocation
in gas rates of New York State distribution companies of contract
take-or-pay costs charged them by pipeline suppliers.  In
connection with such proceeding, the PSC has issued several
orders which have directed, among other things, that 65% of take-
or-pay costs being incurred by the Company may be recovered
through current rates, subject to refund.  
      On September 15, 1995, the Company submitted to the PSC a
Motion for Approval of a settlement agreement entered into
between the Company and PSC Staff which would allow for the
Company to recover through its rates approximately $3.0 million
of deferred take-or-pay costs, which amount will be reduced by an
associated $1.7 million including $200,000 of interest on take-
or-pay refunds received from various gas transmission companies
in 1994.
      Such settlement agreement allows the Company to amortize and
recover in rates the supplier take-or-pay charges deferred as of
June 30, 1995 (an amount estimated to be, including interest,
$3.0 million as of December 31, 1995 ), together with interest
accrued on such deferral up to the dates rates reflecting such
amortization are made effective January 1996.  Amortization
periods and specific rate recovery methods will vary, depending 

                                    - 68 -
<PAGE>
on the type of customer.  As of January 1996, the Company will
terminate the accrual of interest on the balances of deferred
costs to be amortized and shall not be entitled to accrue
additional interest on such deferred costs during the
amortization period.  The settlement agreement also provides for
the recovery of take-or-pay charges incurred after July 1, 1995
on a current basis until the total of such charges (excluding
interest) equals $5.5 million.  The settlement requires that only
65% of the costs above this amount be collected on a current
basis.  The remaining 35% will be spread out and recovered over a
48-month period.  
      The PSC approved the Company's settlement agreement in
November 1995.  The Company began to recover these take-or-pay
charges in January 1996.


Environmental Matters:

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

      Clean Water Act Compliance:  The Company is a party to a
proceeding before the New York State Department of Environmental
Conservation related to the processing of permit renewal
applications for the Company's generating stations under the
State Pollution Discharge Elimination System.  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 power plants that affect "acid rain" and ozone.
      The Phase II "acid rain" emissions reduction requirements do
not apply to the Company's generating plants until January 1,
2000; however, the Company has elected to have the Roseton Plant
covered under the Phase I acid rain regulation 40 CFR Part 72
which went into effect in 1995.  More specifically, the Roseton
Plant has been conditionally identified as a substitute for a
Phase I plant.  Such a substitution, if implemented, results in
the Environmental Protection Agency (EPA) providing emissions
allowances to the Roseton Plant.  Emission allowances that are
not needed for current year emissions may be held for use in
future years or sold.  A decision by the Company to implement a
substitution plan must be made each year by December 1.  



                                    - 69 -
<PAGE>
      The Company's emissions of nitrogen oxides were subject to
additional controls effective May 31, 1995 under Title I of the
CAA Amendments.  To comply with these requirements, the Company
installed nitrogen oxides emissions controls at a cost of $4.7
million for the Danskammer Plant and $3.7 million for the
Company's share of the Roseton Plant.  The Northeast Ozone
Transport Commission (OTC), of which New York State is a member,
has agreed that additional reductions of nitrogen oxides emission
will be required in 1999 and, possibly, in the year 2003. 
Because regulations have not yet been promulgated by New York
State to implement this agreement, the specific reductions
required at the Company's facilities have not been determined.
      The Company expects that it will have adequate financial
resources to comply with the requirements of the CAA Amendments.

      Former Manufactured Gas Plant Facilities:  In May 1995, the
City of Newburgh, New York (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 site of
the Company's former coal gasification plant (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 money damages of at least
$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.
      In its answer to the City's complaint, the Company denied
liability and asserted affirmative defenses and counterclaims
against the City.  The Company also filed a third-party complaint
against "John Doe" defendants whose identities are presently
unknown but who may be responsible for some or all of the
contamination that is alleged to exist on the City's property.
      In October 1995, the Company and the New York State
Department of Environmental Conservation (NYSDEC) entered into an
Order on Consent regarding the development and implementation of
an investigation and remediation program for the Central Hudson
Site and the City's adjacent and nearby property.



                                    - 70 -
<PAGE>
      In November 1995, the Company and the City reached an
agreement in a Memorandum of Understanding to postpone until
August 1, 1996 any further action under the City's lawsuit
pending the results of the studies required under said Order on
Consent.  The agreement also provides for the resumption of
settlement negotiations between the Company and the City.  The
District Court has approved a schedule of proceedings consistent
with such Memorandum.
      At this time, the Company can make no prediction as to the
outcome of this matter, nor can it make reasonable estimates of
the cost of the activities required under the Order on Consent. 
However, the Company has put its insurance carriers on notice and
intends to pursue reimbursement from them.  The Company cannot
predict the extent of reimbursement that will be available from
its carriers at this time.
      By letter dated September 22, 1995, the Company has
petitioned the PSC for authorization to defer all costs including
legal defense costs, but excluding the Company's labor, related
to environmental site investigation and remediation actions that
were incurred by the Company in 1995 and thereafter in connection
with this matter.  These expenses are not reasonably known or
estimable by the Company at this time, nor can the Company
predict at this time what action the PSC will take on such letter
petition. Such costs for 1995 amounted to $719,700 and were
included in "Deferred Charges-Other" on the Consolidated Balance
Sheet.
      

Asbestos Litigation:

      Since 1987, the Company, along with many other parties, has
been joined as a defendant or third-party defendant in
approximately 740 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.
      Approximately 155 of these cases have been dismissed with
respect to the Company, and the Company has agreed to settle 105
of the cases for amounts which are not material in relation to
the consolidated financial statements.  Consequently, on January
1, 1996, the Company was a defendant in approximately 480
asbestos cases.  Although the Company is presently unable to
assess the validity of the remaining asbestos lawsuits, and
accordingly 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 


                                    - 71 -
<PAGE>
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.  
      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.  


Tax Matters:

      Assessments:  The Internal Revenue Service (IRS) has
completed its examination of the Company's federal income tax
returns for 1987 and 1988.  The IRS Agent's Report proposes
adjustments which have the potential to increase the Company's
tax liability by approximately $16.0 million plus interest. 
Included in the proposed adjustments are significant issues
related to the tax in-service date of the Nine Mile 2 Plant.  In
May 1994, the Company, in defending its position regarding Nine
Mile 2 Plant and other tax matters, filed a Protest with the
Appeals Office of the IRS.  The Appeals Office of the IRS has not
yet rendered a decision on such Protest.  To the extent the IRS
is able to sustain its positions on Nine Mile 2 Plant, the
Company will be required to absorb a portion of the resulting tax
liability.  Although the Company is unable to assess its ultimate
liability in this matter, the Company believes it would be able
to recover a significant portion of any additional liability
including interest through rates.  Accordingly, the Company
expects that the ultimate resolution of this matter will not have
a material adverse effect on the Company's financial position.


Rental Expenses and Lease Commitments:

      The Company has lease commitments expiring at various dates,
principally for real property and data processing equipment. 
None of these leases involves any major facilities or any
material noncancelable rental commitments.  


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.              


                                    - 72 -
<PAGE>
      Included in such proceedings are two lawsuits against the
Company arising from a November 1992 explosion in a dwelling in
Catskill, New York involving personal injuries, including the
death of an occupant, and property damage.  One of the lawsuits
seeks recovery from the Company of compensatory and punitive
damages in the sum of $4.0 million.  The other lawsuit seeks an
unspecified amount of compensatory and punitive damages. 
      The PSC, by Order issued and effective January 7, 1994,
approved an Agreement which provides for a program for evaluating
and replacing cast iron and unprotected steel pipeline
facilities, and for an investment in four permanent employee
training centers.  The Company's shareholders contributed $1.0
million in 1995 and $500,000 in 1994 toward the costs of such
training centers and replacement program.  No shareholder
contribution will be required in 1996, however, under such
Agreement the Company's shareholders may be required to
contribute in 1997 from $0 to $500,000 toward the cost of such
pipeline replacement program, depending on the Company's
completion of certain tasks by specified dates.  The Company
believes these tasks will be completed by the specified dates
and, therefore, the Company's shareholders would have no further
contribution obligations under such Agreement.  
      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.  Three lawsuits have arisen from the
Wappingers Falls incident.  One of the lawsuits seeks recovery
from the Company of compensatory and punitive damages in the sum
of $1.0 million, one seeks recovery of $250,000 in compensatory
damages, and the other lawsuit seeks an unspecified amount of
damages against the Company.
      The Company is investigating the above claims and presently
has insufficient information on which to predict their 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.  At this time, the Company can make no
prediction as to any other litigation which may arise out of
these incidents.










                                    - 73 -
<PAGE>
NOTE 9 - DEPARTMENTAL INFORMATION

      The Company is engaged in the electric and natural gas
utility businesses and serves the Mid-Hudson Valley region of New
York State.  Total revenues and operating income before income
taxes (expressed as percentages), derived from electric and gas
operations for each of the last three years, were as follows:

                            Percent of             Percent of Operating
                          Total Revenues        Income Before Income
Taxes

                        Electric    Gas       Electric      Gas 
1995                 80%           20%           90%              10%
1994                 80%           20%           89%              11%
1993                 82%           18%           89%              11%


      For the year ended December 31, 1995, the Company served an
average of 261,876 electric and 59,895 gas customers.  Of the
Company's total electric revenues during that period,
approximately 43% was derived from residential customers, 32%
from commercial customers, 18% from industrial customers and 7%
from other utilities and miscellaneous sources.  Of the Company's
total gas revenues during that period, approximately 39% was
derived from residential customers, 29% from commercial
customers, 4% from industrial customers, 24% from interruptible
customers and 4% from miscellaneous sources (including revenues
from transportation of customer-owned gas).
      The Company's largest customer is International Business
Machines Corporation (IBM), which accounted for approximately 10%
of the Company's total electric revenues and approximately 6% of
its total gas revenues for the year ended December 31, 1995. 
Reference is made to "Management's Discussion and Analysis of
Financial Condition and Results of Operations" for further
information regarding IBM.
      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.










                                    - 74 -
<PAGE>
                                                     Electric         
                                             1995        1994       1993
                                               (Thousands of Dollars)
Operating Revenues................         $409,445    $411,082   $422,925
Operating Expenses:
 Fuel and purchased electricity...          113,263     111,984    122,250
 Depreciation and amortization....           37,503      36,597     35,625
 Other, excluding income tax......          168,313     172,057    173,167
    Total.........................          319,079     320,638    331,042

Operating Income before Income Tax           90,366      90,444     91,883
Federal income tax, including
 deferred income tax - net........           26,632      25,334     25,642
Operating Income..................         $ 63,734    $ 65,110   $ 66,241

Construction Expenditures.........         $ 41,195    $ 49,316   $ 43,097

Identifiable Assets at December 31*
 Net utility plant................         $784,345    $776,169   $777,044
 Construction work in progress....           38,978      46,879     35,424
   Total utility plant............          823,323     823,048    812,468
 Materials and supplies...........           23,167      27,080     28,063
   Total..........................         $846,490    $850,128   $840,531

                                                        Gas             
                                             1995       1994         1993
                                               (Thousands of Dollars)
Operating Revenues................         $102,770    $104,586  $ 94,448
Operating Expenses:
 Purchased natural gas............           62,339      60,588    53,900
 Depreciation and amortization....            3,964       3,783     4,057
 Other, excluding income tax......           26,899      29,483    25,210
    Total.........................           93,202      93,854    83,167

Operating Income before Income Tax            9,568      10,732    11,281
Federal income tax, including
 deferred income tax - net........            2,408       2,709     2,961
Operating Income..................         $  7,160    $  8,023  $  8,320

Construction Expenditures.........         $  9,074    $  8,729  $ 10,940

Identifiable Assets at December 31*
 Net utility plant................         $103,979    $ 96,652  $ 95,074
 Construction work in progress....            9,792      11,373     7,317
   Total utility plant............          113,771     108,025   102,391
 Materials and supplies...........            4,423       6,309     7,354
   Total..........................         $118,194    $114,334  $109,745

 *Identifiable assets not included herein are considered to be    
   corporate assets and have not been allocated between the       
   electric and gas segments.
                                    - 75 -
<PAGE>
NOTE 10 - 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.
     The estimated fair values of the Company's financial
instruments are as follows:
                                                     December 31, 1995  
                                                Carrying           Fair
                                                 Amount            Value
                                                (Thousands of Dollars)

Cash and temporary cash investments...          $ 15,478         $  15,478
Cumulative preferred stock subject 
  to mandatory redemption.............           (35,000)          (34,875)   
 Long-term debt (including
  current maturities).................          (390,822)         (411,299) 

                                                     December 31, 1994  
                                                Carrying           Fair
                                                 Amount            Value
                                                (Thousands of Dollars)

Cash and temporary cash investments...          $  5,792         $   5,792
Cumulative preferred stock subject 
  to mandatory redemption.............           (35,000)          (29,500)
Long-term debt (including
  current maturities).................          (392,889)         (389,957)
Notes payable.........................            (3,000)           (3,000)
                                    - 76 -
<PAGE>
      Effective January 1, 1994, the Company adopted SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity
Securities" (SFAS 115) issued by the FASB.  The adoption of SFAS
115 resulted in the recording of an unrealized net holding gain
as an adjustment to common stock equity.  This unrealized net
holding gain represents the amount by which the market value of
an investment that the Company maintains in an insurance company
exceeds its cost, net of tax effects.  During 1995, the Company
sold all of its investment in the stock of an insurance company
which the Company held as an "available-for-sale" investment. 
The Company recognized net proceeds of $2.9 million on the stock
sold, which cost $775,000.  This sale resulted in a gross
realized gain of $2.1 million which is recorded in the
Consolidated Statement of Income.  
      Additionally, in accordance with SFAS 115, investments in
debt and equity securities held in the Nine Mile 2 Plant
Decommissioning Trust Fund (Fund) are reported at fair value. 
Pursuant to PSC accounting requirements, gains or losses on Fund
investments are included in nuclear decommissioning trust assets
and added to the accumulated decommissioning component of
accumulated depreciation included in the Consolidated Balance
Sheet.  





























                                    - 77 -
<PAGE>
<TABLE>
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

     Selected financial data for each quarterly period within 1995 and 1994 are presented
below:
<CAPTION>
                                                                                  Earnings Per
                                                                   Income           Average
                                                                  Available         Share of
                                                                     for             Common
                               Operating        Operating          Common            Stock 
                               Revenues          Income             Stock         Outstanding
                                       (Thousands of Dollars)                      (Dollars)
Quarter Ended:
<S>                            <C>              <C>              <C>             <C>

       1995
  March 31............         $144,686          $24,204          $18,273           $1.06
  June 30.............          118,618           14,731            9,574             .55
  September 30........          127,547           18,817           12,260             .70
  December 31.........          121,364           13,142            7,543             .43

       1994
  March 31............         $162,836          $28,175          $20,785           $1.22
  June 30.............          117,214           14,500            7,646             .45
  September 30........          116,091           17,540           11,152             .65
  December 31.........          119,527           12,918            6,219             .36







                                                   - 78 -
</TABLE>
</PAGE>