SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

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

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998

                                       OR

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

      For the transition period from __________ to __________

                         COMMISSION FILE NUMBER: 1-2987

                        NIAGARA MOHAWK POWER CORPORATION
             (Exact name of registrant as specified in its charter)

            STATE OF NEW YORK                              15-0265555

       (State or other jurisdiction                     (I.R.S. Employer
       of incorporation or organization)               Identification No.)

300 ERIE BOULEVARD WEST     SYRACUSE, NEW YORK              13202
   (Address of principal executive offices)               (Zip Code)

                                 (315) 474-1511
              (Registrant's telephone number, including area code)

           Securities registered pursuant to Section 12(b) of the Act:
            (Each class is registered on the New York Stock Exchange)


                               Title of each class

                           Common Stock ($1 par value)
                           ---------------------------


Preferred Stock ($100 par                       Preferred Stock ($25 par
value-cumulative):                              value-cumulative):
-------------------------                       ------------------------

3.40% Series  4.10% Series  6.10% Series        9.50% Series
3.60% Series  4.85% Series  7.72% Series        Adjustable Rate Series A &
3.90% Series  5.25% Series                      Series C


        Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.     YES [ X ]     NO [   ]


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K   [ X ]


State the aggregate market value of the voting stock held by non-affiliates of
the registrant.

     APPROXIMATELY $2,800,000,000 AT MARCH 1, 1999.

Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.

    COMMON STOCK, $1 PAR VALUE, OUTSTANDING AT March 1, 1999 - 187,364,863

<PAGE>


                        NIAGARA MOHAWK POWER CORPORATION
                        INFORMATION REQUIRED IN FORM 10-K

INDEX
-----

          PART I 
          ------ 

Glossary of Terms
Item 1.     Business
Item 2.     Properties
Item 3.     Legal Proceedings
Item 4.     Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant

          PART II
          -------

Item 5.     Market for the Registrant's Common Equity and Related
            Stockholders Matters
Item 6.     Selected Consolidated Financial Data
Item 7.     Management's Discussion and Analysis of Financial Condition
            and Results of Operations
Item 7A.    Quantitative and Qualitative Disclosures About Market Risk
Item 8.     Financial Statements and Supplementary Data
Item 9.     Changes in and Disagreements with Accountants on
            Accounting and Financial Disclosure 

          PART III
          --------

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

          PART IV
          -------

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

Signatures

<PAGE>

                       NIAGARA MOHAWK POWER CORPORATION

                                GLOSSARY OF TERMS
                                -----------------

TERM        DEFINITION
----        ----------

AFC         Allowance for Funds Used During Construction

CNG         CNG Transmission Corporation, an interstate natural gas pipeline
            regulated by FERC

CNP         Canadian Niagara Power Company, Limited

COPS        Competitive Opportunities Proceeding

CTC         Competitive transition charges: a mechanism established in the
            POWERCHOICE agreement to recover stranded costs from customers

DEC         New York State Department of Environmental Conservation

DOE         U. S. Department of Energy

Dth         Dekatherm: one thousand cubic feet of gas with a heat content of
            1,000 British Thermal Units per cubic foot

EBITDA      Earnings before Interest Charges, Interest Income, Income Taxes,
            Depreciation and Amortization, Amortization of Nuclear Fuel,
            Allowance for Funds Used During Construction, MRA Regulatory
            Asset amortization, non-cash regulatory deferrals and other
            amortizations and extraordinary items (a non-GAAP measure of
            cash flow)

FAC         Fuel Adjustment Clause: a clause in a rate schedule that provides
            for an adjustment to the customer's bill if the cost of fuel varies
            from a specified unit cost

FASB        Financial Accounting Standards Board

FERC        Federal Energy Regulatory Commission

GAAP        Generally Accepted Accounting Principles

GRT         Gross Receipts Tax

GWh         Gigawatt-hour: one gigawatt-hour equals one billion watt-hours

IPP         Independent Power Producer: any person that owns or operates, in
            whole or in part, one or more Independent Power Facilities

IPP         Independent Power Producers that were a party to the MRA
Party

KW          Kilowatt: one thousand watts

KWh         Kilowatt-hour: a unit of electrical energy equal to one kilowatt of
            power supplied or taken from an electric circuit steadily for one
            hour

MRA         Master Restructuring Agreement - an agreement, including amendments
            thereto, which terminated, restated or amended certain IPP Party 
            power purchase agreements effective June 30, 1998

MRA         Recoverable costs to terminate, restate or amend IPP Party 
regulatory  contracts, which have been deferred and are being amortized and 
asset       recovered under the POWERCHOICE agreement

MW          Megawatt: one million watts

MWh         Megawatt-hour: one thousand kilowatt-hours

Net Cash    Reflects interest charges plus allowance for funds used during
Interest    construction less the non-cash impact of the net amortization of
            discount on long-term debt and interest accrued on the Nuclear
            Waste Policy Act disposal liability less interest income

NRC         U. S. Nuclear Regulatory Commission

NYISO       New York Independent System Operator

NYPA        New York Power Authority

NYPP        New York Power Pool

NYPP        Eight Member Systems are: the seven New York
Member      State investor-owned electric utilities and NYPA
Systems

NYSERDA     New York State Energy Research and Development Authority

POWERCHOICE Company's five-year electric rate agreement, which incorporates
Agreement   the MRA, approved by the PSC in an order dated March 20, 1998

PPA         Power Purchase Agreement: long-term contracts under which a utility
            is obligated to purchase electricity from an IPP at specified rates

PRP         Potentially Responsible Party

PSC         New York State Public Service Commission

PURPA       Public Utility Regulatory Policies Act of 1978, as amended.  One of
            five bills signed into law on November 8, 1978, as the National
            Energy Act.  It sets forth procedures and requirements applicable to
            state utility commissions, electric and natural gas utilities and 
            certain federal regulatory agencies.  A major aspect of this law
            is the mandatory purchase obligation from qualifying facilities.

QF          Qualifying Facility: an individual (or corporation) that owns
            and/or operates a generating facility but is not primarily engaged
            in the generation or sale of electric power.  QFs are either power
            production or cogeneration facilities that qualify under Section
            201 of PURPA.

ROE         Return on Common Stockholders Equity

SFAS        Statement of Financial Accounting Standards No. 71
No. 71      "Accounting for the Effects of Certain Types of Regulation"

SFAS        Statement of Financial Accounting Standards No. 101
No. 101     "Regulated Enterprises - Accounting for the Discontinuance of
            Application of FASB Statement No. 71"

SFAS        Statement of Financial Accounting Standards No. 106
No. 106     "Employers' Accounting for Postretirement Benefits Other
            Than Pensions"

SFAS        Statement of Financial Accounting Standards No. 109
No. 109     "Accounting for Income Taxes"

SFAS        Statement of Financial Accounting Standards No. 121
No. 121     "Accounting for the Impairment of Long-Lived Assets and for
            Long-Lived Assets to Be Disposed Of"

Stranded    Utility costs that may become unrecoverable due to a change in
Costs       the regulatory environment

Unit 1      Nine Mile Point Nuclear Station Unit No. 1

Unit 2      Nine Mile Point Nuclear Station Unit No. 2

<PAGE>

NIAGARA MOHAWK POWER CORPORATION

                                     PART 1
                                     ------

ITEM 1.  BUSINESS

Niagara Mohawk Power Corporation (the "Company"), organized in 1937 under the
laws of New York State, is engaged principally in the regulated business of
generation, purchase, transmission, distribution and sale of electricity and the
purchase, distribution, sale and transportation of gas in New York State.  See
Part II, Item 8. Financial Statements and Supplementary Data - "Note 12. Segment
Information."

The regulated business described above is the Company's primary business
segment.  All other businesses of the Company are non-regulated and at this time
are not considered to be material to the Company's results of operations and
financial condition.  For purposes of this report, all discussion relates to the
regulated electric and gas business unless otherwise noted.

                                     GENERAL
                                     -------

Until recent years, the electric and gas utility industry operated in a
relatively stable business environment, subject to traditional cost-of-service
regulation.  The investment community, both shareholders and creditors,
considered utility securities to be of low risk and high quality. Regulators
upheld the utility's right to provide service in its franchise areas in exchange
for the utility company's obligation to provide universal service to customers
in its service territory, subject to cost-of-service regulation.  Such
regulation often encouraged regulators and other governmental bodies to use
utilities as vehicles to advance social programs and collect taxes.  In general,
prices were established based on cost-of-service, including a fair rate of
return and utilities were allowed to fully recover all prudently incurred costs.
Cash flows were relatively predictable, as was the industry's ability to sustain
dividend payout and interest coverage ratios.

Consequently, the Company's past electricity and gas prices reflected
traditional utility regulation.  As such, the Company's electricity prices have
included both state-mandated purchased power costs from IPPs, at costs far
exceeding the Company's actual avoided costs, and the costs of high taxes in
the state of New York.  Avoided costs are the costs the Company would otherwise
incur to generate power if it did not purchase electricity from another source.

While the Company was experiencing rising prices, rapid technological advances
have significantly reduced the price of new generation and significantly
improved the performance of smaller scale generating units. Actions taken by
other utilities throughout the country to lower their prices, including those in
areas with already relatively low prices, increase the threat of industrial
relocation and the need to offer discounts to industrial customers.

Recognizing the competitive trends in the electric utility industry and the
impracticability of remedying the situation through a series of customer rate
increases, in mid-1996, the Company began comprehensive negotiations to
terminate, amend or restate a substantial portion of above market PPAs in an
effort to mitigate the escalating cost of these PPAs as well as to prepare the
Company for a more competitive environment.  These negotiations led to the MRA
and the POWERCHOICE agreement.

In 1998, the Company finalized these agreements and believes they will
significantly improve its financial outlook.  Pursuant to the Company's
POWERCHOICE agreement, approved by the PSC, which regulates utilities in the
state of New York, the Company agreed to a five year rate plan and agreed to
divest its fossil and hydro generating assets, representing 4,217 MW of capacity
and approximately $1.1 billion of net book value.  The Company has entered into
contract to sell its 72 hydro generating stations and its two coal-fired
generating stations (Huntley and Dunkirk).  The Company is continuing its
efforts to pursue the sale of its two oil and gas fired plants in Albany and
Oswego. In January 1999, the Company announced plans to pursue the sale of its
nuclear assets.

As part of the MRA, the Company terminated 18 PPAs for 1,092 MW, restated 8 PPAs
for 535 MW and amended one PPA for 42 MW in exchange for cash and shares of
Company common stock.  Management believes that the MRA and the POWERCHOICE
agreement provide the Company with financial stability and create an improved
platform from which to build value.  The primary objective of the MRA was to
convert a large and growing off-balance sheet payment obligation that threatened
the financial viability of the Company into a fixed and manageable capital
obligation.  Accordingly, the Company believes that the lower contractual
obligations resulting from the MRA will significantly improve cash flow which
can be dedicated to reduce indebtedness incurred to fund the MRA.  With the
POWERCHOICE agreement, the Company has lowered prices for its industrial,
commercial and residential electric customers for a period of three years and
provides reasonable certainty of prices for the years thereafter.  The 
POWERCHOICE agreement and the MRA also facilitate the creation of a
competitive electricity supply market in the Company's service territory.

In the near term, the Company believes the greatest opportunity for improving
the cash flow and financial condition of the Company will come from paying down
debt.  The Company will continue to emphasize operational excellence and seek to
improve margins through cost reductions.  In addition, the Company intends to
pursue low risk unregulated business opportunities through its unregulated
subsidiaries.  Pursuant to the POWERCHOICE agreement, the Company was authorized
to form a holding company that would enhance the Company's ability to explore
unregulated business opportunities to foster longer term strategic growth.
The Company has obtained approval from its shareholders and several regulatory
agencies for the formation of a holding company.  The implementation of a
holding company will occur following the receipt of one final regulatory
approval.  See Item 5. Market for the Registrant's Common Equity and Related 
Stockholder Matters - "Formation of Holding Company".

For a discussion of events that occurred during 1998 in the competitive
environment, federal and state regulatory initiatives and the Company's efforts
to address its competitive disadvantages and financial condition, see Part II,
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.

<PAGE>

The following topics are discussed under the general heading of "Business."
Where applicable, the discussions make reference to the various other items of
this Form 10-K.

TOPIC
-----

Regulation and Rates
IPPs
New York Power Authority
Other Purchased Power
Fuel for Electric Generation
Nuclear Operations
Electric Supply Planning
Electric Delivery Planning
Gas Delivery
Gas Supply
Financial Information About Segments
Environmental Matters
Research and Development
Construction Program
Insurance
Employee Relations
Seasonality

In addition, for a discussion of the Company's properties, see Item 2.
Properties - "Electric Service" and "Gas Service."  For a discussion of the
Company's treatment of working capital items, see Part II, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
"Financial Position, Liquidity and Capital Resources."

                              REGULATION AND RATES
                              --------------------

Several critical initiatives have been undertaken by various regulatory bodies
and the Company that have had, and are likely to continue to have, a significant
impact on the shape of the Company and the utility industry.  See Part II, Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - "PSC Competitive Opportunities Proceeding - Electric," "FERC
Rulemaking on Open Access and Stranded Cost Recovery," and "Other Federal and
State Regulatory Initiatives -PSC Proposal of New IPP Operating and PPA
Management Procedures," "Future of the Natural Gas Industry," "NRC Policy
Statement and Amended Decommissioning Funding Regulations," "PSC Staff's
Tentative Conclusions on the Future of Nuclear Generation," and "NRC and Nuclear
Operating Matters" for a discussion of these initiatives.

POWERCHOICE AGREEMENT AND THE MRA.  For a discussion of the POWERCHOICE
agreement and the MRA, see Part II, Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations - "Master Restructuring
Agreement and the POWERCHOICE Agreement"

MULTI-YEAR GAS RATE SETTLEMENT AGREEMENT AND FUTURE OF THE NATURAL GAS BUSINESS.
For a discussion of the three-year gas rate settlement agreement that was
conditionally approved by the PSC in December 1996 and the PSC's efforts to
restructure the gas industry, see Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Other Federal and
State Regulatory Initiatives - "Multi-Year Gas Rate Settlement Agreement" and "-
"Future of the Natural Gas Business."

PRICE DISCOUNTS.  For a discussion of price discounts offered to customers, see
Part II, Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - "Other Company Efforts to Address Competitive Challenges
- Customer Discounts."

                                      IPPS
                                      ----

In 1998, the Company purchased 9,668,000 MWh or about 25% of its total power
supply from IPPs, which is a 29% reduction from 1997.  For a discussion of
Company efforts to reduce its IPP costs, see Item 3. Legal Proceedings, Part II,
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - "Master Restructuring Agreement and the POWERCHOICE Agreement"
and "Other Federal and State Regulatory Initiatives - PSC Proposal of New IPP
Operating and PPA Management Procedures" and Part II, Item 8. Financial
Statements and Supplementary Data - Note 9. "Commitments and Contingencies -
Long-Term Contracts for the Purchase of Electric Power" and Note 10. "Fair Value
of Financial and Derivative Financial Instruments."

                            NEW YORK POWER AUTHORITY
                            ------------------------

The Company presently has contracts to purchase electricity from a number of
generating facilities owned by the NYPA. In 1998, these purchases amounted to
7,483,000 MWh, or about 19% of the Company's total power supply requirements.
The Company credits to its residential customers, pursuant to the terms of the
agreements with NYPA, a portion of the low cost power purchased from NYPA
hydropower sources.  Refer to Part II, Item 8. Financial Statements and
Supplementary Data - "Note 9. Commitments and Contingencies - Long-Term
Contracts for the Purchase of Electric Power" for a table that summarizes the
NYPA generating source, amounts of power, and the contract expiration dates for
NYPA electricity which the Company was entitled to purchase as of January 1,
1999.

                              OTHER PURCHASED POWER
                              ---------------------

Power purchased in 1998 from sources other than IPPs and NYPA amounted to
1,155,000 MWh, representing approximately 3% of the Company's total power
supply requirements.  Power purchases from other sources should increase in
future years as a result of the MRA and the Company's sale of its generation
facilities.  The Company purchases electricity from the NYPP and other
neighboring utilities as needed for economic operation.  The price paid for
that power is determined by specific contractual terms, based on market prices.
Physical limitations of existing transmission facilities, as well as competition
with other utilities and availability of energy impact the amount of power the
Company is able to purchase or sell and the price the Company pays or receives
for that power.

<PAGE>

                          FUEL FOR ELECTRIC GENERATION
                          ----------------------------

The POWERCHOICE agreement has eliminated the Company's FAC, which in the past
has provided for partial pass-through to customers of fuel and purchased power
cost fluctuations from amounts forecast.  The Company expects to complete the
sale of its coal-fired and hydro generating assets in 1999.  The Company
continues to pursue the sale of its two oil and gas fired generating assets.
See Part II, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Master Restructuring Agreement and the
POWERCHOICE Agreement."

COAL.  The C. R. Huntley and Dunkirk Steam Stations, the Company's only
coal-fired generating stations purchased their 1998 coal requirements under
short-term contracts.  Similar supply arrangements are in place for 1999.  The
average level of coal supply was 30 days, which is managed for supply risk.

The annual average cost of coal burned was as follows:

<TABLE>
<CAPTION>

Cost              1998    1997    1996
---------------  ------  ------  ------
<S>              <C>     <C>     <C>
per million BTU  $ 1.46  $ 1.41  $ 1.39
per ton . . . .   38.16   36.68   36.00

</TABLE>

See "Environmental Matters - Air."

NATURAL GAS.  The Albany Steam Station has the capability to use natural gas, as
well as residual oil, as a fuel for electric generation.  This dual-fuel
capability permits the use of the lower cost fuel depending on fuel market
conditions.  During 1996, 1997 and 1998, natural gas was the predominant fuel
used.  Generation at this station has been curtailed significantly during this
period because of the requirement to purchase IPP power and excess capacity in
the region.  However, since the completion of the MRA, there has been a
significant increase in the use of Albany Steam Station.  The Oswego Steam
Station, primarily fueled by residual oil, has limited capability for using
natural gas for electric generation.

The Company currently purchases all natural gas for the Albany and Oswego Steam
Stations from the spot market.  This gas is purchased as an interruptible
supply; and therefore, colder than normal weather and increased demand for
capacity on interstate pipelines by other firm (non-interruptible) gas customers
could restrict the amount of gas supplied to the stations.

The Company has a 25% ownership interest in Roseton Steam Station Units No. 1
and 2 (the "Roseton Units").  Both Roseton Units have dual fuel capability with
residual oil as the primary fuel and natural gas as the alternate fuel.  Central
Hudson Gas and Electric Corporation, a co-owner and the operator of the Roseton
Steam Station, has one contract for the supply of up to approximately 100,000
Dths per day of natural gas for use at the Roseton Units.  The natural gas
supply is used primarily during off peak months (April through October of each
year), minimizing the exposure to interruption. In 1998, approximately 1.0
million Dth (the Company's share) of gas were used at the Roseton Units.

The annual average cost of natural gas burned by the Company, including the
Roseton Steam Station, was as follows:

<TABLE>
<CAPTION>

Cost             1998   1997   1996
---------------  -----  -----  -----
<S>              <C>    <C>    <C>
per million BTU  $2.35  $2.50  $1.96
per Dth . . . .   2.35   2.50   1.96

</TABLE>

RESIDUAL OIL.  The Company's total requirements for residual oil in 1999 for
its Albany and Oswego Steam Stations are estimated at approximately 2.0 million
barrels.  Fuel sulfur content standards instituted by New York State require
1.5% sulfur content fuel oil to be burned at the Albany Steam Station. Oswego
Unit No. 6 requires low sulfur fuel oil (0.7%). Oswego Unit No. 5, which burns
1.5% sulfur fuel oil, was returned to service in June 1998 after being placed on
long-term cold standby in March 1994.  All oil requirements are met on the spot
market.  At December 31, 1998, there were approximately 1.3 million barrels of
oil, or more than a 54-day supply, at the Oswego Steam Station and approximately
0.49 million barrels of oil, or a 45-day supply, at the Albany Steam Station,
based on recent burn projections.

The average price of oil for Oswego at December 31, 1998 was $19.00 per barrel
and $18.25 per barrel for 0.7% sulfur residual oil and 1.5% sulfur residual oil,
respectively.  The price of 1.5% sulfur residual oil for Albany at December 1,
1998 was $14.25 per barrel.  The fuel oil prices quoted include the $3.05 per
barrel Petroleum Business Tax imposed by New York State.

The supply of residual oil for the Roseton Units has been arranged by Central
Hudson Gas and Electric Corporation.  All oil requirements are met on the spot
market. 
The annual average cost of residual oil burned at the Albany, Oswego and
Roseton Steam Stations was as follows:

<TABLE>
<CAPTION>

Cost              1998    1997    1996
---------------  ------  ------  ------
<S>              <C>     <C>     <C>
per million BTU  $ 3.09  $ 4.05  $ 3.81
per barrel. . .   19.45   25.58   24.15

</TABLE>

NUCLEAR.  The supply of fuel for the Company's Nine Mile Point nuclear
generating plants involves: (1) the procurement of uranium concentrates, (2) the
conversion of uranium concentrates to uranium hexafluoride, (3) the enrichment
of the uranium hexafluoride, (4) the fabrication of fuel assemblies and (5) the
disposal of spent fuel and radioactive wastes. Agreements for nuclear fuel
materials and services for Unit 1 and Unit 2 (in which the Company has a 41%
interest) have been made through the following years:
<TABLE>
<CAPTION>

                      Unit No. 1  Unit No. 2
                      ----------  ----------
<S>                   <C>         <C>
Uranium Concentrates  2002        2002
Conversion . . . . .  2002        2002
Enrichment . . . . .  2003        2003
Fabrication. . . . .  2007        2006

</TABLE>

Arrangements have been made for procuring a portion of the uranium, conversion
and enrichment requirements through the years listed above, leaving the
remaining portion of the requirements uncommitted.  Enrichment services are
under contract with the U.S. Enrichment Corporation for up to 100% of the
requirements through the year 2003.  Up to approximately 90% and 85% of the
uranium and conversion requirements are under contract through the year 2002 for
Unit 1 and Unit 2, respectively.  The uncommitted requirements for nuclear fuel
materials and services are expected to be obtained through long-term contracts
or secondary market purchases.

The cost of fuel utilized at Unit 1 for and Unit 2 was as follows:

<TABLE>
<CAPTION>

Cost per million BTU  1998   1997   1996
--------------------  -----  -----  -----
<S>                   <C>    <C>    <C>
Unit 1 . . . . . . .  $0.51  $0.54  $0.60
Unit 2 . . . . . . .   0.45   0.49   0.50

</TABLE>

For a discussion of nuclear fuel disposal costs and the disposal of nuclear
wastes, the recovery of nuclear fuel costs through rates and for further
information concerning costs relating to decommissioning of the Company's
nuclear generating plants, see Item 8. - Financial Statements and Supplementary
Data - "Note 1. Summary of Significant Accounting Policies - Depreciation,
Amortization and Nuclear Generating Plant Decommissioning Costs" and "Note 3.
Nuclear Operations."  For a discussion of the Company's treatment of its nuclear
assets under POWERCHOICE, see Item 7. - Management's Discussion and Analysis of
Financial Condition and Results of Operations - "Master Restructuring Agreement
and the POWERCHOICE Agreement."

<PAGE>

                               NUCLEAR OPERATIONS
                               ------------------

See Part II, Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - "Other Federal and State Regulatory Initiatives -
NRC and Nuclear Operating Matters" and Part II, Item 8. Financial Statements and
Supplementary Data - "Note 3. Nuclear Operations."

                            ELECTRIC SUPPLY PLANNING
                            ------------------------

Under the POWERCHOICE agreement, the PSC approved the Company's plan to divest
its hydro and fossil generating plants, which is a key component in the
Company's POWERCHOICE agreement to lower average electricity prices and provide
customer choice.  In addition, the Company is pursuing the sale of its nuclear
generating assets.  As a result, the Company will now purchase power through
various contracts or when necessary from the spot market.  For a discussion of
the results of the sale and discussion of power contracts, see Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - "Master Restructuring Agreement and the POWERCHOICE Agreement,"
"FERC Rulemaking on Open Access and Stranded Cost Recovery," and Item 8.
Financial Statements and Supplementary Data - Note 9. "Commitments and
Contingencies" and Note 10. "Fair Value of Financial and Derivative Financial
Instruments."

                           ELECTRIC DELIVERY PLANNING
                           --------------------------

See Part II. Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "FERC Rulemaking on Open Access and
Stranded Cost Recovery" as to how the Company's transmission system will be
managed under the ISO.

As of January 1, 1999, the Company had approximately 130,000 miles of
transmission and distribution lines for electric delivery.  Evaluation of these
facilities relative to NYPP and Northeast Power Coordinating Council planning
criteria and anticipated Company internal and external demands is an ongoing
process intended to maintain the reliability of electric service while
minimizing the capital requirements for expansion of these facilities.  For a
discussion of major restoration of the Company's electric delivery facilities in
northern New York as a result of an ice storm in January 1998, see Part II, Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operation - "1998 Storms."  The Company continually reviews the adequacy of its
electric delivery facilities and establishes capital requirements to support new
load growth.

                                  GAS DELIVERY
                                  ------------

The Company sells, distributes and transports natural gas to a geographic
territory that generally extends from Syracuse to Albany.  The northern reaches
of the system extend to Watertown and Glens Falls.  Not all of the Company's
distribution areas are physically interconnected with one another by
Company-owned facilities.  Presently, nine separate distribution areas are
connected directly with CNG, an interstate natural gas pipeline regulated by the
FERC, via seventeen delivery stations.  The Company also has one direct
connection with Iroquois Gas Transmission and one with Empire State Pipeline.

                                   GAS SUPPLY
                                   ----------

The majority of the Company's gas sales is for residential and commercial space
and water heating.  Consequently, the demand for natural gas by the Company's
customers is seasonal and influenced by weather factors.  The Company purchases
its natural gas for sale to its customers under firm and spot contracts, which
is transported on both firm and interruptible transportation contracts.  During
1998, about 93% and 7% of the Company's natural gas supply was purchased under
firm contracts and spot contracts, respectively.  The spot contracts are
generally for commitments less than 30 days.  See Part II. Item 8. - Financial
Statements and Supplementary Data - "Note 9. Commitments and Contingencies - Gas
Supply, Storage and Pipeline Commitments."  In addition, the Company has a
commitment with CNG to provide gas storage capability until March 2002.  For a
discussion of the PSC staff's proposal that natural gas utilities exit the
business of purchasing natural gas for customers over the next five years, see
Part II. Item 7. -Management's Discussion and Analysis of Financial Condition
and Results of Operations - "Generic Gas Rate Proceeding."
                       FINANCIAL INFORMATION ABOUT SEGMENTS
                       ------------------------------------

See Part II, Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations and Item 8. Financial Statements and Supplementary
Data - "Note 12. Segment Information."

<PAGE>

                              ENVIRONMENTAL MATTERS
                              ---------------------

GENERAL.  The Company's operations and facilities are subject to numerous
federal, state and local laws and regulations relating to the environment
including, among other things, requirements concerning air emissions, water
discharges, site remediation, hazardous materials handling, waste disposal and
employee health and safety.  While the Company devotes considerable resources to
environmental compliance and promoting employee health and safety, the impact of
future environmental health and safety laws and regulations on the Company
cannot be predicted with certainty.

In compliance with environmental statutes and consistent with its strategic
philosophy, the Company performs environmental investigations and analyses and
installs, as required, pollution control equipment, including, among other
things, effluent monitoring instrumentation and materials storage/handling
facilities designed to prevent or minimize releases of potentially harmful
substances.  Expenditures for environmental matters for 1998 totaled
approximately $35.1 million, of which approximately $2.1 million was capitalized
as pollution control or plant environmental surveillance equipment and
approximately $33.0 million was charged to operating expense for remediation,
operation of environmental monitoring and waste disposal programs.  Expenditures
for 1999 are estimated to total $39.9 million, of which $6.1 million is expected
to be capitalized and $33.8 million charged to operating expense.  Anticipated
expenditures for 2000 are estimated to total $31.4 million, of which $1.0
million is expected to be capitalized and $30.4 million charged to operating
expense.  The expenditures for 1999 and 2000 include the estimated costs for the
Company's expected proportionate share of the costs for site investigation and
remediation of waste sites discussed under "Solid/Hazardous Waste" below, but
exclude costs for the fossil and hydro generating plants.  Costs for site
investigation and remediation are included in operating expense to the extent
actual costs exceed the amount provided for in rates, in which case, the excess
costs are deferred for future recovery through cost-of-service based rates.

The Company believes it is probable that costs associated with environmental
compliance will continue to be recovered through the ratemaking process.  For a
discussion of the circumstances regarding the Company's continued ability to
recover these types of expenditures in rates, see Part II, Item 8. Financial
Statements and Supplementary Data - "Note 2. Rates and Regulatory Issues and
Contingencies."

ISO 14001.  During 1997, the Company had all of its fossil and nuclear
generating assets (the Oswego, Albany, Huntley and Dunkirk Steam Stations and
Nine Mile Point) certified to the ISO 14001 environmental management system
standard.  The registration audits of these facilities were conducted by
Advanced Waste Management Systems.  The Company's position has been and
continues to be that an effective environmental management system is necessary
to prudently manage environmental issues and minimize environmental liabilities.

As part of the POWERCHOICE agreement, the Company is selling its fossil and
hydro generating assets.  Sales have been announced for the hydro and coal-fired
assets (Huntley and Dunkirk Steam Stations), and the Company is pursuing the
sale of its oil and gas fired assets as well as its nuclear assets.  With the
sale of these assets, the Company will no longer be responsible for meeting the
related environmental requirements.  The following discussion of air, water and
solid waste matters presents the Company's plans for addressing environmental
requirements in the unlikely event the Company were to retain ownership of the
assets.  

AIR.  The Company is required to comply with applicable federal and state air
quality requirements pertaining to emissions into the atmosphere from its
fossil-fired generating stations and other air emission sources.  The Company's
four fossil-fired generating stations (the Albany, Huntley, Oswego and Dunkirk
Steam Stations) have Certificates to Operate issued by the DEC.

The provisions of the Clean Air Act address attainment and maintenance of
ambient air quality standards, mobile sources of air pollution, hazardous air
pollutants, acid rain, permits, enforcement, clean air research and other items.
The Clean Air Act will continue to have a substantial and increasing impact upon
the operation of fossil-fired electric power plants in future years. 
The acid rain provisions of the Clean Air Act (Title IV) require that SO2
emissions from utilities and certain other sources be reduced nationwide by 10
million tons from their 1980 levels and that NOx emissions be reduced by two
million tons from 1980 levels.  Emission reductions were to be achieved in two
phases - Phase I was to be completed by January 1, 1995 and Phase II will be
completed by January 1, 2000.

The Company has two units (Dunkirk 3 and 4) affected in Phase I.  Beginning in
1995, the Company was required to reduce SO2 emissions by approximately 10,000 -
15,000 tons per year, and the Company is complying with these requirements by
substituting non-Phase I units and by reducing the utilization of these units to
satisfy its emission reduction requirements at Dunkirk 3 and 4.

With respect to NOx, Title IV of the Clean Air Act requires emission reductions
at Dunkirk 3 and 4.  Low NOx burner technology has been installed to meet the
new emission limitations.  In addition, Title I of the Clean Air Act (Provisions
for the Attainment and Maintenance of National Ambient Air Quality Standards)
required the installation of reasonably available control technology ("RACT") on
all of the Company's coal, oil and gas-fired units by May 31, 1995.  Compliance
with Title I RACT requirements at the Company's units was achieved by installing
low NOx burners or other combustion control technology.

Phase II requirements associated with Title IV of the Clean Air Act (targeted
for the year 2000 and beyond) will require the owners of the fossil plants to
further reduce SO2 emissions at all of the fossil generating units.  Possible
options for Phase II SO2 compliance beyond those considered for Phase I
compliance include fuel switching, installation of flue gas desulfurization or
clean coal technologies, repowering and the use of emission allowances created
under the Clean Air Act.  Appropriate deployment of these options will be
determined by the new owners.

In September 1994, the states comprising the Northeast Ozone Transport
Commission (New York State included) signed a Memorandum of Understanding that
calls for each member state to develop regulations for two additional phases of
NOx reduction beyond RACT (referred to as Phase II and Phase III NOx
reductions).  In Phase II, air emission sources located in upstate New York
(which includes all of the Company's air emission sources) will have to reduce
NOx emissions by May, 1999 by 55 percent relative to 1990 levels.  In Phase III,
these air emission sources will have to reduce NOx emissions in May 2003 by 75
percent relative to 1990 levels.  The Memorandum of Understanding provides that
the specified reductions in Phase III may be modified if evidence shows that
alternative NOx reductions, together with other emission reductions, will
satisfy the air quality standard across the region.  The DEC has proposed
regulations governing the Phase II NOx reduction program in New York State,
which will be implemented beginning May 1, 1999.  The need for and extent of any
further reductions needed in Phase III is the focus of Phase III working group
meetings currently being conducted by the DEC.  However, this should not have an
impact on the Company as a result of the pending sale of its fossil generation
stations.

The Company spent approximately $0.1 million in capital expenditures in each of
the years 1996 and 1997, on projects at the fossil generation plants associated
with Phase I compliance.  The Company has included $0.6 million in its 1999
through 2000 construction forecast for Phase II compliance which will become
effective January 1, 2000.  For a discussion on the Company's plans to sell its
fossil and hydro assets, see Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - "Master
Restructuring Agreement and the POWERCHOICE Agreement."  For a discussion of the
Company's negotiations with DEC of a Consent Decree addressing past opacity
excursions and future opacity compliance issues, see Item 3. Legal Proceedings.

WATER.  The Company is required to comply with applicable federal and state
water quality requirements, including the Clean Water Act, in connection with
the discharge of condenser cooling water and other wastewaters from its
steam-electric generating stations and other facilities.  Wastewater discharge
permits have been issued by DEC for each of its steam-electric generating
stations.  These permits must be renewed every five years.  In addition,
hydroelectric facilities are required to obtain Clean Water Act certifications
as part of the FERC licensing/relicensing process.  Such certifications have
been issued or are pending for a substantial portion of the Company's
hydroelectric facilities.  Conditions of the permits typically require that
studies be performed to determine the effects of station operation on the
aquatic environment in the station vicinity and to evaluate various technologies
for mitigating losses of aquatic life.

LOW LEVEL RADIOACTIVE WASTE.  See Part II, Item 8. Financial Statements and
Supplementary Data - "Note 3. Nuclear Operations -Low Level Radioactive Waste."
<PAGE>

SOLID/HAZARDOUS WASTE.  The public utility industry typically utilizes and/or
generates in its operations a broad range of hazardous and potentially hazardous
wastes and by-products.  The Company believes it is handling identified wastes
and by-products in a manner consistent with federal, state and local
requirements and has implemented an environmental audit program to identify
potential areas of concern and pursue compliance with such requirements.  In
general, environmental laws can impose liability for the entire cost of site
remediation upon each of the parties that have sent waste to a contaminated site
regardless of fault or the lawfulness of the original disposal activity.  The
Company is also currently conducting a program to investigate and remediate, as
necessary to meet current environmental standards, certain properties associated
with former gas manufacturing and other properties which the Company has learned
may be contaminated with industrial waste.  The Company is also investigating
identified industrial waste sites as to which it may be determined that the
Company contributed.  The Company has also been advised that various federal,
state or local agencies believe certain properties require investigation and has
prioritized the sites based on available information in order to enhance the
management of investigation and remediation, if necessary.

The Company is currently aware of 136 sites with which it has been or may be
associated, including 82 which are Company-owned.  With respect to non-owned
sites, the Company may be required to contribute some proportionate share of
remedial costs.  Although one party can, as a matter of law, be held liable for
all of the remedial costs at a site, regardless of fault, in practice costs are
usually allocated among PRPs.  The Company has denied any responsibility at
certain of the PRP sites and is contesting liability accordingly.

Investigations at each of the Company-owned sites are designed to (1) determine
if environmental contamination problems exist, (2) if necessary, determine the
appropriate remedial actions and (3) where appropriate, identify other parties
who should bear some or all of the cost of remediation.  Legal action against
such other parties will be initiated where appropriate.  After site
investigations are completed, the Company expects to determine site-specific
remedial actions and to estimate the attendant costs for restoration.  However,
since investigations are ongoing for most sites, the estimated cost of remedial
action is subject to change.

Estimates of the cost of remediation and past-remedial monitoring are based
upon a variety of factors, including identified or potential contaminants,
location, size and use of the site; proximity to sensitive resources; status of
regulatory investigation and knowledge of activities and costs at similarly
situated sites.  Additionally, the Company's estimating process includes an
initiative where these factors are developed and reviewed using direct input and
support obtained from the DEC.  Actual Company expenditures are dependent upon
the total cost of investigation and remediation and the ultimate determination
of the Company's share of responsibility for such costs, as well as the
financial viability of other identified responsible parties since cleanup
obligations are joint and several.

As a consequence of site characterizations and assessments completed to date and
negotiations with PRPs, the Company has accrued a liability in the amount of
$220 million for these owned sites, representing its best current estimate for
its share of the costs for investigation and remediation.  The potential high
end of the range is presently estimated at approximately $710 million, including
approximately $340 million in the unlikely event the Company is required to
assume 100 percent responsibility at non-owned sites.  The amount accrued at
December 31, 1998, incorporates a method to estimate the liability for 22 of the
Company's largest sites, which relies upon a decision analysis approach.  This
method includes developing several remediation approaches for each of the 22
sites, using the factors previously described, and then assigning a probability
to each approach.  The probability represents the Company's best estimate of the
likelihood of the approach occurring using input received directly from the DEC.
The probable costs for each approach are then calculated to arrive at an
expected value.  While this approach calculates a range of outcomes for each
site, the Company has accrued the sum of the expected values for these sites.
The amount accrued for the Company's remaining sites is determined through
feasibility studies or engineering estimates, the Company's share of a PRP
allocation or, where no better estimate is available, the low end of a range of
possible outcomes is used.  In addition, the Company has recorded a regulatory
asset representing the remediation obligations to be recovered from ratepayers.
POWERCHOICE provides for the continued application of deferral accounting for
cost differences resulting from this effort.

In October 1997, the Company submitted a draft feasibility study to the DEC,
which included the Company's Harbor Point site and five surrounding non-owned
sites.  The study indicates a range of viable remedial approaches, however, a
final determination has not been made concerning the remedial approach to be
taken.  This range consists of a low end of $21 million and a high end of $360
million, with an expected value calculation of $56 million, which is included in
the total amounts accrued at December 31, 1998.  The range represents the total
costs to remediate the properties and does not consider contributions from other
PRPs, the amount of which the Company is unable to estimate.  The Company has
received comments from the DEC on the draft feasibility study, which will
facilitate completion of the feasibility study phase in the spring of 1999.  At
this time, the Company cannot definitively predict the nature of the DEC
proposed remedial action plan or the range of remediation costs the DEC will
require.  While the Company does not expect to be responsible for the entire
cost to remediate these properties, it is not possible at this time to determine
its share of the cost of remediation.

In May 1995, the Company filed a complaint, pursuant to applicable federal and
New York State law, in the U.S. District Court for the Northern District of New
York against several defendants seeking recovery of past and future costs
associated with the investigation and remediation of the Harbor Point and
surrounding sites.  The New York State Attorney General moved to dismiss the
Company's claims against the state of New York, the New York State Department of
Transportation and the Thruway Authority and Canal Corporation under the
Comprehensive Environmental Response, Compensation and Liability Act.  The
Company opposed this motion.  On April 3, 1998, the Court denied the New York
State Attorney General's motion as it pertains to the Thruway Authority and
Canal Corporation, and granted the motion relative to the state of New York and
the Department of Transportation.  On January 12, 1999, a pre-trial status
conference was convened by the Court.  The Court will be issuing an amended case
management order that is expected to call for the close of discovery by the end
of June 1999 and to establish December 1, 1999 as the trial ready date.  As a
result, the Company cannot predict the outcome of the pending litigation against
the defendants or the allocation of the Company's share of the costs to
remediate the Harbor Point and surrounding sites.

With respect to sites not owned by the Company, but for which the Company has
been or may be associated as a PRP, the Company has recorded a liability of $75
million, representing its best current estimate of its share of the total cost
to investigate and remediate these sites.  Total costs to investigate and
remediate all non-owned sites is estimated to be approximately $340 million, but
it is unlikely that the Company will be required to assume 100% of the
responsibility for these sites.  The Company has denied any responsibility for
certain of these PRP sites and is contesting liability accordingly.  Ten of the
PRP sites are included on the National Priorities List ("NPL").  The Company
estimates that its share of the liability for these eight sites is not material
and has included the amount in the determination of the amounts accrued.

Estimates of the Company's potential liability for sites not owned by the
Company, but for which the Company has been identified as an alleged PRP, have
been derived by estimating the total cost of site cleanup and then applying a
Company contribution factor to that estimate where appropriate.  Estimates of
the total cleanup costs are determined by using all available information from
investigations conducted by the Company and other parties, negotiations with
other PRPs and, where no other basis is available at the time of estimate, the
EPA figure for average cost to remediate a site listed on the NPL as disclosed
in the Federal Register of June 23, 1993 (58 Fed. Reg. 119).  A contribution
factor is calculated, when there is a reasonable basis for it, that uses either
a pro rata share based upon the total number of PRPs named or otherwise
identified, or the percentage agreed upon with other PRPs through steering
committee negotiations or by other means.  In some instances, the Company has
been unable to determine a contribution factor and has included in the amount
accrued the total estimated costs to remediate the sites.  Actual Company
expenditures for these sites are dependent upon the total cost of investigation
and remediation and the ultimate determination of the Company's share of
responsibility for such costs as well as the financial viability of other PRPs
since cleanup obligations are joint and several.

In May 1997, the DEC executed an Order on Consent (the "1997 Order") which
serves to keep the annual cash requirement for certain site investigation and
remediation ("SIR") level (at approximately $15 million per year), and which
provides for an annual site prioritization mechanism.  As executed, the 1997
Order expands the scope of the original 1992 Order, which covered 21 former MGP
sites, to encompass 52 sites with which the Company has been associated.  The
agreement is supported by the decision analysis approach, which the Company and
the DEC will continue to revise on an annual basis to address SIR progress and
site priorities relative to establishing the annual cost cap, as well as
determining the Company's liability for these sites.  The Saratoga Springs and
Harbor Point MGP sites are being investigated and remediated pursuant to
separate regulatory Consent Orders with the EPA and the DEC, respectively.
However, the annual costs associated with the remediation of these sites are
included in the cash requirements under the amended 1997 Order.

POWERCHOICE and the Company's gas settlement provide for the recovery of SIR
costs during the settlement periods.  The Company believes future costs, beyond
the settlement periods, will continue to be recovered in rates.  Based upon this
assessment, a regulatory asset has been recorded in the amount of $220 million,
representing the future recovery of remediation obligations accrued to date.  As
a result, the Company does not believe SIR costs will have a material adverse
effect on its results of operations or financial condition.  See also Part II,
Item 8. Financial Statements and Supplementary Data - "Note 2. Rate and
Regulatory Issues and Contingencies."

Where appropriate, the Company has provided notices of insurance claims to
carriers with respect to the investigation and remediation costs for
manufactured gas plant, industrial waste sites and sites for which the Company
has been identified as a PRP.  The Company has reached settlements with a number
of insurance carriers, resulting in payments to the Company of approximately $39
million, net of costs incurred in pursuing recoveries. This amount is being
amortized in rates generally over a 10-year period.

For a discussion of environmental legal proceedings, see Item 3. Legal
Proceedings.

<PAGE>

                            RESEARCH AND DEVELOPMENT
                            ------------------------

The Company maintains a research and development ("R&D") program aimed at
improving the delivery and use of energy products and finding practical
applications for new and existing technologies in the energy business.  These
efforts include (1) improving efficiency; (2) minimizing environmental impacts;
(3) improving facility availability; (4) minimizing maintenance costs; (5)
promoting economic development and (6) improving the quality of life for the
Company's customers with new electric and gas technologies.  R&D expenditures
in 1996 through 1998 were not material to the Company's results of operations
or financial condition.

                              CONSTRUCTION PROGRAM
                              --------------------

See Part II, Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - "Financial Position, Liquidity and Capital Resources
- Construction and Other Capital Requirements" and Part II, Item 8. Financial
Statements and Supplementary Data - "Note 9. Commitments and Contingencies -
Construction Program."

                                    INSURANCE
                                    ---------

As of January 31, 1999, the Company's directors and officers liability insurance
was renewed.  This coverage includes nuclear operations and insures the
directors and officers against obligations incurred as a result of their
indemnification by the Company.  The coverage also insures the directors and
officers against liabilities for which they may not be indemnified by the
Company, except for a dishonest act or breach of trust.  In addition, the policy
covers all of the Company's subsidiaries.  For a discussion of nuclear
insurance, see Part II, Item 8. Financial Statements and Supplementary Data -
"Note 3. Nuclear Operations - Nuclear Liability Insurance" and - "Nuclear
Property Insurance."

                                EMPLOYEE RELATIONS
                                ------------------

The Company's work force at December 31, 1998 numbered approximately 8,400, of
whom approximately 69% were union members.  It is estimated that approximately
80% of the Company's total labor costs is applicable to operation and
maintenance and approximately 20% is applicable to construction and other
accounts.

All of the Company's non-supervisory production and clerical workers subject to
collective bargaining are represented by the International Brotherhood of
Electrical Workers ("IBEW"). In April 1996, the Company and the IBEW agreed on a
five-year, three-month labor agreement, which provides for wage increases of
approximately 2% to 3% in each of the subsequent four years.

The Company has reached agreements to sell its 72 hydro generation stations and
its two coal-fired generating stations, which employ approximately 550
individuals.  In addition, the Company is pursuing the sale of its two oil and
gas-fired stations, which employ approximately 150 individuals.  The Company
has also announced its intent to pursue a sale of its nuclear assets, which
employ approximately 1,300 individuals.

                                   SEASONALITY
                                   -----------

See Item 2. Properties - "Electric Service" and Part II, Item 8. Financial
Statements and Supplementary Data - "Note 13. Quarterly Financial Data
(Unaudited)."

<PAGE>

ITEM 2.  PROPERTIES

                                ELECTRIC SERVICE
                                ----------------

As of December 31, 1998, the Company owned and operated four fossil-fuel steam
plants (as well as having a 25% interest in the Roseton Steam Station and its
output), two nuclear fuel steam plants, and 72 hydroelectric plants, and had a
majority interest in Beebee Island and Feeder Dam hydro plants and their output.
See Part II, Item 7.  Management's Discussion and Analysis of Financial
Condition and Results of Operations - Master Restructuring Agreement and the
POWERCHOICE Agreement," for a discussion of the ongoing sale of the Company's
generation assets.  The Company also purchases substantially all of the output
of 93 other hydroelectric facilities.  The Company's wholly owned subsidiary,
Opinac North America, Inc., owns Opinac Energy Corporation and Niagara Mohawk
Energy, Inc.  Opinac Energy Corporation has a 50 percent interest in CNP
(owner and operator of the 76.8 MW Rankine hydroelectric plant) which
distributes electric power within the province of Ontario and owns a windmill
generator in the province of Alberta.  In addition, the Company has contracts
to purchase electric energy from NYPA and other sources. See Item 1. Business
- "IPPs," - "New York Power Authority" and - "Other Purchased Power" and
Part II, Item 8. Financial Statements and Supplementary Data - "Note 9.
Commitments and Contingencies - Long-term Contracts for the Purchase of
Electric Power" and - "Electric and Gas Statistics."  The Company holds the
FERC license for 65 hydroelectric plants.  Several of these licenses have been
involved in re-licensing since the early  1990's and are expected to take
several more years to conclude.  As of December 31, 1998, the Company has
renewed 3 hydro licenses and has 12 license renewals pending.  The hydro
licenses and the pending license applications will be transferred to the new
owner of the hydro assets, who will be required to comply with current
conditions and negotiated agreements in place at the time of closing.

The following is a list of the Company's major operating generating stations at
December 31, 1998, all of which are for sale:

<TABLE>
<CAPTION>

                                                                                     Company's
                                                                                      Share of
                                                                                    Nominal Net
                                                 Percent                            Capability
  Station                      Location         Ownership     Energy Source            in MW
--------------------------  -------------       ---------   ----------------        ----------- 
<S>                         <C>                       <C>   <C>                         <C>
  Huntley. . . . . . . . .  Niagara River             100%  Coal                        760
  Dunkirk. . . . . . . . .  Lake Erie                 100%  Coal                        600
  Albany . . . . . . . . .  Hudson River              100%  Oil/Natural Gas             400
* Oswego (Unit 5)  . . . .  Lake Ontario              100%  Oil                         850
  Oswego (Unit 6). . . . .  Lake Ontario               76%  Oil/Natural Gas             646
  Roseton. . . . . . . . .  Hudson River               25%  Oil/Natural Gas             300
  Nine Mile Point (Unit 1)  Lake Ontario              100%  Nuclear                     613
  Nine Mile Point (Unit 2)  Lake Ontario               41%  Nuclear                     469

</TABLE>

*     Oswego Unit 5 was returned to service in June 1998 after being put into
      long-term cold standby in 1994.

On November 30, 1998, the Company filed an application with the New York State
Board on Electric Generation Siting and the Environment to install
state-of-the-art technology at the Albany Steam Station, to redevelop the
facility, to increase the capacity from the current 400 MW to 723 MW and to
rename the station the Bethlehem Energy Center.  The new facility would use
natural gas fueled combined cycle units which would reduce air emissions and
significantly improve the facility's operating efficiency.  The licensing
effort and permitting process is expected to take up to 14 months and be
transferable to a new owner of the facility under the fossil asset sale.

The electric system of the Company and CNP is directly interconnected with
other electric utility systems in Ontario, Quebec, New York, Massachusetts,
Vermont and Pennsylvania, and indirectly interconnected with most of the
electric utility systems through the Eastern Interconnection of the United
States.  As of December 31, 1998, the Company's electric transmission and
distribution systems were composed of 952 substations with a rated transformer
capacity of approximately 28,500,000 kilovoltamperes, approximately 8,000
circuit miles of overhead transmission lines, approximately 1,100 cable miles of
underground transmission lines, approximately 113,100 conductor miles of
overhead distribution lines and about 5,800 cable miles of underground
distribution cables, only a part of such transmission and distribution lines
being located on property owned by the Company.

There is seasonal variation in electric customer load.  In 1998, the Company's
maximum hourly demand occurred in the summer.  Historically, the Company's
maximum hourly demand has occurred in the winter.  The maximum simultaneous
hourly demand (excluding economy and emergency sales to other utilities) on the
electric system of the Company for the twelve months ended December 31, 1998
occurred on July 16, 1998 and was 5,928 KWh.  For a summary of the Company's
electric supply capability at December 31, 1998, see Part II, Item 8. Financial
Statements and Supplementary Data -"Electric and Gas Statistics."

                                   LAND CLAIMS
                                   -----------

The Company owns and operates several electric transmission lines crossing the
Seneca Nation Cattaraugus and Allegany Reservations, which range from 230
kilovolts to 34.5 kilovolts.  In 1991, the Seneca Nation opened discussions
alleging the invalidity of the right-of-way agreements for these transmission
lines.  While discussions between the Nation and the Company were suspended in
mid-1992, in 1997, the Nation asked the Company to reopen the discussions.  On
September 30, 1998, the Nation filed, in the U.S. District Court for the Western
District of New York, a civil action to eject the Company from the Nation's land
and is also seeking financial relief from the Company.  The Company is unable to
predict the outcome of this matter.

The Company has also held discussions with other Native American nations and was
involved in legal proceedings regarding the PSC's jurisdiction over their
territories, the Company's right to provide service to individuals located
within these territories, the validity of franchise agreements within their
territories, and the Company's right to collect stranded costs.  The potential
outcome of these discussions could lead to, but is not limited to, more
formalized litigation proceedings.  The Company intends to continue these
discussions and defend its position, but is unable to predict the timing or
outcome of these matters.

                               NEW YORK POWER POOL
                               -------------------

The Company, six other New York utilities and NYPA constitute the NYPP, through
which they coordinate the planning and operation of their interconnected
electric production and transmission facilities in order to improve reliability
of service and efficiency for the benefit of customers of their respective
electric systems.  For a discussion on changes to NYPP, see Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - "Master Restructuring Agreement and the POWERCHOICE Agreement" and
- "FERC Rulemaking on Open Access and Stranded Cost Recovery."

                                   GAS SERVICE
                                   -----------

The Company distributes gas purchased from suppliers and transports gas owned by
others.  As of December 31, 1998, the Company's natural gas system was comprised
of approximately 9,100 miles of pipelines and mains, only a part of which is
located on property owned by the Company.
                                   SUBSIDIARIES
                                   ------------

The Company's subsidiaries are as follows:

1.  Opinac North America, Inc. - owns:

    a.  Opinac Energy Corporation - a Canadian corporation which has portfolio
        investments and owns a 50 percent interest in CNP.  CNP is an electric
        company, which has operations in the province of Ontario, Canada.
        CNP generates electricity at its Rankine hydro plant for the wholesale
        market and for its distribution system in Fort Erie, Ontario.  CNP
        through subsidiary companies, owns and operates a wind power facility
        in the province of Alberta, Canada.
    b.  Niagara Mohawk Energy, Inc. - was incorporated in the state of Delaware
        and is an unregulated company that offers energy-related services.

2.  NM Uranium, Inc. - has an interest in a uranium mining operation in Live
    Oak County, Texas, which is now in the process of reclamation and
    restoration.

3.  NM Properties, Inc. (formerly NM Holdings, Inc.) - engages in real estate
    development of property formally owned by the Company.

4.  NM Receivables - facilitates the sale of an undivided interest in a
    designated pool of customer receivables, including accrued unbilled
    revenues.  NM Receivables LLC is owned by the Company (over 99.99%)
    and by NM Receivables Corp. II, which is a wholly owned subsidiary
    of the Company.

5.  Moreau Manufacturing Corporation - the Company owns a 66.67% interest in
    a New York State subsidiary that owns and operates a hydroelectric
    generating station.  The Company has included its interest in Moreau
    in its hydro generating asset sale.

6.  Beebee Island Corporation - the Company owns 82.84% interest in a New
    York State subsidiary that owns and operates a hydroelectric generating
    station.  The Company has included its interest in Beebee Island in its
    hydro generating asset sale.

                                 MORTGAGE LIENS
                                 --------------

Substantially all of the Company's operating properties are subject to a
mortgage lien securing its mortgage debt.  See Part II, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
"Master Restructuring Agreement and the POWERCHOICE Agreement."

<PAGE>

ITEM 3.  LEGAL PROCEEDINGS

For a detailed discussion of additional legal proceedings, see Part II, Item 8.
Financial Statements and Supplementary Data -"Note 9. Commitments and
Contingencies - Tax Assessments" and -"Environmental Contingencies."  See also
Item 1. Business -"Environmental Matters - Solid/Hazardous Waste," Item 2.
Properties - "Land Claims," and Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - "Master
Restructuring Agreement and the POWERCHOICE Agreement."  The Company is unable
to predict the ultimate disposition of the matters referred to below.  In
addition, consistent with POWERCHOICE and its gas settlement agreement, the
Company believes that it is probable that the Company will continue to recover
these types of expenditures in cost-of-service based rates. See also Part II,
Item 8. Financial Statements and Supplementary Data - "Note 2. Rate and
Regulatory Issues and Contingencies."

1.  On June 22, 1993, the Company and twenty other industrial entities, as
    well as the owner/operator of the Pfohl Brothers Landfill near Buffalo, New
    York, were sued in NYS Supreme Court, Erie County, by a group of residents
    living in the area surrounding the landfill.  The plaintiffs seek 
    compensation for alleged economic loss and property damage claimed to have
    resulted from exposure to contamination associated with the landfill.  In
    addition, since January 18, 1995, the Company has been named as a defendant
    or third party defendant in a series of toxic tort actions filed in federal
    or state courts in the Buffalo area.  These actions allege exposure on the
    part of plaintiffs or plaintiffs' decedents to toxic chemicals emanated
    from the landfill, resulting in the alleged causation of property damage
    and/or physical injury.  The plaintiffs seek compensatory and punitive
    damages so far totaling approximately $60 million.  The Company has filed
    answers responding to the claims put forth in these suits, denying liability
    as to any of the claimed conditions or damages, and intends to continue to
    vigorously defend against each claim.

    The Company is unable to predict at this time the probable outcome of these
    proceedings, which at present remain in the discovery stage.  The Company,
    through membership in the Pfohl Brothers landfill Site Committee, is
    participating in the design and implementation of a remedial program for the
    landfill.  In the context of remedial cost allocation procedures conducted
    on behalf of the Committee, it has been determined that the Company's
    contribution of industrial wastes to the landfill was minor.  Further, it is
    the Company's position that materials present at the landfill attributable
    to the Company are not causally related to any condition alleged by
    plaintiffs in the various lawsuits associated with the landfill.  The
    Company does not believe that the outcome of these proceedings will have a
    material adverse effect on its results of operations or financial condition.

2.  On February 4, 1994, the Company notified NorCon Partners, LP (NorCon) of
    the Company's demand for adequate assurance that NorCon would perform all of
    their future repayment obligations as required by agreement.

    On March 7, 1994, NorCon filed a complaint in the U.S. District Court
    seeking to enjoin the Company from terminating a PPA between the parties and
    seeking a declaratory judgment that the Company has no right to demand
    additional security or other assurances of NorCon's future performance under
    the PPA.  NorCon sought a temporary restraining order against the Company to
    prevent the Company from taking any action on its February 4, 1994 letter.
    On March 14, 1994, the Court entered the interim relief sought by NorCon.
    On April 4, 1994, the Company filed its answer and counterclaim for
    declaratory judgment relating to the Company's exercise of its right to
    demand adequate assurance.  On November 2, 1994, NorCon filed for summary
    judgment.  On February 6, 1996, the U.S. District Court granted NorCon's
    motion for summary judgment and ruled that under New York Law, the Company
    did not have the right to demand adequate assurances of future performance.
    On March 26, 1997, the U.S. Court of Appeals for the Second Circuit ordered
    that the question of whether there exists under New York commercial law the 
    right to demand firm security on an electric contract should be certified to
    the New York Court of Appeals, the highest New York court, for final
    resolution.  The Second Circuit order effectively stayed the U.S. District
    Court's order against the Company, pending final disposition by the New York
    Court of Appeals.  A motion to stay further proceedings was made since this
    contract was included in the MRA.

    NorCon subsequently dropped out of the MRA and arguments were held on
    October 22, 1998 in the New York Court of Appeals at the request of the
    Company.  On December 1, 1998, the New York Court of Appeals ruled in favor
    of the Company's right to demand adequate assurance of future performance
    on an electric contract.  Resolution of the remaining issues will be
    determined in the U.S. District Court for the Southern District of New York.
    The Company is unable to predict the timing and outcome of this matter.

3.  In November 1993, Fourth Branch Associates Mechanicville ("Fourth Branch")
    filed an action against the Company and several of its officers and
    employees in the NYS Supreme Court, seeking compensatory damages of $50
    million, punitive damages of $100 million and injunctive and other related
    relief.  The lawsuit grows out of the Company's termination of a contract
    for Fourth Branch to operate and maintain a hydroelectric plant the Company
    owns in the Town of Halfmoon, New York. Fourth Branch's complaint also
    alleges claims based on the inability of Fourth Branch and the Company to 
    agree on terms for the purchase of power from a new facility that Fourth
    Branch hoped to construct at the Mechanicville site.  In January 1994, the
    Company filed a motion to dismiss Fourth Branch's complaint.  By order 
    dated November 7, 1995, the Court granted the Company's motion to dismiss
    the complaint in its entirety. Fourth Branch filed an appeal from the 
    Court's order.  On January 30, 1997, the Appellate Division modified the
    November 7, 1995 court decision by reversing the dismissal of the fourth and
    fifth causes of action set forth in Fourth Branch's complaint.

    The Company and Fourth Branch had also entered into negotiations under a
    FERC mediation process.  As a result of these negotiations, the Company had
    proposed to sell the hydroelectric plant to Fourth Branch for an amount
    which would not be material. In addition, the proposal included a provision
    that would require the discontinuance of all litigation between the parties.

    Attempts to implement this proposal have been unsuccessful, and the Company
    informed FERC that its participation in the mediation efforts has been
    concluded.  On January 14, 1997, the FERC Administrative Law Judge issued a
    report to FERC recommending that the mediation proceeding be terminated,
    leaving outstanding a Fourth Branch complaint to FERC that alleges anti-
    competitive conduct by the Company.  The Company has made a motion to
    dismiss Fourth Branch's antitrust complaint before the FERC, which motion
    was opposed by Fourth Branch.  A decision from FERC on this matter is
    pending.

    During July 1998, Fourth Branch commenced a condemnation proceeding in
    Federal District Court to obtain title to the project property and also has
    made a unilateral offer of settlement before FERC.  The Company has served
    an answer with various affirmative defenses.  On July 30, 1998, Fourth 
    Branch moved for Summary Judgment.  The Company opposed Fourth Branch's
    motion and cross-moved for summary judgment in favor of the Company.

    The Company is unable to predict the ultimate disposition of the lawsuit
    referred to above.  However, the Company believes it has meritorious
    defenses and intends to defend this lawsuit vigorously.  No provision for
    liability, if any, that may result from this lawsuit has been made in the
    Company's financial statements.

4.  In March 1993, Inter-Power of New York, Inc. ("Inter-Power") filed a
    complaint against the Company and certain of its officers and employees 
    in the NYS Supreme Court.  Inter-Power alleged, among other matters, fraud,
    negligent misrepresentation and breach of contract in connection with the
    Company's alleged termination of a PPA in January 1993.  The plaintiff 
    sought enforcement of the original contract or compensatory and punitive
    damages in an aggregate amount that would not exceed $1 billion, excluding
    pre-judgment interest.

    In early 1994, the NYS Supreme Court dismissed two of the plaintiff's 
    claims; this dismissal was upheld by the Appellate Division, Third
    Department of the NYS Supreme Court.  Subsequently, the NYS Supreme Court
    granted the Company's motion for summary judgment on the remaining causes
    of action in Inter-Power's complaint.  In August 1994, Inter-Power appealed
    this decision and on July 27, 1995, the Appellate Division, Third Department
    affirmed the granting of summary judgment as to all counts, except for one
    dealing with an alleged breach of the PPA relating to the Company's having
    declared the agreement null and void on the grounds that Inter-Power had
    failed to provide it with information regarding its fuel supply in a timely
    fashion.  This one breach of contract claim was remanded to the NYS Supreme
    Court for further consideration.  In January 1998, the NYS Supreme Court
    granted the Company's motion for summary judgment on all remaining claims
    in this lawsuit and dismissed this lawsuit in its entirety.  In January
    1998, Inter-Power filed a notice of appeal and perfected the appeal in
    October 1998.  The appeal was argued before the Appellate Division, Third
    Department, on January 15, 1999.  The Company is unable to predict the
    outcome of this matter.

5.  The DEC, in response to an EPA audit of their enforcement policies,
    which found enforcement of air regulation violations to be insufficient,
    began an initiative to address this issue in 1997.  As a result, the DEC
    began to pursue consent orders from all New York utilities for past opacity
    variances for the years 1994, 1995 and 1996.  The consent order also 
    includes various opacity reduction measures and stipulated penalties for
    future excursions after execution of a consent order.  The Company is in
    the process of negotiating a mutually agreeable consent order.  Based upon
    current negotiations of the consent order, the Company believes that the
    penalties for past opacity variances would be immaterial to the Company's
    results of operations.  In addition, the stipulated penalties for future
    excursions will be reduced subject to the Company's sale of its fossil
    generation assets.  The outcome of this matter is uncertain at this time.

6.  In July 1998, the Public Utility Law Project of New York, Inc. (PULP)
    and others sought a declaratory judgment, declaring the Company's 
    POWERCHOICE agreement unlawful, null and void and injunctive relief in the
    Supreme Court of the state of New York, Albany County against the PSC and
    the Company to enjoin the defendants to halt all their actions and
    expenditures to implement the rules for the provision of retail energy 
    services contained in the POWERCHOICE agreement.  The PSC and the Company
    have filed a motion seeking to dismiss this action.  The motion is pending
    in Albany County Supreme Court.  The Company is unable to predict the
    outcome of this matter.

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

No matters were submitted to a vote of security holders during the fourth
quarter of 1998.

<PAGE>

                         EXECUTIVE OFFCERS OF REGISTRANT
                         -------------------------------
All executive officers of the Company are elected on an annual basis at the
Organizational meeting of the Board of Directors or upon the filling of a
vacancy.  There are no family relationships between any of the executive
officers.  There are no arrangements or understandings between any of the
officers listed below and any other person pursuant to which he or she was
selected as an officer.

<TABLE>
<CAPTION>
                        Age at
Executive             12-31-1998   Current and Prior Positions                                   Date Commenced
---------             ----------   ---------------------------                                   --------------
<S>                       <C>      <C>                                                           <C>
William E. Davis . . . . .56       Chairman of the Board and Chief Executive Officer             May 1993

Albert J. Budney Jr.. .   51       President                                                     April 1995
                                   Corporate Managing Vice President - UtiliCorp Power           Prior to joining
                                    Services Group (a Unit of UtiliCorp United, Inc.)            the Company
                                   President-Missouri Public Service (Operating                  January 1993
                                    Division of UtiliCorp United, Inc.)

Darlene D. Kerr. .. . .   47       Executive Vice President - Energy Delivery                    September 1998
                                   Senior Vice President - Energy Distribution                   December 1995
                                   Senior Vice President - Electric Customer Service             January 1994
                                   Vice President - Electric Customer Service                    July 1993

B. Ralph Sylvia. . .. ..  58       Retired                                                       July 1998
                                   Executive Vice President                                      January 1998
                                   Executive Vice President - Electric Generation                December 1995
                                    and Chief Nuclear Officer
                                   Executive Vice President - Nuclear                            November 1990

David J. Arrington  .  .  47       Senior Vice President - Human Resources                       December 1990

Thomas H. Baron. . ..  .  54       Senior Vice President - Field Operations                      October 1998
                                   Vice President - Fossil/Hydro Generation and                  April 1998
                                    and Environmental Affairs
                                   Vice President - Fossil & Hydro Generation                    May 1991

Edward J. Dienst  . .. .  43       Senior Vice President - Customer Delivery & Asset Management  October 1998
                                   Vice President Electric Delivery                              May 1996
                                   Vice President Regional Operations                            April 1994
                                   General Manager - Northeast Region                            April 1991

William F. Edwards . . .  41       Senior Vice President and Chief Financial Officer             September 1997
                                   Vice President of Financial Planning                          December 1995
                                   Executive Assistant of the Chief Executive Officer            July 1993
                                    and President

Gary J. Lavine .  . . ..  48       Senior Vice President - Legal & Corporate Relations           October 1990

John H. Mueller. . ..  .  52       Senior Vice President and Chief Nuclear Officer               January 1998
                                   Site Vice President of Commonwealth Edison's                  August 1996
                                    Zion Plant
                                   Vice President of Nuclear Energy (for Nebraska                July 1994
                                   Public Power District, owner and operator of the
                                    Cooper nuclear plant)
                                   Plant Manager - Unit 2                                        August 1993

Theresa A. Flaim . .. .   49       Vice President - Corporate Strategic Planning                 May 1994
                                   Vice President - Corporate Planning                           April 1993

Kapua A. Rice. .  . .. .  47       Corporate Secretary                                           September 1994
                                   Assistant Secretary                                           October 1992

Steven W. Tasker .  . .   41       Vice President - Controller                                   December 1993

</TABLE>
<PAGE>

                                       PART II

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

The Company's common stock and certain of its preferred series are listed on the
New York Stock Exchange ("NYSE").  The common stock is also traded on the
Boston, Cincinnati, Midwest, Pacific and Philadelphia stock exchanges.  Common
stock options are traded on the American Stock Exchange.  The ticker symbol is
"NMK."

Preferred dividends were paid on March 31, June 30, September 30, and December
31.  During the second quarter of 1998, the Company consummated the MRA
agreement.  As part of the MRA agreement, the Company made a significant payment
to the IPP Parties that resulted in a substantial tax net operating loss.  (See
Part II, Item 7.  Management's Discussion and Analysis of Financial Condition
and Results on Operations - "Master Restructuring Agreement and the POWERCHOICE
Agreement," and "Financial Position, Liquidity and Capital Resources").  As a
result of this tax net operating loss, dividends paid in the second, third and
fourth quarters of 1998 will constitute a return of capital and only the first
quarter dividends are taxable as ordinary income.

The table below shows quoted market prices (NYSE) for the Company's common
stock:

<TABLE>
<CAPTION>

                      1998               1997
                    --------           ---------
                HIGH       LOW       High      Low
             --------- --------   --------- --------
<S>          <C>       <C>        <C>       <C>
1st Quarter  $13 9/16  $  10 1/8  $ 11 1/8  $ 8 1/8
2nd Quarter    15 1/4         11         9    7 7/8
3rd Quarter    16 3/8     14 3/4   10 1/16    8 1/4
4th Quarter    16 1/2   13 15/16   10 9/16   9 1/16

</TABLE>

For a discussion regarding the common stock dividend, see Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
"Financial Position, Liquidity and Capital Resources - Common Stock Dividend"
below.

OTHER COMPANY STOCKHOLDER MATTERS.  The holders of common stock are entitled to
one vote per share and may not cumulate their votes for the election of
Directors.  Whenever dividends on preferred stock are in default in an amount
equivalent to four full quarterly dividends and thereafter until all dividends
thereon are paid or declared and set aside for payment, the holders of such
preferred stock can elect a majority of the Board of Directors.  Whenever
dividends on any preference stock are in default in an amount equivalent to six
full quarterly dividends and thereafter until all dividends thereon are paid or
declared and set aside for payment, the holders of such stock can elect two
members to the Board of Directors.  No dividends on preferred stock are now in
arrears and no preference stock is now outstanding.  Upon any dissolution,
liquidation or winding up of the Company's business, the holders of common stock
are entitled to receive a pro rata share of all of the Company's assets
remaining and available for distribution after the full amounts to which holders
of preferred and preference stock are entitled have been satisfied.
At the Company's annual meeting on June 29, 1998, the shareholders approved an
amendment to the Company's certificate of incorporation to increase the number
of authorized shares of common stock to 250 million from 185 million.

After the closing of the MRA (see Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - "Master
Restructuring Agreement and the POWERCHOICE Agreement"), IPP Parties and their
designees owned approximately 20.5 million shares of the Company's common stock,
representing approximately 11% of the Company's voting securities.  Pursuant to
the MRA, any IPP Party that received 2% or more of the outstanding common stock
and any designee of IPP Parties that received more than 4.9% of the outstanding
common stock upon the consummation of the MRA, together with certain but not all
affiliates (collectively, "2% Shareholders"), entered into certain shareholder
agreements (the "Shareholders Agreements").  Pursuant to each Shareholder
Agreement, the 2% Shareholders agree that for five years from the consummation
of the MRA, they will not acquire more than an additional 5% of the outstanding
common stock (resulting in ownership in all cases of no more than 9.9%) or take
any actions to attempt to acquire control of the Company, other than certain
permitted actions in response to unsolicited actions by third parties.  The 2%
Shareholders generally vote their shares on a "pass-through" basis, in the same
proportion as all shares held by other shareholders are voted, except that they
may vote in their discretion (i) for extraordinary transactions and (ii) for
directors when there is a pending proposal to acquire the Company.

The indenture securing the Company's mortgage debt provides that retained
earnings shall be reserved and held unavailable for the payment of dividends on
common stock to the extent that expenditures for maintenance and repairs plus
provisions for depreciation do not exceed 2.25% of depreciable property as
defined therein.  Such provisions have never resulted in a restriction of the
Company's retained earnings.  This provision will continue to apply to the
regulated company under the holding company structure.  See "Formation of
Holding Company" as discussed below.

As of January 1, 1999, there were approximately 60,000 holders of record of
common stock of the Company and about 4,300 holders of record of preferred
stock.  The chart below summarizes common stockholder ownership by size of
holding:

<TABLE>
<CAPTION>

Size of Holding           Total         Total
    (Shares)          Stockholders   Shares Held
----------------      ------------   -----------
<S>                     <C>          <C>
1 to 99. . . . .        29,576           761,377
100 to 999 . . .        27,862         6,701,542
1,000 or more. .         2,601       179,901,944
                        ------       -----------
                        60,039       187,364,863
                        ======       ===========

</TABLE>
FORMATION OF HOLDING COMPANY.  The POWERCHOICE agreement allows the Company to
form a holding company, which the Company's shareholders approved at its 1998
annual meeting.  The Company also received approval from the FERC, PSC and NRC,
and is awaiting further approval from the Securities and Exchange Commission.
Once all approvals are received, a share exchange will occur whereby holders of
shares of the Company's common stock will automatically become holders of common
stock of Niagara Mohawk Holdings, Inc. ("Holdings") on the basis of one share of
common stock for one share of Holdings common stock.  The Company's preferred
stock will not be exchanged as part of the share exchange but will continue as
shares of the Company's preferred stock.  Holdings is authorized to issue
50,000,000 shares of its own preferred stock.  The share exchange and the
holding company structure will not change the rights of holders of the
outstanding shares of the Company's preferred stock.  The Company's preferred
stock will continue to rank senior to the Company's common stock (which will be
held by Holdings) as to dividends and as to distribution of the Company's assets
upon any liquidation.

As a result of the share exchange:

-     Holdings will become a holding company owned by the former common
      shareholders of the Company
-     Holdings will become the sole owner of the Company's common stock
-     The Company's obligations with respect to its long-term debt, First
      Mortgage Bonds and preferred stock will remain with the Company and not
      be transferred to Holdings
-     The Company will continue to carry on its regulated utility business as a
      subsidiary of Holdings and the Company's non-regulated subsidiaries will
      be owned as a separate subsidiary of Holdings.  The Company will retain
      all other subsidiaries.
-     The par value per share of Holdings common stock will be $0.01

No income tax gain or loss will be recognized by a holder of the Company's
common stock as a result of share exchange solely for Holdings common stock
under IRS Code Section 351.  The tax basis of the Holdings common stock received
in the share exchange will be the same as the exchanging shareholder's basis in
the Company's common stock.  In addition, no income tax gain or loss will be
recognized by the Company or Holdings.

<PAGE>

ITEM 6.  SELECTED CONSOLIDATED FINANCIAL DATA

The following table sets forth selected financial information of the Company for
each of the five years during the period ended December 31, 1998, which has been
derived from the audited financial statements of the Company, and should be read
in connection therewith.  As discussed in Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations and Item 8. Financial
Statements and Supplementary Data - "Notes to Consolidated Financial
Statements," the following selected financial data is not likely to be
indicative of the Company's future financial condition or results of operations.

<TABLE>
<CAPTION>

                                       1998         1997         1996*        1995         1994
                                   ------------  -----------  -----------  -----------  -----------
<S>                                <C>           <C>          <C>          <C>          <C>
OPERATIONS:  (000'S)
Operating revenues. . . . . . . .  $ 3,826,373   $3,966,404   $3,990,653   $3,917,338   $4,152,178 

Net income (loss) . . . . . . . .     (120,825)     183,335      110,390      248,036      176,984 
---------------------------------  ------------  -----------  -----------  -----------  -----------
COMMON STOCK DATA:
Book value per share at year end.  $     16.92   $    18.89   $    17.91   $    17.42   $    17.06 

Market price  at year end . . . .       16 1/8       10 1/2        9 7/8        9 1/2       14 1/4 

Ratio of market price to
   book value at year end . . . .         95.3%        55.6%        55.1%        54.5%        83.5%

Dividend yield at year end. . . .            -            -            -         11.8%         7.9%

Basic and diluted earnings per
   average common share . . . . .       ($0.95)  $     1.01   $     0.50   $     1.44   $     1.00 

Rate of return on common equity .        (5.3)%         5.5%         2.8%         8.4%         5.8%

Dividends paid per common share .            -            -            -   $     1.12   $     1.09 

Dividend payout ratio . . . . . .            -            -            -         77.8%       109.0%
---------------------------------  ------------  -----------  -----------  -----------  -----------
CAPITALIZATION: (000'S)
Common equity . . . . . . . . . .  $ 3,170,142   $2,727,527   $2,585,572   $2,513,952   $2,462,398 

Non-redeemable preferred stock. .      440,000      440,000      440,000      440,000      440,000 

Mandatorily redeemable
   preferred stock. . . . . . . .       68,990       76,610       86,730       96,850      106,000 

Long-term debt. . . . . . . . . .    6,417,225    3,417,381    3,477,879    3,582,414    3,297,874 
---------------------------------  ------------  -----------  -----------  -----------  -----------
     Total. . . . . . . . . . . .   10,096,357    6,661,518    6,590,181    6,633,216    6,306,272 
Long-term debt maturing
   within one year. . . . . . . .      312,240       67,095       48,084       65,064       77,971 
---------------------------------  ------------  -----------  -----------  -----------  -----------
     Total. . . . . . . . . . . .  $10,408,597   $6,728,613   $6,638,265   $6,698,280   $6,384,243 
---------------------------------  ------------  -----------  -----------  -----------  -----------
Capitalization ratios:  (including long-term debt maturing within one year)
Common stock equity . . . . . . .         30.5%        40.5%        39.0%        37.5%        38.6%
Preferred stock . . . . . . . . .          4.9          7.7          7.9          8.0          8.5 
Long-term debt. . . . . . . . . .         64.6         51.8         53.1         54.5         52.9 

</TABLE>

*Amounts include extraordinary item, see Note 2. Rate and Regulatory Issues and
Contingencies

<PAGE>

<TABLE>
<CAPTION>

                                              1998          1997         1996*          1995          1994
                                          ------------  ------------  ------------  ------------  ------------
<S>                                       <C>           <C>           <C>           <C>           <C>
FINANCIAL RATIOS:
EBITDA   (000's)). . . . . . . . . . . .  $     990.5   $     961.5   $     957.5   $     929.1   $   1,029.9 

Net cash interest   (000's). . . . . . .  $     345.5   $     226.9   $     244.5   $     260.5   $     261.7 

Ratio of EBITDA to net cash
     interest. . . . . . . . . . . . . .          2.9           4.2           3.9           3.6           3.9 

Ratio of earnings to fixed charges . . .         0.57          2.02          1.57          2.29          1.91 

Ratio of earnings to fixed charges
   and preferred stock dividends . . . .         0.52          1.67          1.31          1.90          1.63 

Other ratios (% of operating revenues):

   Fuel, electricity purchased and
      and gas purchased. . . . . . . . .         39.6%         44.4%         43.5%         40.3%         39.6%

   Other operation and maintenance
      expenses . . . . . . . . . . . . .         24.5          21.1          23.3          20.9          23.1 

   Depreciation and amortization . . . .          9.3           8.6           8.3           8.1           7.4 

   Amortization of the MRA
      regulatory asset . . . . . . . . .          3.4             -             -             -             - 

   Federal and foreign income taxes,
      and other taxes. . . . . . . . . .         10.3          15.1          13.6          17.3          14.7 

   Operating income. . . . . . . . . . .          4.4          14.1          13.1          17.5          13.3 

   Balance available for common
      stock. . . . . . . . . . . . . . .         (4.1)          3.7           1.8           5.3           3.5 

MISCELLANEOUS: (000'S)
Gross additions to utility plant . . . .  $   392,200   $   290,757   $   352,049   $   345,804   $   490,124 

Total utility plant. . . . . . . . . . .   11,431,447    11,075,874    10,839,341    10,649,301    10,485,339 

Accumulated depreciation
   and amortization. . . . . . . . . . .    4,553,448     4,207,830     3,881,726     3,641,448     3,449,696 

Total assets . . . . . . . . . . . . . .   13,861,187     9,584,141     9,427,635     9,477,869     9,649,816 

</TABLE>

*Amounts include extraordinary item, see Note 2. Rate and Regulatory Issues and
 Contingencies

<PAGE>

                        NIAGARA MOHAWK POWER CORPORATION

Certain statements included in this Annual Report on Form 10-K are
forward-looking statements as defined in Section 21E of the Securities
Exchange Act of 1934 that involve risk and uncertainty, including the
improvement in the Company's cash flow upon the implementation of the MRA and
POWERCHOICE, the timing and outcome of the future sale of the Company's fossil,
hydro and nuclear generation assets, and the costs and potential recoveries
associated with the January 1998 ice storm and September 1998 windstorm.
In addition, certain statements made related to the Company's year 2000 program
are also forward-looking (see "Year 2000 Readiness Disclosure").
These forward-looking statements are based upon a number of assumptions,
including assumptions regarding the POWERCHOICE agreement and regulatory
actions to continue to support such an agreement, internal assessment of damage
related to the 1998 storms and related government and insurance company's
actions with respect to providing recovery for such damage.  Actual future
results and developments may differ materially depending on a number of
factors, including regulatory changes either by the federal government or the
PSC, uncertainties regarding the ultimate impact on the Company as the
regulated electric and gas industries are further deregulated and electricity
and gas suppliers gain open access to the Company's retail customers, challenges
to the POWERCHOICE agreement under New York laws, the timing and extent of
changes in commodity prices and interest rates, the effects of weather, the
length and frequency of outages at the Company's two nuclear plants, the
results from the Company's ongoing sale of its generation assets, and the
economic conditions of the Company's service territory.

The Company's main business segment is its regulated operations.  See Part II,
Item 8.  Financial Statements and Supplementary Data - "Note 12. Segment
Information."  This discussion and analysis will concentrate on this business
segment unless otherwise noted.

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

                      EVENTS AFFECTING 1998 AND THE FUTURE
                      ------------------------------------

-  In early January 1998, a major ice storm caused extensive damage to the
   Company's facilities in northern New York.  The cost to repair damaged
   facilities was approximately $140 million.

-  On March 20, 1998, the PSC approved the POWERCHOICE settlement agreement,
   which incorporated the terms of the MRA.  POWERCHOICE was implemented
   September 1, 1998 upon PSC approval of rate tariffs.

-  At the June 29, 1998 annual meeting, the shareholders gave the Company
   approval to form a holding company, the implementation of which will
   occur following the receipt of one final regulatory approval.

-  On June 30, 1998, the Company completed $3.8 billion in public financing
   and used the net proceeds along with shares of the Company's common stock
   and additional cash to consummate the MRA, which terminated, restated or
   amended certain IPP power purchase contracts.

-  In September 1998, a severe windstorm passed through a portion of the
   Company's service territory interrupting electric service to more than
   250,000 customers.  The cost to repair and replace damaged facilities was
   approximately $22.5 million.

-  In December 1998, the Company announced agreements to sell its 72
   hydroelectric generating plants for $425 million and its coal-fired electric
   generating stations for $355 million, which have a combined net book value 
   of $639 million as of December 31, 1998.  The Company continues to pursue the
   sale of its two oil and gas-fired plants and its interest in a third plant.

-  In January 1999, the Company announced plans to pursue the sale of its
   nuclear assets, the Unit 1 nuclear plant and a 41% co-ownership of the Unit
   2 plant.  

           MASTER RESTRUCTURING AGREEMENT AND THE POWERCHOICE AGREEMENT
           ------------------------------------------------------------

BACKGROUND.  The Company entered into the PPAs that were subject to the MRA
because it was required to do so under PURPA and New York State law, which
intended to provide incentives for businesses to create alternative energy
sources.  Under PURPA, the Company was required to purchase electricity
generated by qualifying facilities of IPPs at prices that were not expected
to exceed the cost that otherwise would have been incurred by the Company in
generating its own electricity, or in purchasing it from other sources (known
as "avoided costs").  While PURPA was a federal initiative, each state was
delegated certain authority over how PURPA would be implemented within its
borders.  In its implementation of PURPA, the state of New York passed the 
"Six-Cent Law," establishing 6 cents per KWh as the statutory minimum price
for utility purchases of electric power from IPP projects less than 80 MW in
size.  The Six-Cent Law remained in place until it was amended in 1992 to deny
the benefit of the statute to any future PPAs.  The avoided cost determinations
under PURPA were periodically adjusted by the PSC during this period.  PURPA
and the Six-Cent Law, in combination with other factors, including the area's
existing energy infrastructure and availability of cogeneration hosts, attracted
large numbers of IPPs to New York State, and, in particular, to the Company's
service territory.  The pricing terms of substantially all of the PPAs that the
Company entered into in compliance with PURPA and the Six-Cent Law or other New
York laws were based, at the option of the IPP, either on administratively
determined avoided costs or minimum prices, both of which have consistently
been materially higher than the wholesale market prices for electricity.

Since PURPA and the Six-Cent Law were passed, the Company was obligated to
purchase electricity offered from IPPs in quantities in excess of its own demand
and at prices in excess of those available to the Company by internal generation
or for purchase in the wholesale market.  In fact, by 1991, the Company was
facing a potential obligation to purchase power from IPPs substantially in
excess of its peak demand of 6,093 MW.  As a result, the Company's competitive
position and financial performance deteriorated and the price of electricity
paid per KWh by its customers rose significantly above the national average.
Accordingly, in 1991 the Company initiated a parallel strategy of negotiating
individual PPA buyouts, cancellations and renegotiations, and of pursuing
regulatory and legislative support and litigation to mitigate the Company's
obligation under the PPAs.  By mid-1996, this strategy resulted in reducing the
Company's obligations to purchase power under its PPA portfolio to approximately
2,700 MW.  Notwithstanding this reduction in capacity, over the same period, the
payments made to the IPPs in respect of their PPAs rose from approximately $200
million in 1990 to approximately $1.1 billion in 1997 as independent power
facilities from which the Company was obligated to purchase electricity
commenced operations.  The Company estimated that absent the MRA, payments made
to the IPPs pursuant to PPAs would have continued to escalate by approximately
$50 million per year until 2002.

Recognizing the competitive trends in the electric utility industry and the
impracticability of remedying the situation through a series of customer rate
increases, in mid-1996, the Company began comprehensive negotiations to
terminate, amend or restate a substantial portion of above-market PPAs in an
effort to mitigate the escalating cost of these PPAs as well as to prepare the
Company for a more competitive environment.  These negotiations led to the MRA
and the POWERCHOICE agreement.

MASTER RESTRUCTURING AGREEMENT.  The MRA was consummated on June 30, 1998 with
14 IPPs.  The MRA allowed the Company to terminate, restate or amend 27 PPAs
which represented approximately three-quarters of the Company's over-market
purchase power obligations.  The Company terminated 18 PPAs for 1,092 MW of
electric generating capacity, restated eight PPAs representing 535 MW of
capacity and amended one PPA representing 42 MW of capacity.  The Company paid
the IPP Parties an aggregate of $3.934 billion in cash, of which $3.212 billion
was obtained through a public market offering of senior unsecured debt, $303.7
million from the public sale of 22.4 million shares of common stock, and the
remainder from cash on hand.  In addition, the Company issued 20.5 million
shares of common stock to the IPP Parties.

Under the PSC approved POWERCHOICE agreement, a regulatory asset was established
for the costs of the MRA and will be amortized over a period generally not to
exceed ten years.  The Company's rates under POWERCHOICE have been designed to
permit recovery of the MRA regulatory asset.  In approving POWERCHOICE, the PSC
limited the estimated value of the MRA regulatory asset that could be recovered,
which resulted in a charge to the second quarter of 1998 earnings of $263.2
million upon the closing the MRA.  The POWERCHOICE agreement, while having the
effect of substantially depressing earnings during its five-year term, will
substantially improve operating cash flows.

The MRA is estimated to reduce the Company's IPP payments by more than $500
million annually, net of purchases of power at market price.  The improved cash
flow will allow the Company to reduce electricity prices and repay the debt
required to finance the MRA.  In addition, the Company is actively pursuing
other opportunities to reduce its payments to IPPs that were not party to the
MRA.

Under the terms of the MRA, the Company has no continuing obligation to
purchase energy from the terminated IPP Parties.  The restated contracts with
eight PPAs reflect economic terms and conditions that are more favorable to the
Company than the previous PPAs.  The restated contracts have a term of ten years
and are structured as indexed swap contracts where the Company receives or makes
payments to the IPP Parties based upon the differential between the contract
price and a market reference price for electricity.  The contract prices are
fixed for the first two years changing to an indexed pricing formula thereafter.
Contract quantities average 4,100 GWh per year and are fixed for the full
ten-year term of the contracts.  The indexed pricing structure in combination
with the Company's procurement policies ensures that the net price paid for
energy and capacity will fluctuate relative to the underlying market cost of gas
and general indices of inflation.  Until such time as a competitive energy
market structure becomes operational in the state of New York, the restated
contracts provide the IPP Parties with a put option for the physical delivery of
energy.  The put energy is to be priced at a market proxy based upon short run
marginal cost.  Additionally, one PPA representing 42 MW of capacity was amended
to reflect a shortened term and a lower stream of fixed unit prices.  The
Company projects, based upon current projections of future market prices, that
it will make the following payments to the IPP Parties under the indexed swap
contracts for the years 1999 to 2003 as follows:

<TABLE>
<CAPTION>

             Projected
              Payment
Year      (in thousands)
----      ---------------
<S>       <C>
1999      $        97,354
2000               97,688
2001              102,073
2002              103,552
2003              105,531

</TABLE>
Although against the Company's forecast of market energy prices the
restructured and amended PPAs represent an expected above-market payment
obligation, the Company's portfolio of these PPAs provides it and its customers
with a hedge against significant upward movement in market prices that may be
caused by a change in energy supply or demand.  This portfolio contains terms
that are believed to be more responsive to competitive market price changes.
See Item 8. Financial Statements and Supplementary Data, and Note 9.
"Commitments and Contingencies - Long-term Contracts for the Purchase of
Electric Power."

POWERCHOICE AGREEMENT.  The POWERCHOICE proposal was originally filed by the
Company in October 1995 and subsequent negotiations with PSC Staff and
intervenors resulted in the POWERCHOICE settlement agreement which was filed
by the Company in October 1997.  The POWERCHOICE agreement, which was approved
in the PSC's written order dated March 20, 1998, establishes a five-year rate 
plan that will reduce class average residential and commercial prices by an
aggregate of 3.2% over the first three years, beginning September 1, 1998.
The reduction in prices includes certain savings that will result from approved
reductions of the New York State GRT.  Industrial customers will see average
reductions of 25% relative to 1995 tariffs; these decreases will include
discounts currently offered to some industrial customers through optional
and flexible rate programs.  Additionally, in approving POWERCHOICE, which
incorporated the terms of the MRA, the PSC made various changes to the
settlement agreement.  These changes included, among others, exempting certain
customers from paying the CTC and requiring the Company to defer savings from
the reduction in the interest rate associated with the debt issued in connection
with the MRA financing, which have accumulated to $10.7 million through
December 31,1 998.  The POWERCHOICE agreement measured the 3.2% reduction
against 1995 prices.  The PSC determined that the percentage reduction should
be applied against the lower of 1995 prices or the most current 12-month
period.  The rates used in the POWERCHOICE implementation on September 1, 1998
are based on the 12-month period ended December 31, 1997 for residential and
commercial customers and 1995 prices for all others.

During the term of the POWERCHOICE agreement, the Company would be permitted to
defer certain incremental costs associated primarily with environmental
remediation, nuclear decommissioning and related costs, and changes in laws,
regulations, rules and orders.  To date, the Company has not deferred any
additional costs other than those stipulated in the POWERCHOICE agreement.  In
years four and five of its rate plan, the Company can request an annual increase
in prices subject to a cap of 1% of the all-in price, excluding commodity costs
(e.g., transmission, distribution, nuclear, and forecasted CTC).  In addition to
the price cap, the POWERCHOICE agreement provides for the recovery of deferrals
established in years one through four and, beginning in year four, recover cost
variations in the indexed swap contracts resulting from indexing provisions of
these contracts.  The aggregate of the price cap increase and recovery of
deferrals is subject to an overall limitation of inflation.

Under the terms of the POWERCHOICE agreement, all of the Company's customers
will be able to choose their electricity supplier in a competitive market by
December 1999.  Currently, some customers are able to choose their electricity
supplier, and the Company expects to offer retail choice to all customers by
August 1, 1999.  The Company will continue to distribute electricity through its
transmission and distribution systems and will be obligated to be the provider
of last resort for those customers who do not exercise their right to choose a
new electricity supplier.

The POWERCHOICE agreement provides that the MRA and the contracts executed
pursuant thereto are prudent.  The POWERCHOICE agreement further provides that
the Company shall have a reasonable opportunity to recover its stranded costs,
including those associated with the MRA and the contracts executed thereto,
through a CTC and, under certain circumstances, through exit fees or in rates
for back up service.  The Company's rates under POWERCHOICE are designed to
permit recovery of the MRA regulatory asset and to permit recovery of, and a
return on, the remainder of its assets, as appropriate.

Between the MRA closing date (June 30, 1998) and the POWERCHOICE implementation
date (September 1, 1998), the Company experienced a reduction in power purchase
costs of $80 million as well as increased financing costs of $40.4 million as a
result of the MRA and the MRA financing.  The net effect of these items was
deferred for future disposition because the time lag between these events was
not contemplated in the POWERCHOICE agreement.

In July 1998, the Public Utility Law Project of New York, Inc. ("PULP") and
others sought a declaratory judgment, declaring the Company's POWERCHOICE
agreement unlawful, null and void and seeking injunctive relief in the Supreme
Court of the state of New York, Albany County against the PSC and the Company to
enjoin the defendants to halt all their actions and expenditures to implement
the rules for the provision of retail energy services contained in the
POWERCHOICE agreement.  The PSC and the Company filed a motion seeking to
dismiss this action.  The motion is pending in the Albany County Supreme Court.
The Company is unable to predict the outcome of this matter.

In early October 1998, the Alliance for Municipal Power, a group of 21 towns
and villages in St. Lawrence and Franklin Counties pursuing municipalization
that has also called themselves the Retail Service Communities, and Alfred P.
Coppola, a Councilman from the City of Buffalo, commenced an Article 78
Proceeding in Albany County Supreme Court that challenged the PSC's decision to
approve POWERCHOICE and the PSC's decision that denied the petitions of Alliance
for Municipal Power and Coppola for rehearing before the Commission.  The
Article 78 Petition seeks to vacate the decision of the PSC approving
POWERCHOICE provisions relating to the determination and recovery of strandable
costs through the application of a competitive transition charge and exit fees.
The PSC has made a motion to dismiss the Article 78 Petition in this matter and
the motion is pending in the Albany County Supreme Court.  The Company is unable
to predict the outcome of this matter at this time.  Suspension of POWERCHOICE
or renegotiation of its material terms could have a material adverse effect on
the Company's results of operations, financial condition, and future cash flows.

In its written Order dated May 6, 1998, the PSC approved the Company's plan to
divest all of its fossil and hydro generation assets, which is a key component
in the Company's POWERCHOICE agreement to lower average electricity prices and
provide customer choice.  On December 3, 1998, the Company announced it had
reached an agreement with an affiliate of Orion Power Holding, Inc. ("Orion") to
sell its 72 hydroelectric generating plants with a combined capacity of 661 MW
for $425 million, representing 1.7 times their book value of approximately
$258.2 million at December 31, 1998.  As part of the agreement, the Company will
purchase electricity from Orion under a transition power agreement ("TPA")
through September 2001.  On December 23, 1998, the Company announced an
agreement with NRG Energy, Inc. ("NRG") to sell its Huntley and Dunkirk
coal-fired electric generating stations for $355 million.  The coal stations
have a book value of approximately $380.6 million and a combined capacity of
1,360 megawatts at December 31, 1998.  The Company has also signed, as part of
this agreement, a TPA to purchase electricity from NRG through June 2003 at
prices consistent with those negotiated in POWERCHOICE for those assets.  The
TPAs for the hydro and coal-fired facilities are designed to help the Company
meet the objectives of rate reduction and price cap commitments as well as meet
expected demand as the "provider of last resort" as outlined in the POWERCHOICE
agreement.  The TPAs acts as hedges against rising power costs.  The terms of
the TPAs provide for both fixed and variable payments, encompassing both
capacity and energy.  These TPAs are one part of the integrated transactions
for the sale of the generating facilities.  It is anticipated that transaction
closings will occur in mid-1999 after receipt of the necessary regulatory
approvals.  The Company continues to pursue the sale of its two oil and
gas-fired plants in Albany and Oswego, which have net book values of $39.3
million and $332.4 million, respectively at December 31, 1998.  The Company is
unable to predict the outcome or timing of the divestiture of these plants.
The Company will also be selling its interest in the Roseton plant with a net
book value of $39.8 million as of December 31, 1998, through an auction by the
operator of the plant, Central Hudson Gas and Electric Corporation.  Central
Hudson Gas and Electric Corporation has indicated that the sale is expected to
conclude in 2000.  The auction process will serve to quantify any stranded
costs associated with the Company's fossil and hydro generating assets.  The
Company will have a reasonable opportunity to recover these costs through the
CTC and otherwise as described above.  After the auction process is complete,
the Company has agreed not to own any non-nuclear generating assets in the
state of New York, subject to certain exceptions provided in the POWERCHOICE
agreement.  Under the terms of the note indenture prepared in connection with 
the financing of the MRA, the Company is obligated to use 85% of the proceeds
of the sale of the fossil and hydro generation assets to reduce outstanding
debt.

The POWERCHOICE agreement contemplated that the Company's nuclear plants would
remain part of the Company's regulated business.  The POWERCHOICE agreement
stipulates that absent a statewide solution, the Company will file a detailed
plan for analyzing other proposals regarding its nuclear assets, including the
feasibility of an auction, transfer and/or divestiture of such facilities,
within 24 months of POWERCHOICE approval. On January 28, 1999, the Company
announced plans to pursue the sale of its nuclear assets.  The Company is unable
to predict if a sale will occur and the timing of such sale.  See "PSC Staff's
Tentative Conclusions on the Future of Nuclear Generation."

The POWERCHOICE agreement also allows the Company to form a holding company,
which the Company's shareholders approved at its 1998 annual meeting.  The
Company received approval from the FERC, PSC and NRC to form the holding
company.  The Company is awaiting further approval from the Securities and
Exchange Commission, prior to implementation of the holding company.  

The holding company structure is intended to provide the Company and its
subsidiaries with the financial and regulatory flexibility to compete more
effectively in an increasingly competitive energy industry by providing a
structure that can accommodate both regulated and unregulated lines of business.
The holding company structure would largely eliminate many regulatory
constraints that would limit the Company's ability to participate in unregulated
business opportunities as the industry evolves.

All of the foregoing discussion of the POWERCHOICE agreement is qualified in its
entirety by the text of the agreement and PSC Order.

For a discussion of the Company's ability to continue to apply SFAS No. 71 to
its remaining electric business (nuclear generation and electric transmission
and distribution business), under POWERCHOICE, see Note 2. Rate and Regulatory
Issues and Contingencies.

<PAGE>

               PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC
               ---------------------------------------------------

On May 16, 1996, the PSC issued its Order in the COPS case, which called for a
major restructuring of New York State's electric industry, and the introduction
of a competitive wholesale power market and retail access for all electric
customers.  The goals include lowering consumer rates, increasing choice,
continuing reliability of service, continuing environmental and public policy
programs, mitigating concerns about market power and continuing customer
protection and the obligation to serve.  The provisions of the Company's
POWERCHOICE agreement are consistent with COPS objectives.

The PSC continues to assess other functions in the regulated electric and gas
business to lower consumer rates and increase customer choice.  The PSC is
considering to open competition to such functions as metering, billing,
collections and customer service.  In addition, on January 13, 1999, the PSC
adopted a set of Uniform Business Rules for Retail Access designed to streamline
and make more uniform the manner in which the local utilities interact with
natural gas and electricity marketers, energy services companies and customers
who purchase energy in New York State's evolving competitive market.  This was a
collaborative effort among all parties involved.  The Company will continue to
participate with the PSC and other parties as New York State moves forward with
a competitive utility industry, but the Company cannot predict the outcome of
the results and the impact on its POWERCHOICE agreement.

            FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY
            ---------------------------------------------------------

RULEMAKING ON OPEN ACCESS.  In April 1996, the FERC issued Order 888.  Order
888 promotes competition by requiring that public utilities owning, operating,
or controlling interstate transmission facilities file tariffs which offer
others the same transmission services they provide for themselves, under
comparable terms and conditions.  The Company complied with this requirement by
filing its open access transmission tariff with FERC on July 7, 1996.  Based
upon settlement discussions with various parties, a proposed settlement was
submitted to the FERC in the first quarter of 1997.  The settlement has not been
approved by the FERC at this time. Hearings were conducted in September 1997
with non-settling parties.  A March 1998 Administrative Law Judge's ("ALJ")
recommended decision in this proceeding recommended lower tariffs than those
filed by the Company.  The Company is unable to determine the ultimate
resolution of this issue or when a decision will be issued by FERC.
Under FERC Order 888, the NYPP was required to file reformed power pooling
agreements that establish open, non-discriminatory membership provisions and
modify any provisions that are unduly discriminatory or preferential.  On
January 31, 1997, the NYPP Member Systems (the "Member Systems") submitted a
comprehensive proposal to establish a NYISO, a New York State Reliability
Council ("NYSRC") and a New York Power Exchange ("NYPE") that will foster a
fully competitive wholesale electricity market in New York State.  The NYISO
would provide for the reliable operation of the transmission system in New York
State and provide nondiscriminatory open access to transmission services under a
single NYISO tariff.  Through the NYISO, the transmission owners, including the
Company, would be compensated for the use of their transmission systems on a
cost-of-service basis.  The NYSRC would establish the reliability rules and
standards by which the NYISO operates the bulk power system.  The NYISO would
also administer the daily electric energy market and the NYPE would facilitate
the electric energy market on a day-ahead basis.

On June 24, 1998, FERC gave the Member Systems conditional approval to form the
NYISO.  However, FERC deferred action on the rates, terms and conditions of the
NYISO's open access transmission tariff, and directed the Member Systems and
interested parties to negotiate a modified voting structure for the NYISO
committees.  In compliance with this directive, a settlement agreement supported
by the Member Systems and a number of parties was submitted to FERC on October
23, 1998.  Other steps have also been taken to prepare for the establishment of
the NYISO, including selection of members of the Board of Directors.
Subsequently, on January 27, 1999, FERC conditionally approved the tariffs,
market rules and market based rates proposed by the NYISO.  While the Company is
unable to predict when FERC will rule on the remaining details of the Member
Systems' NYISO proposal, it does believe that progress is being made in New York
State toward more competitive wholesale electricity markets, consistent with the
POWERCHOICE restructuring agreement.

STRANDED COST RECOVERY IN THE CASE OF MUNICIPALIZATION.  In Order 888, the FERC
also stated that it would provide for the recovery of prudent and verifiable
wholesale stranded costs where the wholesale customer was able to obtain
alternative power supplies as a result of Order 888's open access mandate.
Order 888 left to the states the issue of retail stranded cost recovery.  Where
newly created municipal electric utilities required transmission service from
the displaced utility, the FERC stated that it would entertain requests for
stranded cost recovery since such municipalization is made possible by open
access.  The FERC also reserved the right to consider stranded costs on a
case-by-case basis if it appeared that open access was being used to circumvent
stranded cost review by any regulatory agency.

In November 1997, FERC issued Order 888-B.  This Order clarified that the FERC
recognizes the existence of concurrent state jurisdiction over stranded costs
arising from municipalization.  The FERC acknowledged in Order 888-B that the
states may be first to address the issue of retail-turned-wholesale stranded
costs, and stated that it will give the states substantial deference where they
have done so.

In approving POWERCHOICE, the PSC authorized changes to the Company's Retail
Tariff providing for the recovery of stranded costs in the case of
municipalization regardless of whether the new municipal utility requires
transmission service from the Company.  The calculation of stranded costs is
governed by this Retail Tariff, which became effective on April 6, 1998.  A
number of communities are considering municipalization and have requested an
estimate of their stranded cost obligation.

In late January 1997, the Company provided 26 communities in St. Lawrence and
Franklin Counties with estimates they requested of the stranded costs they might
be expected to pay if they withdrew from the Company's system to create
municipal electric utilities.  The stranded cost calculations were based on the
methodology prescribed by the FERC in Order 888.  The preliminary estimate of
the combined potential stranded cost liability for the communities ranged from a
low of $225 million to a high of $452 million, depending upon the forecast of
electricity market prices that was used.  These amounts did not include the
costs of creating and operating a municipal utility.  At this time, it appears
that 21 of the original 26 communities are still pursing municipalization.  If
these 21 communities withdrew from the Company's system, the Company would
experience a potential revenue loss of approximately 2% per year.
These 21 communities seeking to withdraw from the Company's system also propose
to disconnect entirely from the Company's system and to take transmission
service from another utility.  They state that, given the provisions of Order
888, FERC would not approve the Company's request for stranded cost recovery
under these circumstances.  The Company has responded that, regardless of the
result at the FERC, those communities will be subject both to the exit fee
provisions of the Company's Retail Tariff and the possibility that a state court
may permit the Company to recover some or all of the stranded costs in a
condemnation proceeding.  The 21 communities have filed suit in state court
challenging the PSC's approval of the exit fee provisions in the Company's
Retail Tariff.  The PSC has moved to dismiss the case.  The Company is unable to
predict the outcome of this matter.  See "Master Restructuring Agreement and
the POWERCHOICE Agreement."

In August 1997, the Company provided the Village of Lakewood with an estimate of
its stranded cost obligation in response to a formal request under FERC Order
888.  In June 1998, the Village of Lakewood filed a petition with FERC seeking a
determination that it would not be responsible for any of the Company's stranded
costs if it created a new municipal electric system.  The Company responded in
opposition to this petition.  On October 1, 1998, FERC set a hearing with a FERC
Administrative Law Judge in the matter of Lakewood's stranded cost obligation to
the Company under Order 888.

The PSC and the Company requested rehearing of the FERC's Order of October 1,
1998.  Both parties pointed out that the PSC has a process in place to
adjudicate Lakewood's liability for stranded costs under the Company's Retail
Tariff in the event of municipalization, and suggested that it would be
inefficient and contrary to Order No. 888-B for the FERC to hold hearings on
Lakewood's stranded cost obligation under Order 888 until Lakewood's stranded
cost obligation under the Retail Tariff has been established by the PSC.  The
Company also sought clarification that Order 888 does not preempt the PSC's
jurisdiction to authorize the recovery of stranded costs under the exit fee
provisions of the Company's Retail Tariff.

On December 11, 1998 the FERC issued an order granting the Company's request for
clarification that Order 888 does not preempt the exit fee provision of the
Retail Tariff and directing that the Lakewood case be held in abeyance pending
the resolution of Lakewood's stranded cost obligation under the Company's Retail
Tariff.  Lakewood and the Company are required to file a joint status report
with FERC six months from the issuance of the Order.  On January 7, 1999, the
PSC directed the Company to provide Lakewood, within 45 days, an estimate of
Lakewood's stranded cost obligation under the exit fee provisions of the
Company's Retail Tariff.  On February 18, 1999, the Company provided Lakewood
with an estimate of these exit fees of $14.98 million.  The Company is unable to
predict the outcome of this matter.

On December 7, 1998, the Company provided the City of Buffalo with both a PSC
exit fee estimate and FERC Order 888 estimate of its stranded cost obligation.
The PSC exit fee estimate is $899 million and the FERC Order 888 estimate is
$1.5 billion.  If the City of Buffalo withdrew from the Company's system, the
Company would experience a potential revenue loss of approximately 8% per year.
The Company has also prepared exit fee stranded cost estimates for annexations
in the Village of Wellsville and Madison County.  The Company is unable to
predict whether the City of Buffalo or these other municipalities will pursue
withdrawal from the Company's system or the amount of stranded costs the Company
may receive as a result of any withdrawals.

                 OTHER FEDERAL AND STATE REGULATORY INITIATIVES
                 ----------------------------------------------

MULTI-YEAR GAS RATE SETTLEMENT AGREEMENT.  The Company, Multiple Intervenors
(an unincorporated association of approximately 60 large commercial and
industrial energy users with manufacturing and other facilities located
throughout New York State) and PSC staff reached a three-year settlement that
was conditionally approved by the PSC on December 19, 1996.  The settlement rate
has the effect of a $10 million annual reduction in base rates or a $30 million
total reduction over the three-year term of the settlement.  This reflected a
$19 million reduction in the amount of fixed non- commodity costs to be
recoverable in base rates, offset by a $9 million increase in annual base rates.
The Company estimated that the combination of in-hand supplier refunds and
further reductions in upstream pipeline costs would be sufficient to fund the
$19 million annual reduction in non-commodity cost recovery.

If the non-commodity cost reductions exceed $57 million ($19 million annually)
during the three-year settlement period, the excess, up to $40 million will be
credited to a Contingency Reserve Account ("CRA") to be utilized for ratepayer
benefit in the rate year ending October 31, 2000 or beyond.  To the extent the
actual non-commodity cost reductions exceed $57 million by more than $40
million, the Company may retain any excess subject to a return on equity sharing
provision.  In the event the non-commodity reductions fall short of the $57
million estimate, the Company will bear the risk of any shortfall.  As of
December 31, 1998, the Company has credited $30 million to the CRA.  With
respect to the second year of the gas rate settlement agreement (November 1,
1997 to October 31, 1998), the Company did not experience any margin (revenues
less fuel costs) or peak shaving losses, since the terminating and restructuring
IPPs ran longer than originally anticipated.  However, the Company may
experience margin or peak shaving losses in the last year of the settlement, a
result of the termination or restructuring of IPP contracts.  The margin losses
would be collected currently subject to 80%/20% (ratepayer/shareholder) sharing
and the peak shaving losses will be deferred to the CRA, subject to limits
specified in the settlement.

In return for taking on this risk, the Company has achieved a portion of the
revised rate structure that had been proposed, such that the Company is allowed
to recover more of its costs through the customer basic service charge and less
on the customer usage charge, which fluctuates based on volume.  The Company
obtained an ROE cap of 13.5% with 50/50 sharing between ratepayers and
shareholders in excess of the cap.  The Company has not achieved an ROE
exceeding the cap in the rate years ending October 31, 1997 or 1998.  The
Company also has an opportunity to earn up to $2.25 million annually if its gas
commodity costs are lower than a market based target without being subject to
the ROE cap.  The Company has an equal $2.25 million risk if gas commodity costs
exceed the target.  An additional major benefit of the revised rate design is
that the margin made on each additional new customer will significantly increase
to the extent additional throughput does not require additional upstream
pipeline capacity for service.  This, along with the approval of the Company's
Progress Fund, which allows the Company to use utility revenues in an amount not
to exceed $11 million in total for the purpose of providing financing for large
customers to convert or increase their gas use, will provide new opportunities
for growth.

FUTURE OF THE NATURAL GAS INDUSTRY.  In November 1998, the PSC issued its
Policy Statement concerning the Future of the Natural Gas Industry in New York
State and Order Terminating Capacity Assignment (PSC Policy Statement).  The PSC
Policy Statement noted the following:

-  The PSC envisions a transitional time frame of three to seven years for
   local gas distribution companies (LDC) to exit the business of purchasing
   natural gas (the "merchant" function).

-  The PSC envisions a process comprising three basic elements, which should
   be pursued in parallel in the exiting of the merchant function:

   1.  Addressing the issues involved in the exiting of the merchant
       function on a utility-by-utility basis as part of the LDCs individual
       rate plans;

   2.  Collaboration among staff, LDCs, marketers, pipelines and other
       stakeholders of generic issues such as operational and reliability
       issues, protocols and information systems requiring a status report
       by April 1, 1999; and

   3.  Coordination of issues faced by electric utilities, including provider
       of last resort issues and a plan to allow competition in other areas,
       such as metering, billing and information services.

-  LDCs may no longer require capacity assignment or inclusion of capacity
   costs in transportation rates beyond April 1, 1999 to customers migrating to
   marketers except where specific operational and reliability requirements
   warrant.

In November 1998, the PSC approved the Company's proposed pilot program that
would, effective December 1, 1998, no longer require assigning pipeline capacity
and related costs upstream of the CNG Transmission System to customers migrating
to transportation.  However, the Company's proposed pilot program sought to
continue to assign capacity on the CNG system until October 31, 1999, the
expiration date of its current gas rate settlement agreement.  A stranded cost
recovery mechanism, in the form of a surcharge, was established to provide for
the recovery of the unassigned pipeline capacity costs until October 31, 1999.

In December 1998, the Company notified the PSC that the Company's specific
operational and reliability requirements continue to warrant certain mandatory
capacity assignment and inclusion of capacity costs in transportation rates
after April 1, 1999.  The PSC noted in its PSC Policy Statement that it will
provide LDCs with a reasonable opportunity to recover these strandable costs if
they can demonstrate compliance with the PSC's directives to minimize such
costs.  The Company believes that it has taken numerous actions to reduce its
capacity obligations and its potential stranded costs, but is unable to predict
the outcome of this matter.  The Company anticipates that this issue will be
addressed in the individual negotiations with the PSC anticipated to begin
during the second quarter of 1999.  For a discussion of the Company's long term
supply, transportation and storage commitments, see Part II, Item 8. Financial
Statements and Supplementary Data - Note 9." Commitments and Contingencies."

NRC POLICY STATEMENT AND AMENDED DECOMMISSIONING FUNDING REGULATIONS.  The NRC
issued a policy statement on the Restructuring and Economic Deregulation of the
Electric Utility Industry (NRC Policy Statement) in 1997.  The NRC Policy
Statement addresses the NRC's concerns about the adequacy of decommissioning
funds and about the potential impact on operational safety.  In addition to the
NRC Policy Statement, the NRC amended its regulations on decommissioning funding
to reflect conditions expected from deregulation of the electric power industry.

The NRC's new decommissioning funding rule, which addresses concerns about the
adequacy of decommissioning funds, took effect on November 23, 1998.  The NRC's
new rule and its accompanying standard review plan, which is still pending NRC
review, could raise compliance issues. Licensees that are no longer subject to
traditional cost-of-service regulation for 80% or less of their electricity
sales will need to assure that they have a source of revenue for decommissioning
funds through a non-bypassable charge which qualifies a licensee to use a
sinking fund.  See Part II, Item 8. Financial Statements and Supplementary
Data, Note 3 - "Nuclear Operations" for a discussion of the Company's
decommissioning estimates for Unit 1 and Unit 2.

NRC AND NUCLEAR OPERATING MATTERS.  In January 1998, the NRC issued its
Systematic Assessment of Licensee Performance ("SALP") report on Unit 1 and
Unit 2, which covers the period June 1996 to November 1997.  The SALP report,
which is an extensive assessment of the plants' performance in the areas of
operations, maintenance, engineering and support, stated that the performance of
Unit 1 and Unit 2 was generally good, although ratings were lower than the
previous assessment.  The Company agrees with the NRC's determination that there
are areas of its performance that need improvement and has taken several actions
to make those needed improvements.

Some owners of older General Electric Company boiling water reactors, including
the Company, have experienced cracking in horizontal welds in the plants' core
shrouds.  In response to industry findings, the Company installed pre-emptive
modifications to the Unit 1 core shroud during a 1995 refueling and maintenance
outage.  The core shroud, a stainless steel cylinder inside the reactor vessel,
surrounds the fuel and directs the flow of reactor water through the fuel
assemblies.  Inspections conducted as part of the March 1997 refueling and
maintenance outage detected cracking in vertical welds not reinforced by the
1995 repairs.  Subsequently, the Company filed a comprehensive inspection and
analysis report with the NRC that concluded that the condition of the Unit 1
core shroud supports the safe operation of the plant, and currently has NRC
approval to operate Unit 1 until the Unit's scheduled refueling and maintenance
outage in spring 1999, at which time the core shroud will be reinspected.  The
Company has developed a repair that would be accomplished during the spring 1999
outage if inspections indicate that repairs are needed.

On May 2, 1998, Unit 2 was taken out of service for a planned refueling and
maintenance outage.  During the outage the Company performed scheduled
inspections of the plant's reactor core shroud and identified cracking in the
welds of the shroud.  The scope of the inspection was expanded once the cracking
was found, which extended the length of outage.  The NRC staff agreed that
continued operation without repair or intermediate inspection of the core shroud
is acceptable for at least one operating cycle after completion of the May 1998
refueling outage.  Unit 2 returned to service on July 5, 1998 after completing
the 64-day refueling and maintenance outage.

PSC STAFF'S TENTATIVE CONCLUSIONS ON THE FUTURE OF NUCLEAR GENERATION.  On
August 27, 1997, the PSC requested comments on its staff's tentative conclusions
about how nuclear generation should be treated after decisions are made on the
individual electric restructuring agreements.  The PSC staff concluded that
beyond the transition period (the period covered by the various New York utility
restructuring agreements, including POWERCHOICE), nuclear generation should
operate on a competitive basis.

In October 1997, the majority of utilities with interests in nuclear power
plants, including the Company, requested that the PSC reconsider its staff's
nuclear proposal, and the utilities recommended that a more formal process be
developed to address issues relating to competition, sale of nuclear plants,
responsibility for decommissioning, disposal of spent fuel, safety, and
environmental benefits of fuel diversity.

On March 20, 1998, the PSC issued an opinion and order instituting a further
inquiry into the matters addressed in the PSC Staff's tentative conclusions
regarding the treatment of nuclear generation in the future.  The order
concluded that the proposals contained in the Staff Report required more
extensive examination, and directed that the examination begin with a
collaborative process and move to litigation on particular issues if necessary.
A collaborative proceeding commenced on January 20, 1999.

The matters addressed in the inquiry include:
-     Market treatment for nuclear power
-     The feasibility of mandated divestiture and its likely consequences
-     Decommissioning issues
-     Effects of PSC Staff's proposal on municipalities

The tentative time line established by PSC Staff for this inquiry calls for
completion of the process by the end of 1999.

In January 1999, the Company announced plans to pursue the sale of its nuclear
assets, which will require approval from the PSC.  The Company is unable to
predict if a sale will occur and the timing of such sale.

At December 31, 1998, the net book value of the Company's nuclear generating
assets was approximately $1.6 billion, excluding the reserve for
decommissioning.  In addition, the Company has other assets of approximately
$0.5 billion.  These assets include the decommissioning trusts and regulatory
assets, primarily due to the deferral of income taxes.

             OTHER COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES
             -------------------------------------------------------

TAX INITIATIVES.  The Company is working with utility, customer and state
representatives to solve the negative impact that all utility taxes, including
the GRT, are having on rates and the state of the economy.  At the same time,
the Company is also contesting the high real estate taxes it is assessed by many
taxing authorities, particularly those imposed upon generating facilities.

The New York State Legislature passed a state budget in August 1997 which
includes a reduction of the GRT over three years.  For gas and electric
utilities, the tax imposed on gross income was reduced from 3.5% to 3.25% on
October 1, 1998 and from 3.25% to 2.5% on January 1, 2000.  The state tax
imposed on gross earnings will remain unchanged at .75%, bringing the total GRT
to 3.25% -- a full percentage point lower than 1997's level of 4.25%.  As
contemplated in POWERCHOICE, the savings from the reduction of the GRT will be
passed on to the Company's customers.  The Company believes that further tax
relief is needed to relieve the Company's customers of high energy costs and to
improve New York State's competitive position as the industry moves toward a
competitive marketplace.

The following table sets forth a summary of the components of other taxes
(exclusive of income taxes) incurred by the Company in the years 1996 through
1998:

<TABLE>
<CAPTION>

                                                        In millions of dollars
                                                        1998      1997     1996
                                                   -----------  -------  -------
<S>                                               <C>            <C>      <C>
Property tax expense. . . . . . . . .             $      251.1   $250.7   $249.4 
Sales tax . . . . . . . . . . . . . .                     17.6     13.4     14.1 
Payroll tax . . . . . . . . . . . . .                     37.4     34.1     36.4 
Gross Receipts Tax. . . . . . . . . .                    167.0    184.6    184.1 
Other taxes . . . . . . . . . . . . .                      0.3      0.1      0.5 
                                                  -------------  -------  -------
      Total tax expense . . . . . . .                    473.4    482.9    484.5 
Charged to construction, subsidiaries
   and regulatory recognition . . . .                    (13.4)   (11.4)    (8.7)
                                                  -------------  -------  -------
      Total other taxes . . . . . . .             $      460.0   $471.5   $475.8 
                                                  =============  =======  =======

</TABLE>

CUSTOMER DISCOUNTS.  In recent years, as energy prices have risen, customers
have found alternatives to electric service from their host utility, including
the Company.  To address that competitive challenge, the Company filed for a
service tariff in 1994 called SC-11.  The SC-11 tariff provided the Company with
flexibility to individually negotiate service agreements within the Company's
service franchise territory in response to a number of competitive alternatives
such as on-site generation, fuel switching, and facility relocation.

Effective September 1, 1998, the Company's POWERCHOICE agreement was
implemented.  As part of that agreement, the PSC approved several key pricing
initiatives to address the Company's price levels and the resulting need to
provide discounted service.  Those initiatives include:

-  Service class specific pricing goals were agreed upon (see "Master
   Restructuring Agreement and the POWERCHOICE Agreement").  The targeted rate
   redesigns contained in POWERCHOICE are intended to deliver the greatest price
   reductions to those customers who have exhibited the greatest competitive
   challenges to the Company under SC-11.  The rate design provides the most
   competitive prices to customers who provide economic value to the state
   because they use the greater amounts of electricity and have the greater
   demand on the Company's system, thereby minimizing the need (and amount)
   of future discounts, while maximizing the incentive to remain in New York
   State.  In addition, the pricing goals include those discounts forecasted
   under SC-11.

-  The PSC agreed to close SC-11 to new subscriptions provided that the
   Company agrees to honor all existing contracts through their natural
   expiration date, provide a provision for limited renewal of expiring SC-11
   agreements and develop a suitable replacement tariff.  Therefore, as
   contracts expire, customers will either migrate back to the redesigned
   standard tariff rate classification or continue on the SC-11 agreement.

-  A new service tariff, SC-12, has been approved as a replacement tariff to
   SC-11 and will address future competitive challenges for the Company.  SC-12
   is differentiated from SC-11 in that predetermined minimum criteria are
   specified within the tariff along with standardized discounted pricing which
   varies according to the underlying competitive challenge which the Company
   is facing.  The Company has also retained flexibility to address specific
   competitive challenges for energy intensive and job intensive challenges
   through individual negotiations.

-  Revisions were made to the Company's back up, supplemental, and maintenance
   pricing tariff for customers installing on-site generation.  The Company has
   been trying to establish compensatory rates for these services for a
   number of years.  A tariff provision resulting from POWERCHOICE ensures that
   the Company can charge compensatory rates for these services and thereby
   reduce the discounts that would otherwise be necessary in its absence.

Together, these initiatives will provide lower overall prices to customers,
strengthen the Company's competitive position and minimize the amount of future
discounts during the term of POWERCHOICE.

                          YEAR 2000 READINESS DISCLOSURE
                          ------------------------------

As the year 2000 approaches, the Company, along with other companies, could
experience potentially serious operational problems, since many computer
programs that were developed in the past may not properly recognize calendar
dates beginning with year 2000.  Further, there are embedded chips contained
within generation, transmission, distribution, gas, and other equipment that may
be date sensitive.  In circumstances where an embedded chip fails to recognize
the correct date, electric, gas and business operations could be adversely
affected.

PLAN:  A Company-wide year 2000 project management office has been formed and
year 2000 project managers have been appointed within each business group.  A
year 2000 program vice-president and an executive level steering committee have
been put in place to oversee all aspects of the program.  In addition to Company
personnel, the Company has retained the services of leading computer service and
consulting firms specializing in computer systems and embedded components, which
are involved in various phases of the project.  Also, the Company is working
closely with industry groups such as the Electric Power Research Institute
("EPRI"), North American Electric Reliability Council ("NERC"), Nuclear Energy
Institute, and other utilities.  In addition, the PSC is requiring that New York
utilities have mission critical year 2000 work, including a contingency plan,
completed by July 1, 1999, and the NRC is requiring the Company to certify that
the Company's two nuclear plants will be year 2000 ready by July 1, 1999.  A
plan was developed that established phases of the work to be done.  The phases
are:

-  an inventory of all systems and equipment, (including a physical
   walk-down of all of the Company's substations),
-  an assessment of all systems and equipment and definition of next steps,
-  remediation,
-  testing and validation,
-  acceptance and deployment,
-  independent validation, and
-  contingency planning.

As part of the inventory phase, all the systems and equipment have been
prioritized into four categories based upon their functional need and
importance.  The priorities are:

-  Priority 1 - Any failure or regulatory breach that can cause an
   interruption to the generation or delivery of electric or gas energy to
   customers, or can jeopardize the safety of any employee, customer, or the
   general public (e.g. the Energy Management System that controls the flow of
   electricity and communicates information between the control center and
   sub-stations).
-  Priority 2 - Any failure that can cause an interruption to customer
   service or breach of significant contractual or financial commitment  (e.g.
   Meter reading equipment).
-  Priority 3 - Any failure that can inconvenience a business partner or
   significantly impact a Company business group productivity (e.g. electronic
   payments to vendors).
-  Priority 4 - Any failure that can adversely impact a Company work group or
   personal productivity, or other business processes (e.g. applications used
   on a desktop computer used to accomplish day-to-day productivity activities).

Although the Company has identified seven different phases of the project, in
some cases the phases are done concurrently.  For example, individual computers
may be completely tested and redeployed while others are still being remediated.
Information obtained within the phases is reviewed by a panel consisting of
employees and consultants.  Additional testing may be performed based on the
importance of the component and a recommendation of the panel.  Complete
integration and interface testing will be performed on components and systems
whenever possible.

The Company's primary focus is on priorities 1 and 2 because of the direct
impact on customers.  Although the Company's plan addresses completion of all
priority items prior to July 1, 1999, some exceptions may not be addressed
completely.  These are scheduled, however, to be completed by January 1, 2000.

The Company's progress with its year 2000 issues for priority items 1 and 2 are
as follows:

<TABLE>
<CAPTION>

         PHASE                STATUS       ESTIMATED COMPLETION DATE
------------------------  ---------------  -------------------------
<C>                           <S>          <C>
- Inventory                   Complete
- Assessment                  Complete
- Remediation                 In-progress  December 1998 - May 1999
- Testing & Validation        In-progress  March 1999 - May 1999
- Acceptance                  In-progress  March 1999 - June 1999
- Independent Validation      In-progress  October 1999
- Contingency Planning        In-progress  December 1998 - June 1999

</TABLE>

      Note:  Each business group within the Company has its own schedule.  The
      estimated completion dates above may show a range due to different
      schedules within each business group.

The Company has expanded the scope of its Independent Validation phase and has
added an additional Quality Assurance Audit scheduled for September 1999.
Therefore, the Company has extended its estimated completion date for that phase
to October 1999.

RISKS:  The failure to correct for year 2000 problems, either by the Company or
third parties, could result in significant disruptions of the Company's
operations.  At this point in time based on the Company's progress to date and
the information received from third parties, the Company is unable to determine
its most reasonably likely worst case scenario.

Like any organization, the Company is dependent upon many third parties,
including suppliers of energy and materials (e.g. independent power producers),
service providers, transporters, and the government.  These third parties
provide services vital to the Company and year 2000 problems at these companies
could adversely affect electric and gas operations.  One such example is that
the Company expects that by the year 2000, it will be purchasing the majority of
its electric generation needs.  If any of these suppliers has a year 2000
failure, it could interrupt energy supply to the Company's customers.  Another
example of such a vital third party is telephone companies.  If the telephone
companies have year 2000 failures, this could in turn affect the Company's
customer response capabilities and the Company's ability to operate and maintain
the transmission and distribution system that carries electricity to businesses
and customer homes.  To address these third party issues, the Company has
requested certificates of compliance from third parties.  To date, the Company
has received some responses, but disclosure has been limited.  The Company will
continue to follow up with third parties to verify the accuracy of responses
when the Company's relationship with such third parties is material for its
operations.  However, the Company may not be able to verify accuracy in all
cases.  The inability of suppliers to complete their year 2000 readiness process
could materially impact the Company.

The Company is connected to an electric grid that links utilities throughout
the United States and Canada.  This interconnection is essential to the
reliability and operational integrity of the connected utilities.  If one of the
electric utilities in the grid has a failure, it could cause power fluctuations
and possible interruption of others in the grid.  As a result, even when the
Company does an effective job of becoming compliant, it could still have
customer interruptions.  The Company is working closely with NYPP, NERC, other
utilities, EPRI, and other industry groups to address the issue of grid
reliability.

The Company's gas distribution system also has the potential to be adversely
impacted by year 2000 noncompliance either by third parties or if the Company's
program fails to identify and remediate all problem areas.  From the third party
natural gas production and transmission facilities, to the Company's
distribution pipeline system, and ultimately, to the customer, there are
computer systems and equipment with date sensitive processing.  If, despite the
Company and third party's best efforts, a year 2000 failure occurs, the flow of
gas to the customer could be jeopardized.

As an example, the Company is connected directly to three major transmission
pipelines, and has an indirect connection with a fourth.  If these pipelines are
unable to provide full gas delivery to the Company, the Company would implement
standing emergency procedures that could interrupt customers.  To avoid such an
event, the Company is working with the pipelines, and state agencies to reduce
the probability of any customer interruptions due to year 2000 problems.

CONTINGENCY PLANS:  The Company's year 2000 schedules also include the
development and implementation of contingency plans in the event of year 2000
failures, both within the Company and by third parties.  The Company expects to
have these plans completed during 1999 for all priority categories.  The Company
has established a year 2000 Contingency Planning department to oversee and
assist the business groups in the creation of their contingency plans.  The
contingency plans will vary by business group and by the various priority levels
for different systems and equipment.  A schedule has been created to track
progress, which includes participation in the NERC drills scheduled for April
1999 and September 1999.

COSTS:  The Company estimates that total program costs will approximate $33.3
million of which approximately $23.3 million will be expensed and $10 million
will be capitalized.  Total program costs incurred through December 31, 1998 are
$11.6 million of which $8.0 million was expensed and $3.6 million was
capitalized.  The Company expects to fund the total program costs through
operating cash flows.

Over the last several years as the Company implemented various large computer
projects, the Company was conscious of year 2000 exposures and therefore made
sure the projects were year 2000 compliant.  However, these computer projects
were implemented for business reasons rather than to solely comply with year
2000 issues.  These projects included replacing the customer
service/billing/revenue system, as well as implementing a project accounting
system, a computer aided dispatch system, and desktop computers for employees,
among others. Through December 31, 1998, the Company has spent approximately $70
million on these projects in addition to specific year 2000 compliance spending.
The Company has not deferred any significant computer projects as a result of
the year 2000 project.

Certain statements included in this discussion regarding year 2000 compliance
are forward-looking statements as defined in Section 21E of the Securities
Exchange Act of 1934.  These statements include management's best estimates for
completion dates for the various phases and priorities, testing to be performed,
costs to be spent for compliance, and the risks associated with non-compliance
either by the Company or third parties.  These forward-looking statements are
subject to various factors, which may materially affect the Company's efforts
with year 2000 compliance.  Specific factors that might cause such material
differences include, but are not limited to, the availability and cost of
personnel trained in this area, which could cause a change in the estimated
completion date of a particular phase, the ability to locate and correct all
relevant software and embedded components, the compliance of critical vendors,
as well as neighboring utilities, and similar uncertainties.  The Company's
assessments of the effects of year 2000 on the Company are based, in part, upon
information received from third parties and other utilities, and the Company's
reasonable reliance on that information.  Therefore, the risk that inaccurate
information is supplied by third parties and other utilities upon which the
Company reasonably relied must be considered as a risk factor that might affect
the Company's year 2000 efforts.  The Company is attempting to reduce the risks
by utilizing an organized approach, extensive testing, and allowance of ample
contingency time to address issues identified by tests.

                                   1998 STORMS
                                   -----------

In early January 1998, a major ice storm and flooding caused extensive damage in
a large area of northern New York.  The Company's regulated electric
transmission and distribution facilities in an area of approximately 7,000
square miles were damaged, interrupting service to approximately 120,000 of the
Company's customers, or approximately 300,000 people.  The Company had to
rebuild much of its transmission and distribution system to restore power in
this area.  By the end of January 1998, service to all customers was restored.

The total estimated cost of the restoration and rebuild efforts is approximately
$140.5 million.  As of December 31, 1998, the Company expensed $72.9 million
associated with the January 1998 ice storm (of which $62.1 million was
considered incremental) and capitalized $67.6 million of costs as utility plant.

The Company continues to pursue federal disaster relief assistance.  The Company
has submitted claims to its insurance carriers for hydroelectric stations and
substations damages,  and for electric transmission and distribution damages.
In December 1998, the Company received a $2 million advance payment from one of
its insurance carriers.  The Company is unable to determine the total amount of
recoveries it may receive from these sources.

On September 7, 1998 a severe windstorm passed through a portion of the
Company's service territory interrupting electric service to more than 250,000
customers from Niagara Falls to Albany.  Power was restored to the majority of
the customers within one week. The total preliminary estimated cost of
restoration from the September storm is approximately $22.5 million.  However,
final costs of the storm will not be known until all costs and charges are
analyzed and charges from other utilities and contractors have been received.
As of December 31, 1998, the Company recorded $19.2 million in expense (of which
$15.7 million was considered incremental).  The remaining $3.3 million has been
capitalized.  The Company is continuing to inspect and survey the work
completed.  The Company will pursue federal disaster relief assistance for the
September storm.

                              RESULTS OF OPERATIONS
                              ---------------------

The Company experienced a loss in 1998 of $157.4 million or 95 cents per share,
as compared to earnings of $145.9 million, or $1.01 per share, in 1997 and
earnings of $72.1 million, or 50 cents per share, in 1996.

Results for 1998 were negatively impacted by a non-cash write-off of $263.2
million or $1.03 per share associated with the portion of the MRA regulatory
asset disallowed in rates by the PSC and by the regulatory treatment of the MRA
regulatory asset.  (see Master Restructuring Agreement and the POWERCHOICE
Agreement).  With the consummation of the MRA and implementation of POWERCHOICE
effective September 1, 1998, the Company expects reported earnings for the next
five years to be substantially depressed as a result of the regulatory treatment
of the MRA regulatory asset.  (See Item 8. Financial Statements and
Supplementary Data - Note 2. Rate and Regulatory Issues and Contingencies).  The
January 1998 ice storm and the September 1998 windstorm also negatively impacted
1998 earnings by $77.8 million, or 30 cents per share, which reflects the
Company's estimate of incremental, non-capitalized costs to restore power and
rebuild its electric system.  In addition, per share results for the year ended
December 31, 1998 were diluted by the issuance of 42.9 million shares of common
stock in connection with the MRA.

Earnings in 1996 were reduced by an after-tax write-off of $67.4 million, or 47
cents per share, associated with the discontinued application of regulatory
accounting principles to the Company's fossil and hydro generation business.
Largely as a result of the Company's 1996 assessment of the increased risk of
collecting significantly higher levels of past-due customer bills, bad debt
expense in 1996 was higher than in 1997 by $81.1 million, reducing earnings in
1996, compared to 1997, by 37 cents per share.  However, earnings in 1996 were
aided by a $15 million after-tax gain on the sale of a 50 percent interest in
CNP which added 10 cents per share to 1996 earnings.  Industrial customer
discounts not recovered in rates in 1997 exceeded 1996 levels by $25.2 million,
reducing 1997 earnings by 11 cents per share.  In addition, a decline in
higher-margin residential sales also adversely impacted 1997 earnings.  The
lower-margin industrial-special sales (sales by the Company on behalf of NYPA),
as well as, industrial sales increased.  As a result, 1997 total public sales
were essentially the same as sales in 1996.

The Company's 1998 earned ROE was -5.3% as compared to 5.5% in 1997 and 2.8%
(5.4% before extraordinary loss) in 1996.  The Company's ROE authorized in the
1995 or last rate setting process is 11.0% for the electric business and 11.4%
for the regulated gas business.  No specific ROE percentage was established
under POWERCHOICE.

The following discussion and analysis highlights items that significantly
affected primarily the regulated operations during the three-year period ended
December 31, 1998.  This discussion and analysis is not likely to be indicative
of future operations or earnings, particularly in view of the consummation of
the MRA and implementation of POWERCHOICE.  It also should be read in
conjunction with Item 8. Financial Statements and Supplementary Data and other
financial and statistical information appearing elsewhere in this report.

                      REGULATED SEGMENT REVENUES AND SALES
                      ------------------------------------

REGULATED ELECTRIC REVENUES for 1998 were $3,261 million and were $3,309 million
in both 1997 and 1996.  Revenues in 1997 and 1996 were the same in aggregate
with variances between customer groups.

The $48.3 million or 1.5% decrease in 1998 regulated electric revenues was
primarily due to a decrease in volume and mix of sales of $44.4 million along
with rate reductions under POWERCHOICE.  The decrease was partially offset by
increases in sales of energy to other electric systems.  Under POWERCHOICE,
revenues may decline further as customers choose alternative suppliers.
However, the Company will recover stranded costs through the CTC.  See "Master
Restructuring Agreement and the POWERCHOICE Agreement."

During 1997, FAC revenues increased $42.8 million, primarily as a result of the
Company's ability in 1997 to recover increased payments to the IPPs through the
FAC.  However, this increase was offset by a decrease in revenues from sales to
other electric systems and lower electric sales due to warmer weather.

<TABLE>
<CAPTION>

                                    Increase (decrease) from prior year
                                       (In millions of dollars)
REGULATED ELECTRIC REVENUES             1998     1997    Total
---------------------------------       ----     ----    -----
<S>                                <C>         <C>      <C>
Fuel adjustment clause revenues .  $    (4.7)  $ 42.8   $ 38.1 
Changes in volume and mix of
      sales to ultimate consumers      (44.4)   (12.7)   (57.1)
Sales to other electric systems .       11.0    (29.6)   (18.6)
POWERCHOICE rates . . . . . . . .      (10.2)       -    (10.2)
                                   ----------  -------  -------
                                   $   (48.3)  $  0.5   $(47.8)
                                   ==========  =======  =======

</TABLE>

The FAC has been eliminated under the POWERCHOICE agreement.  Changes in FAC
revenues generally were margin-neutral (subject to an incentive mechanism
discussed in Item 8. Financial Statements and Supplementary Data - "Note 1.
Summary of Significant Accounting Policies"), while sales to other utilities,
because of regulatory sharing mechanisms and relatively low prices, generally
resulted in low margin contributions to the Company.  Thus, fluctuations in
these revenue components generally did not have a significant impact on net
operating income.  With POWERCHOICE, the Company is no longer subject to
regulatory sharing mechanisms for sales to other utilities and transmission
revenues.

REGULATED ELECTRIC KILOWATT-HOUR SALES were 36.4 billion in 1998, 37.1 billion
in 1997 and 39.1 billion in 1996.  The 1998 decrease of 0.7 billion KWh, or 1.9%
as compared to 1997, is related primarily to a 4.5% decrease in sales to other
electric systems.  See Item 8. Financial Statements and Supplementary Data
-"Regulated Electric and Gas Statistics - Regulated Electric Statistics."
Sales to ultimate consumers also decreased in 1998 primarily due to warmer
weather during the winter months.  After adjusting for the effects of weather
and the farm and food processor retail access pilot program (which the pilot
program has the effect of reducing sales to ultimate consumers), sales to
ultimate consumers would have expected to increase 0.4%.  The 1997 decrease of
2.0 billion KWh, or 5.1% as compared to 1996, primarily reflects a 31.0%
decrease in sales to other electric systems.

Details of the changes in regulated electric revenues and KWh sales by customer
group are highlighted in the table below:

<TABLE>
<CAPTION>

                                    1998
                                    % OF    % Increase (decrease) from prior year
                                            -------------------------------------
                                  ELECTRIC          1998             1997
CLASS OF SERVICE                  REVENUES   REVENUES  SALES   Revenues   Sales
------------------------------    --------   --------  -----   --------   -----
<S>                                <C>       <C>       <C>     <C>      <C> 
Residential                         36.9     (2.1)     (2.6)    (2.0)     (2.0)
Commercial                          37.4     (1.1)      0.1     (0.3)     (0.1)
Industrial                          14.7     (9.5)     (4.8)     1.2       0.6 
Industrial - Special                 2.0      3.3       1.4      5.8       4.2 
Other                                1.7      1.1       2.6      1.4      (4.5)
                                   -----     -----     -----   ------   -------
   Total to ultimate consumers      92.7     (2.8)     (1.6)    (0.6)        - 
Other electric systems               2.9     13.1      (4.5)   (26.1)    (31.0)
Miscellaneous                        4.4     23.2        -      70.4    (100.0)
                                   -----     -----     -----   ------   -------
   Total                           100.0     (1.5)     (1.9)       -      (5.1)

</TABLE>

As indicated in the table below, REGULATED ELECTRIC FUEL AND PURCHASE POWER
COSTS decreased in 1998 by 12.3% or $173.6 million.  The decrease is mainly the
result of decreased purchases from the IPPs of $321.9 million.  Of this amount,
$80 million relates to net reductions in purchases from IPP Parties for the
period between the closing of the MRA to the POWERCHOICE implementation date,
which were deferred for future rate making disposition because the time lag
between these events was not contemplated in the POWERCHOICE agreement.  The
decrease in IPP purchases is primarily the result of the MRA agreement, which
resulted in the termination of 18 PPAs for 1,092 MW, restatement of eight PPAs
for 535 MW and the amendment of one PPA for 42 MW.  Other purchased power costs
decreased $8.2 million.  As a result, the Company's load requirements were met
to a greater extent from internal sources, which resulted in an increase in fuel
costs of $58.9 million as compared to 1997.

Internal generation decreased 10.1% in 1997 principally due to the outage at
Unit 1 and a reduction in hydroelectric power as a result of lower than normal
precipitation in the summer months.  In 1997, Unit 1 was out of service for 153
days, due to a planned refueling and maintenance outage (which took 68 days) and
for the emergency condenser replacement (which took approximately 85 days) while
in 1996, Unit 2 was out of service for a 36 day planned refueling and
maintenance outage.  The amount of electricity delivered to the Company by the
IPPs decreased by approximately 277 GWh or 2.0%.  However, total IPP costs
increased by approximately $18.0 million or 1.7%.

<PAGE>

                              REGULATED ELECTRIC FUEL AND PURCHASED POWER COSTS
                              -------------------------------------------------

<TABLE>
<CAPTION>
                                                                                            % Change from prior year
                                                                                          ----------------------------
                                       1998            1997                 1996          1998 TO 1997    1997 to 1996
                                       ----            ----                 ----          ------------    ------------
                                  GWH     COST     GWh      Cost        GWh      Cost     GWH    COST     GWh     Cost
                               ---------------------------------------------------------------------------------------
<S>                            <C>     <C>       <C>     <C>          <C>     <C>        <C>     <C>     <C>     <C>
FUEL FOR ELECTRIC GENERATION:
   Coal . . . . . . . . . . .   7,988  $  118.7   7,459  $   106.4     7,095  $  100.6     7.1    11.6     5.1     5.8 
   Oil. . . . . . . . . . . .   1,669      57.1     701       32.2       462      21.1   138.1    77.3    51.7    52.6 
   Natural gas. . . . . . . .     843      23.3     394        8.6       319       9.2   114.0   170.9    23.5    (6.5)
   Nuclear. . . . . . . . . .   7,842      40.0   6,339       33.0     8,243      47.7    23.7    21.2   (23.1)  (30.8)
   Hydro. . . . . . . . . . .   2,694         -   2,905          -     3,679         -    (7.3)      -   (21.0)      - 
                               ------  --------  ------  ---------    ------  --------   ------  ------  ------  ------
                               21,036     239.1  17,798      180.2    19,798     178.6    18.2    32.7   (10.1)    0.9 
                               ------  --------  ------  ---------    ------  --------   ------  ------  ------  ------

ELECTRICITY PURCHASED:
IPP's:
   Capacity . . . . . . . . .       -     127.9       -      220.8         -     212.8       -   (42.1)      -     3.8 
   Energy and taxes . . . . .   9,668     656.7  13,520      885.7    13,797     875.7   (28.5)  (25.9)   (2.0)    1.1 
                               ------  --------  ------  ---------    ------  ---------  ------  ------  ------  ------
      Total IPP purchases . .   9,668     784.6  13,520    1,106.5    13,797   1,088.5   (28.5)  (29.1)   (2.0)    1.7 
Other . . . . . . . . . . . .   8,638     122.0   9,421      130.2     9,569     130.6    (8.3)   (6.3)   (1.5)   (0.3)
                               ------  --------  ------  ---------    ------  --------   ------  ------  ------  ------
                               18,306     906.6  22,941    1,236.7    23,366   1,219.1   (20.2)  (26.7)   (1.8)    1.4 
                               ------  --------  ------  ---------    ------  --------   ------  ------  ------  ------

   TOTAL GENERATED AND
      PURCHASED . . . . . . .  39,342   1,145.7  40,739    1,416.9    43,164   1,397.7    (3.4)  (19.1)   (5.6)    1.4 
Fuel adjustment clause. . . .       -      96.3       -       (1.3)        -     (33.3)      -               - 
Losses/Company use. . . . . .   2,910         -   3,603         -      4,037         -   (19.2)      -   (10.8)      - 
                               ------  --------  ------  ---------    ------  --------   ------  ------ -------  ------
                               36,432  $1,242.0  37,136  $ 1,415.6    39,127  $1,364.4    (1.9)  (12.3)   (5.1)    3.8 
                               ======  ========  ======  =========    ======  ========   ======  ======  ======  ======

</TABLE>

The above table presents the total costs for purchased electricity, while
reflecting only fuel costs for Company generation.  Other costs of power
production, such as taxes, other operating expenses and depreciation are
included within other income statement line items.

<PAGE>

The Company's management of its IPP power supply generally divides the projects
into three categories: hydroelectric, "must run" cogeneration and schedulable
cogeneration projects.

There was lower snowfall during the winter months resulting in lower than normal
1998 spring run off.  In addition, the January 1998 ice storm damaged several
hydro generation stations.  As a result, hydroelectric IPP projects delivered 56
GWh or 3.7% less under PPAs than they did for the same period last year,
representing decreased payments to those IPPs of $1.7 million.

A substantial portion of the Company's portfolio of IPP projects has
historically operated on a "must run" basis.  This means that they would tend to
run at maximum production levels regardless of the need for or economic value of
the electricity produced.  Output from "must run" cogeneration IPPs was 2,720
GWh or 33.7% lower than produced last year, mainly due to the closing of the MRA
agreement, which terminated or restructured 13 of the largest contracts of this
type.  Separate from the MRA, the Company also bought out two IPP contracts with
intermediate sized cogeneration facilities.  See "Master Restructuring
Agreement and the POWERCHOICE Agreement."

Quantities purchased from schedulable cogeneration IPPs also decreased 1,076 GWh
or 27.5% and payments decreased $119.3 million.  The decrease in payments is
also mainly due to the closing of the MRA Agreement, which either terminated or
amended all but one of these contract types.  See "Master Restructuring
Agreement and the POWERCHOICE Agreement."

REGULATED GAS REVENUES decreased by $91.7 million, or 14.0% in 1998, and
decreased by $24.7 million, or 3.6%, in 1997.  As shown in the table below,
regulated gas revenues decreased in 1998 primarily due to decreased sales to
ultimate customers as a result of the migration of commercial sales customers to
the transportation class and due to warmer weather in the winter months.
Regulated gas revenues were also negatively impacted by the regulated gas
commodity cost adjustment clause ("CCAC").  See "Other Federal and State
Regulatory Initiatives - Future of the Natural Gas Industry."

Regulated gas revenues decreased in 1997 primarily due to decreased sales to
ultimate customers as a result of the migration of commercial sales customers to
the transportation class, decreased spot market sales and a decrease in base
rates of $5.9 million in accordance with the 1996 rate order.  This was
partially offset by higher regulated CCAC recoveries and an increase in revenues
from the transportation of customer-owned gas.

Rates for transported gas (excluding aggregation services) yield lower margins
than gas sold directly by the Company.  Therefore, sales of gas transportation
services have not had a proportionate impact on earnings, particularly in
instances where customers that took direct service from the Company move to a
transportation-only class.  In addition, changes in CCAC revenues are generally
margin- neutral.

<TABLE>
<CAPTION>

                                       Increase (decrease) from prior year
                                            (In millions of dollars)
REGULATED GAS REVENUES                    1998      1997       Total
----------------------                    ----      ----       -----
<S>                                   <C>         <C>        <C>
Base rates . . . . . . . . . . . . .  $     -     $ (5.9)    $  (5.9)
Transportation of customer-owned gas     (1.6)       5.3         3.7 
CCAC revenues. . . . . . . . . . . .    (38.5)      45.3         6.8 
Spot market sales. . . . . . . . . .      2.4      (30.8)      (28.4)
Changes in volume and mix of sales
      to ultimate consumers. . . . .    (54.0)     (38.6)      (92.6)
                                      --------    -------    --------
                                      $ (91.7)    $(24.7)    $(116.4)
                                      ========    =======    ========

</TABLE>

REGULATED GAS SALES, excluding transportation of customer-owned gas and spot
market sales, were 65.0 million Dth in 1998, a 17.3% decrease from 1997.
Regulated gas sales for 1997 decreased 7.3% from 1996.  See Item 8. Financial
Statements and Supplementary Data - "Regulated Electric and Gas Statistics -
Regulated Gas Statistics."  The decrease in 1998 was in all ultimate consumer
classes, primarily due to the warmer weather.  Regulated gas revenues were also
negatively impacted by a decrease in transportation volumes of 24.9 million Dth
or 16.3% to customers purchasing gas directly from producers mainly as a result
of the termination and restatement of the PPAs as part of the MRA.  The
decreases were partially offset by increased spot market sales (sales for
resale), which are generally from higher priced gas available to the Company
and, therefore, yield margins that are substantially lower than traditional
sales to ultimate customers.

Changes in regulated gas revenues and Dth sales by customer group are detailed
in the table below:

<TABLE>
<CAPTION>

                                             1998
                                             % OF   % Increase (decrease) from prior year
                                                    -------------------------------------
                                             GAS            1998               1997
CLASS OF SERVICE                           REVENUES  REVENUES   SALES    Revenues   Sales
------------------------------------       --------  --------   -----    --------   -----
<S>                                         <C>      <C>       <C>       <C>        <C>
Residential                                  66.9    (13.3)    (14.4)      4.5       (2.7)
Commercial                                   19.6    (25.4)    (22.9)     (8.7)     (13.0)
Industrial                                    0.6    (44.8)    (45.5)    (50.9)     (50.1)
                                            -----    ------    ------    ------     ------

Total to ultimate consumers                  87.1    (16.7)    (17.3)     (0.3)      (7.3)
Other gas systems                               -    (46.9)    (39.3)     (5.8)      (6.7)
Transportation of customer-owned gas          9.6     (2.8)    (16.3)     10.5       13.5 
Spot market sales                             1.5     37.9      83.6     (82.9)     (76.6)
Miscellaneous                                 1.8    155.7       -       263.1          - 
                                            -----    ------    ------    ------     ------
Total                                       100.0    (14.0)    (15.6)     (3.6)       1.7 

</TABLE>

The total cost of GAS PURCHASED decreased 21.3% in 1998 and decreased 6.6% in
1997.  The cost fluctuations generally correspond to sales volume changes, as
well as a decrease in gas prices.  The Company sold 4.5, 2.5 and 10.5 million
Dth on the spot market in 1998, 1997 and 1996, respectively.  The total cost of
gas decreased $73.5 million in 1998.  This was the result of a 19.3 million
decrease in Dth purchased and withdrawn from storage for ultimate consumer sales
($71.7 million), a 1.3% decrease in the average cost per Dth purchased ($3.5
million) and a $1.0 million decrease in purchased gas costs and certain other
items recognized and recovered through the CCAC.  These decreases were partially
offset by a $2.7 million increase in Dth purchased for spot market sales.

The total cost of gas decreased $24.4 million in 1997.  This was the result of a
5.3 million decrease in Dth purchased and withdrawn from storage for ultimate
consumer sales ($18.8 million) and a $22.5 million decrease in Dth purchased for
spot market sales, partially offset by a 3.3% increase in the average cost per
Dth purchased ($10.7 million) and a $6.3 million increase in purchased gas costs
and certain other items recognized and recovered through the CCAC.

Through the electric FAC and gas CCAC, costs of fuel, purchased power and gas
purchased, above or below the levels allowed in approved rate schedules, are
billed or credited to customers.  In the past, the Company's electric FAC
provided for a partial pass-through of fuel and purchased power cost
fluctuations from those forecast in rate proceedings, with the Company absorbing
a portion of increases or retaining a portion of decreases to a maximum of $15
million per rate year.  The Company absorbed losses of approximately $1.4
million and $13.1 million in 1996 and 1997,  and $11.0 million for the first
eight months in 1998, respectively.  Effective September 1, 1998, under
POWERCHOICE, the electric FAC has been eliminated.  The Company does not believe
that the elimination of the electric FAC will have a material adverse effect on
its financial condition, as a result of its management of (1) power supplies
provided through: (i) the operation of its own power plants, and future power
purchase arrangements as part of the auction of the fossil and hydro assets;
(ii) fixed price and quantity power purchases from NYPA and remaining IPPs; and
(iii) fixed and indexed swap arrangements with IPP Parties; and (2) the transfer
of the risk associated with electricity commodity prices to the customer through
implementation of retail access included in the POWERCHOICE agreement.

OTHER OPERATION AND MAINTENANCE EXPENSE increased in 1998 by $102.5 million, or
12.3%, as compared to a decrease of $92.9 million or 10% in 1997.  The increase
in 1998 is primarily the result of costs associated in the 1998 storms (see
"1998 Storms") and increased nuclear costs of $8 million mostly due to the
extended Unit 2 refueling outage.  Other operation and maintenance expense
decreased in 1997 mainly due to lower bad debt expense.  During 1996, the
Company changed its method of assessing uncollectible customer accounts to give
greater recognition to the increased risk of collecting past due customer bills,
which resulted in significantly higher bad debt expense recognition in 1996 as
compared to 1997.  Bad debt expense was $127.6 million, $46.5 million and $31.7
million in 1996, 1997 and 1998, respectively.  Other operation and maintenance
expense also decreased in 1997 as a result of a reduction in administrative and
general expenses of $15.8 million, primarily due to a reduction in legal costs.

OTHER INCOME increased by $17.6 million in 1998 and decreased by $10.9 million
in 1997.  Other income increased in 1998 mainly due to the deferral of MRA
financing costs, which are reflected in interest charges, due to the delay in
the implementation of POWERCHOICE.  The increase was partially offset by lower
interest income, which reflects the use of cash and also by lower subsidiary
earnings.

Despite higher interest income ($12.0 million) related to increasing cash
balances, OTHER INCOME was lower in 1997, since 1996 reflected a gain on the
sale of a 50% interest in CNP ($15.0 million).

INTEREST CHARGES increased in 1998 by $123.3 million after having remained
fairly constant for the years 1996 and 1997.  The increase in 1998 is mainly due
to the interest charges incurred on the debt issued in connection with the MRA.
Dividends on preferred stock decreased by $0.8 million and $0.9 million in 1998
and 1997, respectively, primarily due to a reduction in preferred stock
outstanding through sinking fund redemptions.  The weighted average long-term
debt interest rate and preferred dividend rate paid, reflecting the actual cost
of variable rate issues, changed to 7.46% and 7.00%, respectively, in 1998 from
7.81% and 7.04%, respectively, in 1997.

FEDERAL AND FOREIGN INCOME TAXES decreased by $193.3 million in 1998 primarily
due to a decrease in pre-tax income and increased by $24.1 million in 1997
primarily due to an increase in pre-tax income.  Other taxes decreased by $11.5
million in 1998 and decreased by $4.4 million in 1997.  The 1998 decrease is
mainly due to a reduction in GRT taxes of $17.6 million primarily due to the
lower sales revenue for the year and due to the GRT credits received for
customers in the Company's service territory that participate in New York
State's Power for Jobs program.  The 1997 decrease was primarily due to lower
payroll taxes ($2.3 million) and lower sales taxes ($0.7 million).

                           EFFECTS OF CHANGING PRICES
                           --------------------------

The Company is especially sensitive to inflation because of the amount of
capital it typically needs and because its prices are regulated using a rate
base methodology that reflects the historical cost of utility plant.

The Company's consolidated financial statements are based on historical events
and transactions when the purchasing power of the dollar was substantially
different than now.  The effects of inflation on most utilities, including the
Company, are most significant in the areas of depreciation and utility plant.
The Company could not replace its utility assets for the historical cost value
at which they are recorded on the Company's books.  In addition, the Company
would not replace these with identical assets due to technological advances and
competitive and regulatory changes that have occurred.  In light of these
considerations, the depreciation charges in operating expenses do not reflect
the cost of providing service if new facilities were installed.  The Company
will seek additional revenue or reallocate resources, if possible, to cover the
costs of maintaining service as assets are replaced or retired.

               FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES
               ---------------------------------------------------

FINANCIAL POSITION.  The Company's capital structure at December 31, 1998 and
1997 was as follows:

<TABLE>
<CAPTION>

         %        1998  1997
----------------  ----  ----
<S>               <C>   <C>
Long-term debt .  64.6  51.8
Preferred stock.   4.9   7.7
Common equity. .  30.5  40.5

</TABLE>

The closing of the MRA has significantly increased the leverage of the Company.
Under the MRA, the Company paid an aggregate of $3.934 billion in cash, of which
$3.212 billion was obtained through a public market offering of senior unsecured
debt, $303.7 million from the public sale of 22.4 million shares of common
stock, and the remainder from cash on hand.  In addition, the Company issued
20.5 million shares of common stock to the IPP Parties.  Through the anticipated
increased operating cash flow resulting from the MRA and POWERCHOICE agreement
and the sale of the generation assets, the planned rapid repayment of debt
should deleverage the Company over time.  Book value of the common stock was
$16.92 per share at December 31, 1998, as compared to $18.89 per share at
December 31, 1997.  With the issuance of common stock at below book value to
the IPP Parties as part of the MRA and the one-time non-cash write-off
associated with the portion of the MRA regulatory asset disallowed in rates by
the PSC, book value per share and earnings per share have been diluted.

The 1998 ratio of earnings to fixed charges was 0.57 times.  The ratios of
earnings to fixed charges for 1997 and 1996 were 2.02 times and 1.57 times,
respectively.  The change in the ratio is primarily due to the consummation of
the MRA, since the MRA and POWERCHOICE agreements will have the effect of
substantially depressing earnings during its five-year term, while at the same
time substantially improving operating cash flows.  The primary result of the
MRA was to convert a large and growing off-balance sheet payment obligation that
threatened the financial viability of the Company into a fixed and more
manageable capital obligation.

The Company's EBITDA for 1998 was approximately $990.5 million.  After the
changes from POWERCHOICE and the MRA are fully reflected in a consecutive
12-month period, EBITDA is expected to increase to approximately $1.2 billion to
$1.3 billion per year.  EBITDA represents earnings before interest charges,
interest income, income taxes, depreciation and amortization, amortization of
nuclear fuel, allowance for funds used during construction, non-cash regulatory
deferrals and other amortizations and extraordinary items.  The ratio of EBITDA
to net cash interest for 1998 was 2.9 times.  Net cash interest is defined as
interest charges plus allowance for funds used during construction less the
non-cash impact of the net amortization of discount on long-term debt and
interest accrued on the Nuclear Waste Policy Act liability less interest income.
The ratio of EBITDA to net cash interest is also expected to improve as the
results of the MRA and POWERCHOICE are fully reflected in a consecutive 12-month
period and the Company reduces its debt.  EBITDA is a non-GAAP measure of cash
flows and is presented to provide additional information about the Company's
ability to meet its future requirements for debt service.  EBITDA should not be
considered an alternative to net income as an indicator of operating performance
or as an alternative to cash flows, as presented on the Consolidated Statement
of Cash Flows, as a measure of liquidity.

COMMON STOCK DIVIDEND.  The Board of Directors omitted the common stock dividend
beginning the first quarter of 1996.  This action was taken to help stabilize
the Company's financial condition and provide flexibility as the Company
addressed growing pressure from mandated power purchases and weaker sales and is
the primary reason for the increase in the cash balance.  In making future
dividend decisions, the Board of Directors will evaluate, along with standard
business considerations, the financial condition of the Company, limitations on
dividend payments under the POWERCHOICE agreement, limitations on common stock
dividends in indenture agreements, the degree of competitive pressure on its
prices, the level of available cash flow and retained earnings and other
strategic considerations.  The Company expects to dedicate a substantial portion
of its future expected positive cash flow to reduce the leverage created in
connection with the implementation of the MRA.  The POWERCHOICE agreement
establishes limits to the annual amount of common stock dividends that can be
paid by the regulated business.  The POWERCHOICE agreement limits the amount of
common stock dividends that can be paid by the regulated company to the holding
company, but does not limit the dividends the holding company may pay to its
shareholders.  The limit under POWERCHOICE is based upon the amount of net
income each year of the regulated company, plus a specified amount ranging from
$50 million in 1998 to $100 million in 2000 and declining thereafter through
2007.  The limitation excludes one-time dividends associated with asset sales.
The dividend limitation is subject to review after the term of the POWERCHOICE
agreement. Furthermore, the Company forecasts that earnings for the five-year
term of the POWERCHOICE agreement will be substantially depressed, as non-cash
amortization of the MRA regulatory asset is occurring and the interest costs on
the IPP debt is the greatest.  See " Master Restructuring Agreement and the
POWERCHOICE Agreement."

CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS.  The Company's total capital
requirements consist of amounts for the Company's construction program (see Item
8. Financial Statements and Supplementary Data - "Note 9. Commitments and
Contingencies - Construction Program,"), nuclear decommissioning funding
requirements (See Item 8. Financial Statements and Supplementary Data - "Note 3.
Nuclear Operations - Nuclear Plant Decommissioning"), working capital needs,
maturing debt issues and sinking fund provisions on preferred stock.  Annual
expenditures for the years 1996 to 1998 for construction and nuclear fuel,
including related AFC and overheads capitalized, were $352.1 million, $290.8
million and $351.2 million, respectively, and are budgeted to be approximately
$300 million for 1999 and to range from $266 - $312 million for each of the
subsequent three years.  Capital expenditures for 1998 increased primarily due
to the costs incurred to rebuild a portion of the Company's regulated electric
transmission and distribution facilities as a result of several storms in 1998
(see "1998 Storms").  The estimate for 1999 and beyond excludes construction
expenditures relating to the fossil and hydro generation assets.

Mandatory debt and preferred stock retirements are expected to add approximately
another $320 million to the 1999 estimate of capital requirements.  In addition,
the Company is obligated to reduce the Senior Debt outstanding by using 85% of
the net proceeds of the sale of the generation assets within 180 days after the
receipt of such proceeds.  As of December 31, 1998, the Company has entered
into agreements for the sale of its hydroelectric and coal-fired generation
assets for $780 million.  It is anticipated that transaction closings will
occur in mid-1999 after receipt of the necessary regulatory approvals.  The
Company is also pursuing the sale of its oil and gas-fired, and nuclear
generation assets.  The Company may also use the positive cash flow generated
as a result of the MRA and the cash tax benefits received as a result of the tax
net operating loss generated from the MRA to further reduce debt.  The estimate
of construction additions included in capital requirements for the period 1999
to 2003 will be reviewed by management to give effect to the overall objective
of further reducing construction spending where possible.  See discussion in
"Liquidity and Capital Resources" section below, which describes how management
intends to meet its financing needs for the five-year period, 1999 to 2003.

LIQUIDITY AND CAPITAL RESOURCES.  External financing plans are subject to
periodic revision as underlying assumptions are changed to reflect developments
and market conditions.  The ultimate level of financing during the period 1999
through 2003 will be affected by, among other things: the cash tax benefits
anticipated because the MRA generated a net tax operating loss carryforward in
1998; the implementation of the POWERCHOICE agreement, levels of common dividend
payments, if any, and preferred dividend payments; the results of the sale of
the Company's generation assets; the Company's competitive position and
the extent to which competition penetrates the Company's markets; potential
future actions with respect to IPPs not covered under the MRA; and uncertain
energy demand due to the weather and economic conditions.  The proceeds of the
sale of the generation assets will be subject to the terms of the Company's
 mortgage indenture and the note indenture that was entered into in connection
 with the MRA debt financing.  The Company could also be affected by the
 outcome of the NRC's consideration of new rules for adequate financial
assurance of nuclear decommissioning obligations.  (See "NRC Policy Statement
and Amended Decommissioning Funding Regulations").  The Company does not
anticipate the need to incur any additional financing in 1999 and expects that
all capital needs can be met internally.  However, the Company may refinance
existing debt to take advantage of lower interest rates.

The Company has an $804 million senior bank financing with a bank group,
consisting of a $255 million term loan facility, a $125 million revolving credit
facility and $424 million for letters of credit.  The letter of credit facility
provides credit support for the adjustable rate pollution control revenue bonds
issued through the NYSERDA.  The interest rate applicable to the senior bank
financing is variable based on certain rate options available under the
agreement and currently approximates 6.5% (but is capped at 15%).  As of
December 31, 1998, the amount outstanding under the senior bank financing was
$529 million, consisting of $105 million under the term loan facility and $424
million of letters of credit, leaving the Company with $275 million of borrowing
capability under the financing.  The Company amended the financing as of June
30, 1998.  The amendment, which included an extension of the term from June 30,
1999 to June 1, 2000, also accommodates the holding company structure and
permits the auction of fossil and hydro generating assets.

This facility is collateralized by first mortgage bonds, which were issued on
the basis of additional property under the earnings test required under the
mortgage trust indenture ("First Mortgage Bonds").  The Company has the ability
to issue First Mortgage Bonds to the extent that there have been redemptions
since June 30, 1998.  The Company redeemed $60 million First Mortgage Bonds in
August 1998.

During November 1998, the Company refinanced its 8-7/8 percent series of
tax-exempt bonds issued through NYSERDA.  The $75 million bonds were refinanced
at 5.15 percent.  The refinancing will reduce interest expense by approximately
$2.8 million per year, not including the costs of issuance.

The Company believes that the closing of the MRA and implementation of
POWERCHOICE will result in substantially depressed earnings during its five-year
term, but will substantially improve operating cash flows.  There is risk that
credit ratings could decline or not increase if the current expectation of
stranded cost recovery is endangered.

In December 1998, the Company received a ruling from the IRS to the effect that
the amount of cash and the value of common stock that was paid to the terminated
IPP Parties will be currently deductible and generate a substantial net
operating loss ("NOL") for federal income tax purposes, such that the Company
will not pay taxes for 1998.  Further, the Company has carried back unused NOL
to the years ended 1996 and 1997, and also for the years 1988 through 1990,
which has resulted in tax refunds of $130 million and $5 million, respectively,
received in January 1999.  In addition, the Company anticipates that it will be
able to utilize the remaining $3.3 billion NOL deductions carried over to future
years before the expiration date in 2019.  The Company's ability to utilize the
NOL generated as a result of the MRA could be limited under the rules of section
382 of the Internal Revenue Code if certain changes in the Company's common
stock ownership were to occur in the future.  In general, the limitation is
triggered by a more than 50% change in stock ownership during a three-year
testing period by shareholders that own, directly or indirectly, 5% or more of
the common stock.  For purposes of making the change in ownership computation,
the IPP Parties who were issued common stock pursuant to the MRA are likely to
be considered a separate 5% shareholder group, as will the purchasers of common
stock in the public offering completed immediately prior to consummation of the
MRA.  Under the computational rules prescribed by applicable Treasury
regulations, the aggregate increase in stock ownership experienced by these
shareholder groups as a result of their participation in the public offering and
the MRA was likely no greater than 17%.  Thus, if the IPP Parties, the
purchasers in the public offering, and any other 5% shareholders collectively
experience ownership increases totaling more than 33% during any three year
testing period that includes the consummation dates of the public offering and
the MRA, the statutory threshold could be breached and the NOL limitation would
in that event apply.  The rules for determining change in stock ownership for
purposes of Code Section 382 are extremely complicated and in many respects
uncertain.  A stock ownership change could occur as a result of circumstances
that are not within the control of the Company.  If a more than 50% change in
ownership were to occur, the Company's remaining usable NOL likely would be
significantly lower in the future than the NOL amount which otherwise would be
usable absent the limitation.  Consequently, the Company's net cash position
could be significantly lower as a result of tax liabilities, which otherwise
would be eliminated or reduced through unrestricted use of the NOL.

During 1995, past due accounts receivable increased significantly.  A number of
factors contributed to the increase, including rising prices (particularly to
residential customers).  Rising prices have been driven by increased payments to
IPPs and high taxes and have been passed on in customers' bills.  The stagnant
economy in the Company's service territory since the early 1990's has adversely
affected collection of past-due accounts.  Also, laws, regulations and
regulatory policies impose more stringent collection limitations on the Company
than those imposed on business in general; for example, the Company faces more
stringent requirements to terminate service during the winter heating season.
In 1996, the Company increased its allowance for doubtful accounts because of
its reassessment of the collection risk associated with residential accounts
receivable and arrears.  Over the last several years, the Company has
implemented a number of collection initiatives that have resulted in lower
arrears levels, and in 1998, the Company lowered its allowance for doubtful
accounts.

The information gathered in developing these strategies enabled management to
update its risk assessment of the accounts receivable portfolio.  Based on this
assessment, management determined in 1996 that the level of risk associated
primarily with the older accounts had increased and the historical loss
experience no longer applied.  Accordingly, the Company determined that a
significant portion of the past-due accounts receivable (principally of
residential customers) might be uncollectible, and wrote-off a substantial
number of these accounts as well as increased its allowance for doubtful
accounts in 1996 and 1997.  In 1998, 1997 and 1996, the Company charged $31.7
million, $46.5 million and $127.6 million, respectively to bad debt expense.
The allowance for doubtful accounts is based on assumptions and judgments as to
the effectiveness of collection efforts.  Future results with respect to
collecting the past-due receivables may prove to be different from those
anticipated.  Although the Company has experienced improvement in collection
efforts, future results are necessarily dependent upon the following factors,
including, among other things, the effectiveness of the strategies implemented
to date, the support of regulators and legislators to allow utilities to move
towards commercial collection practices and improvement in the condition of the
economy in the Company's service territory.  The introduction of competition
requires that policies and practices that were central to traditional
regulation, including those involving collections, be changed so as not to
jeopardize the benefits of competition to customers but not increase collection
risk to the Company.  The Company is actively pursuing these issues before the
PSC.

NET CASH USED IN OPERATING ACTIVITIES increased $3,778.0 million in 1998
primarily due to the consummation of the MRA.

NET CASH USED IN INVESTING ACTIVITIES increased $53.1 million in 1998 primarily
as a result of an increase in the acquisition of utility plant of $98.1 million,
mainly due to the January 1998 ice storm and the September 1998 windstorm.

NET CASH PROVIDED BY FINANCING ACTIVITIES increased $3,573.1 million, primarily
due to the issuance of the senior notes and public sale of common stock used to
consummate the MRA.

<PAGE>

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The financial instruments held or issued by the regulated business are for
purposes other than trading.  The Company's energy marketing subsidiary engages
in both trading and non-trading activities.

Quantitative and qualitative disclosures are discussed by market risk exposure
category:

-     Interest Rate Risk
-     Commodity Price Risk
-     Equity Price Risk
-     Foreign Currency Exchange Risk

      The Company has a foreign currency exchange risk as a result of its
      investments in Canada through its subsidiary Opinac Energy Corporation.
      Translation adjustments due to exchange rate movement across the value of
      the subsidiary is reported in Capitalization as a Foreign Currency
      Translation Adjustment (see "Note 5. - Capitalization") and is a component
      of Comprehensive Income.  See " Consolidated Statements of Comprehensive
      Income."  In aggregate, the risk of loss does not pose a material threat
      to the Company's consolidated results of operations or total
      capitalization.

The Company maintains a Financial Risk Management Policy Manual (the "Policy")
applicable to the regulated company that outlines the parameters within which
corporate managers are to engage in, manage, and report on various areas of risk
exposure.  At the core of the Policy is a condition that the Company will engage
in activities at risk, only to the extent that those activities fall within
commodities and financial markets to which it has a physical market exposure, in
terms and in volumes consistent with its core business.  That core business is
to supply energy, in the form of electricity and natural gas to customers within
the Company's service territory.  The policies of the Company may be revised as
its primary markets continue to change, principally as increased competition is
introduced and the role of the Company in these markets evolves.

The Company's energy marketing subsidiary maintains a separate Risk Management
and Trading Policy Manual that allows for transactions such as marketing and
trading in retail and wholesale, physically and financially settled, energy
based instruments.  These actions expose this subsidiary to a number of risks
such as forward price, deliverability, market liquidity and credit risk.  Like
the Company's Policy, the energy trading policy seeks to assure that risks are
identified, evaluated and actively managed.

INTEREST RATE RISK.  The Company's exposure to changes in interest rates is due
to its financing through a senior debt facility, several series of adjustable
rate promissory notes and adjustable rate preferred stock.  See "Note 5.
Capitalization" and "Note 6. Bank Credit Arrangements."  Under the senior debt
facility, the Company currently has an outstanding term loan of $105 million.
The adjustable rate promissory notes are currently valued at $413.8 million, and
the Company has $122.5 million outstanding in adjustable rate preferred stock.
There is no interest rate cap on the promissory notes.  The interest on the term
loan is variable but capped at 15%.

Dividend rates for the preferred stock are indexed to U.S. government interest
bearing securities plus or minus an amount stipulated in each series and have
floors of 6.5% to 7.0% and caps of between 13.5% and 16.5%.  As of December 31,
1998, the rate calculated on the index for each series is below the floor;
therefore, the current rate is equal to the floor.  Future changes in the
indexed rate will not result in an exposure to higher dividend rates until the
floor is exceeded.  However, for the purposes of the following sensitivity
analysis, a hypothetical one percent increase from the floor dividend rate is
assumed.

The Company also maintains long term debt at fixed interest rates.  A
controlling factor on the exposure to interest rate variations is the mix of
fixed to variable rate instruments maintained by the Company.  All adjustable
rate instruments comprise 6.4% of total capitalization.  The term loan and
promissory notes are 7.7% of total long-term debt, thus limiting Company
exposure to interest rate fluctuations.

If interest rates averaged one percent more in 1999 versus 1998, the Company's
interest expense would increase and income before taxes decrease by
approximately $5.2 million.  This figure was derived by applying the
hypothetical one percent variance across the variable rate debt of $518.8
million at December 31, 1998 (the sum of the term loan and promissory notes).
The same one percent increase in the preferred dividend rate applied against the
outstanding balance of $122.5 million would result in an increase to dividend
payments of $1.2 million, assuming that the indexed rate was between the floor
and cap.  Under POWERCHOICE, prices to customers are fixed for three years, with
limited increases available in years four and five, if justified by the Company.
Changes in the actual cost of capital from levels assumed in POWERCHOICE would
create either exposure or opportunity for the Company until reflected in future
prices.

COMMODITY PRICE RISK.  The Company is exposed to market fluctuations in the
prices for electricity, natural gas, coal, and oil.  The Company, exclusive of
its energy marketing subsidiary, does not, generally, speculate on movements in
the underlying prices for these commodities.  Purchases are based on analyses
performed in relation to fuel needs for power generation and customer delivery
for electricity and natural gas.  Where possible, the Company takes positions in
order to mitigate expected price increases but only to the extent that
quantities are based on expectations of delivery.  The Company attempts to
mitigate exposure through a program that hedges risks as appropriate.

Niagara Mohawk Energy, Inc., a wholly owned subsidiary of the Company, does
engage in both trading and non-trading activities.

Transactions entered into for trading purposes are accounted for on a
mark-to-market basis with changes in fair value recognized as a gain or loss in
the period of change.  At December 31, 1998, there were no open trading
positions.

Activities for non-trading purposes generally consist of transactions entered
into to hedge the market fluctuations of contractual and anticipated
commitments.  Gas futures are used for hedging purposes.  Changes in market
value of futures contracts relating to hedged items are deferred until the
physical transaction occurs, at which time, income or loss is recognized.  The
fair value of open positions for non-trading purposes at December 31, 1998, as
well as the effect of these activities on the Company's results of operations
for the same period ending, was not material.

The fair values of futures and forward contracts are determined using quoted
market prices or broker's quotes.

The commodity risk exposure of Niagara Mohawk Energy, Inc. does not constitute a
material risk of loss to the Company.

The regulated company, as part of the MRA, entered into restated indexed swap
contracts with eight IPPs.  See Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Master Restructuring Agreement
and the POWERCHOICE Agreement for a more detailed discussion of the indexed swap
contracts.

The fair value of the liability under the indexed swap contracts, based upon the
difference between projected future market prices and projected indexed contract
prices applied to the notional quantities and discounted at 8.5% is
approximately $693 million and is recorded on the balance sheet as a liability
for indexed swap contracts.  The discount rate is based upon comparable debt
instruments of the Company.  Based upon the PSC's approval of the restated
contracts, including the indexed swap contracts, as part of the MRA and being
provided a reasonable opportunity to recover the estimated indexed swap
liability from customers, the Company has recorded a corresponding regulatory
asset.  The amount of the recorded liability and regulatory asset is sensitive
to changes in discount rate, anticipated future market prices and changes in the
indices upon which the indexed swap contracts are based.  However, changes in
anticipated future market prices and discount rates will not impact the future
cash flow of the Company when considering the all-in price of the notional
quantities of energy.  Specifically, as market prices rise or fall, payments
under the indexed swap contracts move inversely.  Similarly, changes in discount
rates will not impact the all-in price.  If the indexed contract price were to
increase or decrease by one percent, the Company would see a $15.5 million
increase or decrease in the present value of the projected over-market exposure.
If the market prices were to increase or fall by one percent, the Company would
see a $7.5 million decrease or increase in the projected over-market exposure.
If the discount rate were to increase or decrease to 9.0% or 8.0%, the net
present value of the projected over market exposure would decrease or increase
by approximately $10.5 million.

Under POWERCHOICE, the Company agreed to divest of its fossil generation assets
through an auction process.  As of December 31, 1998, the Company has reached an
agreement to sell its coal-fired generation plants with an anticipated close in
mid-1999.  The Company continues to pursue the sale of its two oil and gas-fired
generation plants.  Central Hudson Gas and Electric Corporation has indicated
that the sale of the Company's share of the Roseton Steam Station is not
expected to close until mid-2000.  The terms of these sales call for the new
owners to take possession of the existing fuel inventory at book value.
Because of these anticipated sales and the level of coal and oil inventory on
hand at December 31, 1998, the Company will not be exposed to any significant
commodity price risks for fuel used in generation in 1999 and beyond.

The Company has an exposure to market price fluctuations for the cost of the
natural gas sold to customers.  The gas prices are most volatile in the winter
months.  The Company has adopted a policy to reduce the variability in gas
costs, primarily over the winter months.  The Company has accomplished this by
limiting or eliminating gas price volatility on four contracts and through the
use of stored gas supplies where the price is already fixed.  These two factors,
as compared to the winter gas needs, allow the Company to reduce or eliminate
volatility on approximately 49% of anticipated demand.

The remaining gas needs of the Company are met through spot market purchases and
are subject to market price fluctuations.  However, the Company has a gas
commodity cost adjustment clause (CCAC) built into its approved rate structure
that limits this risk.  This pricing mechanism calls for a 50/50 sharing,
between customers and stockholders, of the variability between a target price
for gas and actual purchases up to $2.25 million annually.  Variability greater
than $2.25 million accrues to or is borne by the customers.

EQUITY PRICE RISK.  The NRC requires nuclear plant owners to place funds in an
external trust to provide for the cost of decommissioning of the contaminated
portions of nuclear facilities.  See "Note 3. - Nuclear Operations."  The
Company has established qualified and non-qualified trust funds for Unit 1 and
Unit 2.  As of December 31, 1998, these funds were invested in fixed income
securities, domestic equity securities, and cash equivalents.  The fixed income
securities are subject to interest rate fluctuations and the equity securities
to price change in the equity markets.  The funds asset allocation is designed
to maximize returns commensurate with the Company's risk tolerance.

The Company's investment policy for managing the nuclear decommissioning trust
funds conforms to NRC guidelines.  The policy's main objective is to assure that
the growth in the decommissioning funds, together with Company contributions,
will ultimately provide sufficient funds to decommission Units 1 and 2.  This
objective is met by optimizing the return; maintaining a diversified portfolio;
and seeking a return competitive with like institutions employing similar
strategies.

<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A.  FINANCIAL STATEMENTS

-  Report of Management
-  Report of Independent Accountants
-  Consolidated Statements of Income and Retained Earnings for each of the
   three years in the period ended December 31,1998
-  Consolidated Statements of Comprehensive Income for each of the three
   years in the period ended December 31, 1998
-  Consolidated Balance Sheets at December 31, 1998 and 1997
-  Consolidated Statements of Cash Flows for each of the three years in the
   period ended December 31, 1998
-  Notes to Consolidated Financial Statements

<PAGE>

                              REPORT OF MANAGEMENT

The consolidated financial statements of the Company and its subsidiaries were
prepared by and are the responsibility of management.  Financial information
contained elsewhere in this Annual Report is consistent with that in the
financial statements.

To meet its responsibilities with respect to financial information, management
maintains and enforces a system of internal accounting controls, which is
designed to provide reasonable assurance, on a cost effective basis, as to the
integrity, objectivity and reliability of the financial records and protection
of assets.  This system includes communication through written policies and
procedures, an organizational structure that provides for appropriate division
of responsibility and the training of personnel.  This system is also tested by
a comprehensive internal audit program.  In addition, the Company has a
Corporate Policy Register and a Code of Business Conduct (the "Code") that
supply employees with a framework describing and defining the Company's overall
approach to business and require all employees to maintain the highest level of
ethical standards as well as requiring all management employees to formally
affirm their compliance with the Code.

The financial statements have been audited by PricewaterhouseCoopers LLP, the
Company's independent accountants, in accordance with GAAP.  In planning and
performing its audit, PricewaterhouseCoopers LLP considered the Company's
internal control structure in order to determine auditing procedures for the
purpose of expressing an opinion on the financial statements, and not to provide
assurance on the internal control structure. The independent accountants' audit
does not limit in any way management's responsibility for the fair presentation
of the financial statements and all other information, whether audited or
unaudited, in this Annual Report. The Audit Committee of the Board of Directors,
consisting of five outside directors who are not employees, meets regularly with
management, internal auditors and PricewaterhouseCoopers LLP to review and
discuss internal accounting controls, audit examinations and financial reporting
matters.  PricewaterhouseCoopers LLP and the Company's internal auditors have
free access to meet individually with the Audit Committee at any time, without
management being present.





/s/William E. Davis
--------------------
William E. Davis
Chairman of the Board and
Chief Executive Officer
Niagara Mohawk Power Corporation


<PAGE>

                        REPORT OF INDEPENDENT ACCOUNTANTS

To the Stockholders and
Board of Directors of
Niagara Mohawk Power Corporation


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





/s/PricewaterhouseCoopers LLP
-----------------------------
PricewaterhouseCoopers LLP
Syracuse, New York


January 28, 1999

<PAGE>

            NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
             CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

<TABLE>
<CAPTION>



                                                                 For the year ended December 31,
                                                                  1998         1997        1996
                                                                  ----         ----        ----  
                                                                    (In thousands of dollars)
OPERATING REVENUES:
<S>                                                   <C>                   <C>         <C>
    Electric . . . . . . . . . . . . . . . . . . . .  $         3,261,144   $3,309,441  $3,308,979 
    Gas. . . . . . . . . . . . . . . . . . . . . . .              565,229      656,963     681,674 
                                                      --------------------  ----------  -----------
                                                                3,826,373    3,966,404   3,990,653 
                                                      --------------------  ----------  -----------
OPERATING EXPENSES:
    Fuel for electric generation . . . . . . . . . .              239,982      179,455     181,486 
    Electricity purchased. . . . . . . . . . . . . .            1,001,991    1,236,108   1,182,892 
    Gas purchased. . . . . . . . . . . . . . . . . .              272,141      345,610     370,040 
    Other operation and maintenance expenses . . . .              937,798      835,282     928,224 
    POWERCHOICE charge (Note 2). . . . . . . . . . .              263,227            -           - 
    Amortization of the MRA regulatory asset . . . .              128,833            -           - 
    Depreciation and amortization (Note 1) . . . . .              355,417      339,641     329,827 
    Other taxes. . . . . . . . . . . . . . . . . . .              459,961      471,469     475,846 
                                                      --------------------  ----------  -----------
                                                                3,659,350    3,407,565   3,468,315 
                                                      -------------------   ----------  -----------
OPERATING INCOME . . . . . . . . . . . . . . . . . .              167,023      558,839     522,338 
Other income (deductions) (Note 1) . . . . . . . . .               42,602       24,997      35,943 
                                                      --------------------  ----------  -----------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . .              209,625      583,836     558,281 
Interest charges (Note 1). . . . . . . . . . . . . .              397,178      273,906     278,033 
                                                      --------------------  ----------  -----------
INCOME (LOSS) BEFORE FEDERAL AND FOREIGN
    INCOME TAXES . . . . . . . . . . . . . . . . . .             (187,553)     309,930     280,248 
Federal and foreign income taxes (Note 7). . . . . .              (66,728)     126,595     102,494 
                                                      --------------------  ----------  -----------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM. . . . . . .             (120,825)     183,335     177,754 
Extraordinary item for the discontinuance of
   regulatory accounting principles, net of income
   taxes of $36,273 (Note 2) . . . . . . . . . . . .                    -            -     (67,364)
                                                      --------------------  ----------  -----------
NET INCOME (LOSS). . . . . . . . . . . . . . . . . .             (120,825)     183,335     110,390 
Dividends on preferred stock . . . . . . . . . . . .               36,555       37,397      38,281 
                                                      --------------------  ----------  -----------
BALANCE AVAILABLE FOR COMMON STOCK . . . . . . . . .             (157,380)     145,938      72,109 
Retained earnings at beginning of year . . . . . . .              803,420      657,482     585,373 
                                                      --------------------  ----------  -----------
Retained earnings at end of year . . . . . . . . . .  $           646,040   $  803,420  $  657,482 
                                                      ====================  ==========  ===========

AVERAGE NUMBER OF SHARES OF COMMON STOCK
    OUTSTANDING (IN THOUSANDS) . . . . . . . . . . .              166,186      144,404     144,350 
BASIC AND DILUTED EARNINGS (LOSS) PER AVERAGE SHARE
    OF COMMON STOCK BEFORE EXTRAORDINARY ITEM. . . .  $             (0.95)  $     1.01  $     0.97 
EXTRAORDINARY ITEM . . . . . . . . . . . . . . . . .                    -            -       (0.47)
                                                      --------------------  ----------  -----------
BASIC AND DILUTED EARNINGS PER AVERAGE SHARE
   OF COMMON STOCK . . . . . . . . . . . . . . . . .  $             (0.95)  $     1.01  $     0.50 
                                                      ====================  ==========  ===========
</TABLE>

                      CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                               For the year ended December 31,
                                                                 1998          1997       1996
                                                         -----------------  ---------  ---------
                                                                  (In thousands of dollars)
<S>                                                      <C>               <C>        <C>
NET INCOME (LOSS) . . . . . . . . . . . . . . . . . . .  $      (120,825)  $183,335   $110,390 
                                                         ----------------  ---------  ---------
OTHER COMPREHENSIVE INCOME (LOSS):
   Unrealized gains (losses) on securities, net of tax.              304          6       (231)
   Foreign currency translation adjustment. . . . . . .           (6,896)    (4,567)      (708)
                                                         ----------------  ---------  ---------
OTHER COMPREHENSIVE INCOME (LOSS) . . . . . . . . . . .           (6,592)    (4,561)      (939)
                                                         ----------------  ---------  ---------
COMPREHENSIVE INCOME (LOSS) . . . . . . . . . . . . . .  $      (127,417)  $178,774   $109,451 
                                                         ================  =========  =========

</TABLE>

( ) Denotes deduction

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

<PAGE>

            NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>

                                                                                  December 31,
                                                                               1998          1997
                                                                      ----------------  ------------
ASSETS                                                                      (In thousands of dollars)
<S>                                                                   <C>               <C>
UTILITY PLANT (NOTE 1):
         Electric plant. . . . . . . . . . . . . . . . . . . . . . .  $      8,826,650  $ 8,752,865
         Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . .           604,213      577,409
         Gas plant . . . . . . . . . . . . . . . . . . . . . . . . .         1,179,716    1,131,541
         Common plant. . . . . . . . . . . . . . . . . . . . . . . .           349,066      319,409
         Construction work in progress . . . . . . . . . . . . . . .           471,802      294,650
                                                                      ----------------  -----------
                                  TOTAL UTILITY PLANT. . . . . . . .        11,431,447   11,075,874
         Less - Accumulated depreciation and amortization. . . . . .         4,553,488    4,207,830
                                                                      ----------------  -----------
                                  NET UTILITY PLANT. . . . . . . . .         6,877,959    6,868,044
                                                                      ----------------  -----------

OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . . . . .           411,106      371,709
                                                                      ----------------  -----------

CURRENT ASSETS:
         Cash, including temporary cash investments
               of $122,837 and $315,708, respectively. . . . . . . .           172,998      378,232
         Accounts receivable (less allowance for doubtful accounts
               of $47,900 and $62,500, respectively) (Notes 1 and 9)           427,588      492,244
         Materials and supplies, at average cost:
               Coal and oil for production of electricity. . . . . .            42,299       27,642
               Gas storage . . . . . . . . . . . . . . . . . . . . .            38,803       39,447
               Other . . . . . . . . . . . . . . . . . . . . . . . .           118,855      118,308
         Refundable Federal income taxes . . . . . . . . . . . . . .           130,411            -
         Prepaid taxes . . . . . . . . . . . . . . . . . . . . . . .            17,282       15,518
         Other . . . . . . . . . . . . . . . . . . . . . . . . . . .            22,208       20,309
                                                                      ----------------  -----------
                                                                               970,444    1,091,700
                                                                      ----------------  -----------
REGULATORY ASSETS (NOTE 2):
          MRA regulatory asset . . . . . . . . . . . . . . . . . . .         4,045,647        7,516
          Indexed swap contracts regulatory asset. . . . . . . . . .           535,000            -
          Regulatory tax asset . . . . . . . . . . . . . . . . . . .           425,898      399,119
          Deferred finance charges . . . . . . . . . . . . . . . . .                 -      239,880
          Deferred environmental restoration costs (Note 9). . . . .           220,000      220,000
          Unamortized debt expense . . . . . . . . . . . . . . . . .            51,922       57,312
          Postretirement benefits other than pensions. . . . . . . .            52,701       56,464
          Other. . . . . . . . . . . . . . . . . . . . . . . . . . .           137,061      196,533
                                                                      ----------------  -----------
                                                                             5,468,229    1,176,824
                                                                      ----------------  -----------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . .           133,449       75,864
                                                                      ----------------  -----------

                                                                      $     13,861,187  $ 9,584,141
                                                                      ================  ===========

</TABLE>

The accompanying notes are an integral part of these financial statements

<PAGE>

                      NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
                                  CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>

                                                                                           December 31,
                                                                                      1998             1997
                                                                                      ----             ----
CAPITALIZATION AND LIABILITIES                                                     (In thousands of dollars)
<S>                                                                           <C>               <C>
CAPITALIZATION (NOTE 5):
        COMMON STOCKHOLDERS' EQUITY:
             Common stock, issued 187,364,863 and 144,419,351, respectively.  $       187,365   $  144,419 
             Capital stock premium and expense . . . . . . . . . . . . . . .        2,358,380    1,794,739 
             Accumulated other comprehensive income. . . . . . . . . . . . .          (21,643)     (15,051)
             Retained earnings . . . . . . . . . . . . . . . . . . . . . . .          646,040      803,420 
                                                                              ----------------  -----------
                                                                                    3,170,142    2,727,527 

        Non-redeemable preferred stock . . . . . . . . . . . . . . . . . . .          440,000      440,000 
        Mandatorily redeemable preferred stock . . . . . . . . . . . . . . .           68,990       76,610 
        Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . .        6,417,225    3,417,381 
                                                                              ----------------  -----------
             TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . .       10,096,357    6,661,518 
                                                                              ----------------  -----------

CURRENT LIABILITIES:
         Long-term debt due within one year (Note 5) . . . . . . . . . . . .          312,240       67,095 
         Sinking fund requirements on redeemable preferred stock (Note 5). .            7,620       10,120 
         Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . .          197,124      263,095 
         Payable on outstanding bank checks. . . . . . . . . . . . . . . . .           39,306       23,720 
         Customers' deposits . . . . . . . . . . . . . . . . . . . . . . . .           17,148       18,372 
         Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . . . .            6,254        9,005 
         Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . .          132,236       62,643 
         Accrued vacation pay. . . . . . . . . . . . . . . . . . . . . . . .           38,727       36,532 
         Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           91,877       64,756 
                                                                              ----------------  -----------
                                                                                      842,532      555,338 
                                                                              ----------------  -----------

REGULATORY AND OTHER LIABILITIES (NOTE 2):
         Deferred finance charges. . . . . . . . . . . . . . . . . . . . . .                -      239,880 
         Accumulated deferred income taxes (Notes 1 and 7) . . . . . . . . .        1,511,417    1,387,032 
         Employee pension and other benefits (Note 8). . . . . . . . . . . .          235,376      240,211 
         Unbilled revenues (Note 1). . . . . . . . . . . . . . . . . . . . .           30,652       43,281 
         Liability for indexed swap contracts (Note 10). . . . . . . . . . .          693,363            - 
         Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          231,490      236,881 
                                                                              ----------------  -----------
                                                                                    2,702,298    2,147,285 
                                                                              ----------------  -----------
COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 9):
          Liability for environmental restoration. . . . . . . . . . . . . .          220,000      220,000 
                                                                              ----------------  -----------
                                                                              $    13,861,187   $9,584,141 
                                                                              ================  ===========

</TABLE>

The accompanying notes are an integral part of these financial statements

<PAGE>

                     NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
                              CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   INCREASE (DECREASE) IN CASH

<TABLE>
<CAPTION>

                                                                        FOR THE YEAR ENDED DECEMBER 31,
                                                                        1998         1997          1996
                                                                        ----         ----          ----
                                                                            (In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                             <C>               <C>            <C>
Net income (loss) . . . . . . . . . . . . . . . . . . . . . .   $      (120,825)  $ 183,335      $ 110,390
Adjustments to reconcile net income to net cash provided by
 (used in) operating activities:
  POWERCHOICE charge. . . . . . . . . . . . . . . . . . . . . .         263,227           -              -
  Extraordinary item for the discontinuance of regulatory
   accounting principles, net of income taxes . . . . . . . .                 -           -         67,364
  Depreciation and amortization . . . . . . . . . . . . . . . .         355,417     339,641        329,827 
  Amortization of MRA regulatory asset. . . . . . . . . . . . .         128,833           -              -
  Amortization of nuclear fuel. . . . . . . . . . . . . . . . .          30,798      25,241         38,077
  Provision for deferred income taxes . . . . . . . . . . . . .          97,606      46,994         (6,870)
  Gain on sale of subsidiary. . . . . . . . . . . . . . . . . .               -           -        (15,025)
  Unbilled revenues . . . . . . . . . . . . . . . . . . . . . .         (12,629)     (6,600)        21,471
  Net accounts receivable . . . . . . . . . . . . . . . . . . .          64,656    (118,939)       121,198
  Materials and supplies. . . . . . . . . . . . . . . . . . . .         (14,341)     (1,306)         2,265
  Accounts payable and accrued expenses . . . . . . . . . . . .         (38,712)    (11,175)         8,224
  Accrued interest and taxes. . . . . . . . . . . . . . . . . .          66,842       4,180        (11,750)
  MRA regulatory asset. . . . . . . . . . . . . . . . . . . . .      (3,959,508)     (7,516)             -
  Refundable Federal income taxes . . . . . . . . . . . . . . .        (130,411)          -              -
  Changes in other assets and liabilities . . . . . . . . . . .          28,592      83,720         35,231
                                                                ----------------  ----------     ---------
     NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES.            (3,240,455)    537,575        700,402
                                                                ----------------  ----------     ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
 Construction additions. . . . . . . . . . . . . . . . . . . . .       (365,396)   (286,389)      (296,689)
 Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . . . .        (26,804)     (4,368)       (55,360)
 Less: Allowance for other funds used during construction. . . .          8,626       5,310          3,665
                                                                ----------------  ----------     ----------
 Acquisition of utility plant. . . . . . . . . . . . . . . . . .       (383,574)   (285,447)      (348,384)
 Materials and supplies related to construction. . . . . . . . .           (219)      1,042          8,362
 Accounts payable and accrued expenses related to construction .         (9,678)     (2,794)         2,056
 Other investments . . . . . . . . . . . . . . . . . . . . . . .        (35,069)   (115,533)           541
 Proceeds from sale of subsidiary (net of cash sold) . . . . . .              -           -              -
 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        (18,551)      8,761         (8,786)
                                                                ----------------  ----------     ----------
     NET CASH USED IN INVESTING ACTIVITIES. . . . . . . .              (447,091)   (393,971)      (331,611)
                                                                ----------------  ----------     ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
 Issuance of common stock. . . . . . . . . . . . . . . . . . . .        316,389           -              -
 Proceeds from long-term debt. . . . . . . . . . . . . . . . . .      3,361,178           -        105,000
 Reductions of preferred stock . . . . . . . . . . . . . . . . .        (10,120)     (8,870)       (10,400)
 Reductions in long-term debt. . . . . . . . . . . . . . . . . .       (135,000)    (44,600)      (244,341)
 Dividends paid. . . . . . . . . . . . . . . . . . . . . . . . .        (36,555)    (37,397)       (38,281)
 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        (13,580)         97         (8,846)
                                                                ----------------  ----------     ----------
     NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES.             3,482,312     (90,770)      (196,868)
                                                                ----------------  ----------     ----------
NET INCREASE (DECREASE) IN CASH . . . . . . . . . . . . . . . .        (205,234)     52,834        171,923
Cash at beginning of period . . . . . . . . . . . . . . . . . .         378,232     325,398        153,475
                                                                ----------------  ----------     ----------
CASH AT END OF PERIOD . . . . . . . . . . . . . . . . . . . .   $       172,998   $ 378,232      $ 325,398
                                                                ================  ==========     ==========

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
 Interest paid . . . . . . . . . . . . . . . . . . . . . . . . .$       315,541   $ 279,957      $ 286,497
 Income taxes paid (refunded). . . . . . . . . . . . . . . . . .$       (12,127)  $  82,331      $  95,632

SUPPLEMENTAL SCHEDULE OF NONCASH FINANCING ACTIVITIES:
 Issued 20,546,264 shares of common stock, valued at $14.75 per
 share to the IPP Parties on June 30, 1998 or $303.1 million

</TABLE>

The accompanying notes are an integral part of these financial statements

<PAGE>

Notes to Consolidated Financial Statements

NOTE 1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Company is subject to regulation by the PSC and FERC with respect to its
rates for service under a methodology, which establishes prices, based on the
Company's cost.  The Company's accounting policies conform to GAAP, including
the accounting principles for rate-regulated entities with respect to the
Company's nuclear, transmission, distribution and gas operations (regulated
business), and are in accordance with the accounting requirements and ratemaking
practices of the regulatory authorities.  The Company discontinued the
application of regulatory accounting principles to its fossil and hydro
generation operations in 1996 (see Note 2).  In order to be in conformity with
GAAP, management is required to use estimates in the preparation of the
Company's financial statements.

PRINCIPLES OF CONSOLIDATION:  The consolidated financial statements include the
Company and its wholly owned subsidiaries.  Inter-company balances and
transactions have been eliminated.

UTILITY PLANT:  The cost of additions to utility plant and replacements of
retirement units of property are capitalized.  Cost includes direct material,
labor, overhead and AFC.  Replacement of minor items of utility plant and the
cost of current repairs and maintenance are charged to expense.  Whenever
utility plant is retired, its original cost, together with the cost of removal,
less salvage, is charged to accumulated depreciation.  The discontinuation of
SFAS No. 71 to the fossil and hydro operations did not affect the carrying value
of the Company's utility plant.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION:  The Company capitalizes AFC in
amounts equivalent to the cost of funds devoted to plant under construction for
its regulated business.  AFC rates are determined in accordance with FERC and
PSC regulations.  The AFC rate in effect during 1998 was 9.19%.  AFC is
segregated into its two components, borrowed funds and other funds, and is
reflected in the "Interest charges" and "Other income" sections, respectively,
of the Consolidated Statements of Income.  The amount of AFC credits recorded in
each of the three years ended December 31, in thousands of dollars, was as
follows:

<TABLE>
<CAPTION>

                   1998     1997    1996
                  -------  ------  ------
<S>               <C>      <C>     <C>
Other income . .  $ 8,626  $5,310  $3,665
Interest charges   10,228   4,396   3,690

</TABLE>

As a result of the discontinued application of SFAS No. 71 to the fossil and
hydro operations, the Company capitalizes interest cost associated with the
construction of fossil and hydro assets.

DEPRECIATION, AMORTIZATION AND NUCLEAR GENERATING PLANT DECOMMISSIONING COSTS:
For accounting and regulatory purposes, depreciation is computed on the
straight-line basis using the license lives for nuclear and hydro classes of
depreciable property and the average service lives for all other classes.  The
percentage relationship between the total provision for depreciation and average
depreciable property was approximately 3.4% to 3.5% for the years 1996 through
1998.  The Company performs depreciation studies to determine service lives of
classes of property and adjusts the depreciation rates when necessary.

Estimated decommissioning costs (costs to remove a nuclear plant from service in
the future) for the Company's Unit 1 and its share of Unit 2 are being accrued
over the service lives of the units, recovered in rates through an annual
allowance and currently charged to operations through depreciation.  The Company
expects to commence decommissioning of both units shortly after cessation of
operations at Unit 2 (currently planned for 2026), using a method which removes
or decontaminates the Units' components promptly at that time.  See Note 3. -
"Nuclear Plant Decommissioning."

The Company currently recognizes the liability for nuclear decommissioning over
the service life of the plant as an increase to accumulated depreciation and
does not recognize the closure or removal obligation associated with its fossil
and hydro plants.  The Company's POWERCHOICE agreement provides for the recovery
of nuclear decommissioning costs.  As discussed in Note 2, the Company is in the
process of selling its fossil and hydro generating assets through an auction
process.  In addition, the Company has announced plans to pursue the sale of its
nuclear assets (see Note 3).

Amortization of the cost of nuclear fuel is determined on the basis of the
quantity of heat produced for the generation of electric energy.  The cost of
disposal of nuclear fuel, which presently is $.001 per KWh of net generation
available for sale, is based upon a contract with the DOE.  These costs are
charged to operating expense.

REVENUES:  Revenues are based on cycle billings rendered to certain customers
monthly and others bi-monthly.  The Company accrues the estimated revenue
associated with energy consumed and not billed at the end of the fiscal period.
The unbilled revenues included in accounts receivable at December 31, 1998 and
1997 were $205.6 million and $211.9 million, respectively.

In accordance with regulatory practice, accrued unbilled revenues are not
recognized in results of operations until authorized and may be used to reduce
future revenue requirements.  Such amounts are included in "Other Liabilities"
pending regulatory disposition.  Under the POWERCHOICE agreement, $8.6 million
of unrecognized unbilled electric revenues as of the implementation date of
POWERCHOICE were netted with certain other regulatory assets and liabilities and
subsequent changes in the estimated unbilled electric revenues are recognized
currently in results of operations.  At December 31, 1998 and 1997, $30.7
million and $34.7 million, respectively, of unbilled gas revenues remain
unrecognized in results of operations.

The Company's tariffs include electric and gas adjustment clauses under which
energy and purchased gas costs, respectively, above or below the levels allowed
in approved rate schedules, are billed or credited to customers.  The Company,
as authorized by the PSC, charges operations for energy and purchased gas cost
variances in the period of recovery.  The PSC has periodically authorized the
Company to make changes in the level of allowed purchased gas costs included in
approved rate schedules.  As a result of such periodic changes, a portion of
purchased gas costs deferred at the time of change would not be recovered or may
be overrecovered under the normal operation of the gas adjustment clause.
However, the Company has been permitted to defer and bill or credit such
portions to customers, through the gas adjustment clause, over a specified
period of time from the effective date of each change.  Under the POWERCHOICE
agreement, the electric fuel adjustment clause was discontinued as of September
1, 1998.

In December 1996, the Company, Multiple Intervenors and the PSC staff reached a
three-year gas settlement that was conditionally approved by the PSC.  The
agreement eliminated the gas adjustment clause and established a gas commodity
cost adjustment clause ("CCAC").  The Company's gas CCAC provides for the
collection or pass back of certain increases or decreases from the base
commodity cost of gas.  The maximum annual risk or benefit to the Company is
$2.25 million.  All savings or excess costs beyond that amount flow to
ratepayers.

FEDERAL INCOME TAXES:  As directed by the PSC, the Company defers any amounts
payable pursuant to the alternative minimum tax rules.  Deferred investment tax
credits are amortized over the useful life of the underlying property.

STATEMENT OF CASH FLOWS:  The Company considers all highly liquid investments,
purchased with a remaining maturity of three months or less, to be cash
equivalents.

EARNINGS PER SHARE:  Basic earnings per share ("EPS") is computed based on the
weighted average number of common shares outstanding for the period.  The number
of options outstanding at December 31, 1998, 1997 and 1996 that could
potentially dilute basic EPS, (but are considered antidilutive for each period
because the options exercise price was greater than the average market price of
common shares), is immaterial.  Therefore, the calculation of both basic and
dilutive EPS are the same for each period.

SEGMENT DISCLOSURE:  For the fiscal year ending December 31, 1998, the Company
adopted Statement of Financial Accounting Standards No. 131 "Disclosures about
Segments of an Enterprise and Related Information."  SFAS No. 131 supersedes
Statement of Financial Accounting Standards No. 14 "Financial Reporting for
Segments of a Business Enterprise," replacing the "industry segment" approach
with the "management" approach.  The management approach requires financial
information to be disclosed for segments whose operating results are reviewed by
the chief operating officer for decisions on resource allocation.  It also
requires related disclosures about products and service, geographic areas and
major customers.  The adoption of SFAS No. 131 did not affect results of
operations or financial position, but did affect the disclosure of segment
information.

DERIVATIVES:  In June 1998, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities."  The new standard requires
companies to record derivatives on the balance sheet as assets or liabilities,
measured at fair value.  Gains or losses resulting from the changes in the
values of the derivatives will be accounted for depending on the use of the
derivative and whether it qualifies for hedge accounting.  The Company will be
required to adopt this standard by fiscal year beginning January 1, 2000.  The
Company has identified the indexed swap contracts (see Note 10. - "Fair Value of
Financial and Derivative Financial Instruments") as derivative instruments and
has recorded a liability at fair value under SFAS No. 80, "Accounting for
Futures Contracts."  These indexed swap contracts qualify as hedges of future
purchase commitments and will continue to under SFAS No. 133.  The Company
continues to assess the applicability of this new standard to other contractual
obligations.

ENERGY TRADING:  The Emerging Issues Task Force of the FASB recently reached a
consensus on Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities."  The Company does not believe that the accounting requirements of
Issue 98-10 will have a significant impact on its financial position or results
of operations.  Niagara Mohawk Energy, Inc., a wholly owned subsidiary of the
Company, engages in trading activities, and such transactions are accounted for
on a mark-to-market basis with changes in fair value recognized as a gain or
loss in the period of change.  The effects of these trading activities on the
Company's 1998 and 1997 results of operations were not material.

COMPREHENSIVE INCOME:  While the primary component of comprehensive income is
the Company's reported net income or loss, the other components of comprehensive
income relate to foreign currency translation adjustments and unrealized gains
and losses associated with certain investments held as available for sale.

RECLASSIFICATIONS:  Certain amounts from prior years have been reclassified on
the accompanying Consolidated Financial Statements to conform with the 1998
presentation.

NOTE 2.  RATE AND REGULATORY ISSUES AND CONTINGENCIES

The Company's financial statements conform to GAAP, including the accounting
principles for rate-regulated entities with respect to its regulated operations.
The Company discontinued application of regulatory accounting principles to the
Company's fossil and hydro generation business as of December 31, 1996, which
resulted in a $103.6 million charge against 1996 income as an extraordinary
non-cash charge.  Substantively, SFAS No. 71 permits a public utility, regulated
on a cost-of-service basis, to defer certain costs, which would otherwise be
charged to expense, when authorized to do so by the regulator.  These deferred
costs are known as regulatory assets, which in the case of the Company are
approximately $5.5 billion at December 31, 1998.  These regulatory assets are
probable of recovery.

Under POWERCHOICE, a regulatory asset was established for the costs of the MRA
and will be amortized over a period generally not to exceed ten years.  The
Company's rates under POWERCHOICE have been designed to permit recovery of the
MRA regulatory asset.  In approving POWERCHOICE, the PSC limited the estimated
value of the MRA regulatory asset that could be recovered, which resulted in a
charge to the second quarter of 1998 earnings of $263.2 million upon the closing
of the MRA.

The Company, as part of the MRA, entered into restated contracts with eight
IPPs.  The contracts have a term of ten years and are structured as indexed swap
contracts where the Company receives or makes payments to the IPP Parties based
upon the differential between the contract price and a market reference price
for electricity.  The Company has recorded the liability for these contractual
obligations and recorded a corresponding regulatory asset since payments under
these restated contracts are authorized under POWERCHOICE.  See Note 10. - "Fair
Value of Financial and Derivative Financial Instruments."

Under POWERCHOICE, the Company's remaining electric business (nuclear generation
and electric transmission and distribution business) will continue to be
rate-regulated on a cost-of-service basis and, accordingly, the Company
continues to apply SFAS No. 71 to these businesses.  Also, the Company's IPP
contracts, including those restructured under the MRA, will continue to be the
obligations of the regulated business.  Under POWERCHOICE, the Company was
required to net certain regulatory assets and liabilities for future ratemaking
consideration and has reflected these changes in its December 31, 1998 balance
sheet.

The EITF of the FASB reached a consensus on Issue No. 97-4 "Deregulation of the
Pricing of Electricity - Issues Related to the Application of SFAS No. 71 and
SFAS No. 101" in July 1997.  EITF 97-4 does not require the Company to earn a
return on regulatory assets that arise from a deregulating transition plan in
assessing the applicability of SFAS No. 71.  The Company believes that the
regulated cash flows to be derived from prices it will charge for electric
service over the next 10 years, including the Competitive Transition Charge
("CTC") assuming no unforeseen reduction in demand or bypass of the CTC or exit
fees, will be sufficient to recover the MRA Regulatory Asset and to provide
recovery of and a return on the remainder of its assets, as appropriate.  In the
event the Company determines, as a result of lower than expected revenues and/or
higher than expected costs, that its net regulatory assets are not probable of
recovery, it can no longer apply the principles of SFAS No. 71 and would be
required to record an after-tax non-cash charge against income for any remaining
unamortized regulatory assets and liabilities.  If the Company could no longer
apply SFAS No. 71, the resulting charge would be material to the Company's
reported financial condition and results of operations and adversely effect the
Company's ability to pay dividends.

POWERCHOICE requires the Company to divest its portfolio of fossil and hydro
generating assets.  As of December 31, 1998, the Company has agreed to sell its
hydroelectric generating plants and coal-fired stations for $780 million.  These
assets have a total book value of approximately $639 million.  The remaining oil
and gas-fired plants in Albany and Oswego and the Company's 25% ownership in the
Roseton Steam Station have a book value of approximately $411 million.  The
POWERCHOICE agreement provides for deferral and future recovery of net losses,
if any, resulting from the sale of the portfolio.  The Company believes that it
will be permitted to record a regulatory asset for any such losses in accordance
with EITF 97-4.  The Company has determined that there is no impairment of this
portfolio of assets.

The Company has recorded the following regulatory assets on its Consolidated
Balance Sheets reflecting the rate actions of its regulators:

MRA REGULATORY ASSET represents the recoverable costs to terminate, restate or
amend IPP Party contracts, which have been deferred and are being amortized and
recovered under the POWERCHOICE agreement.  The MRA Regulatory Asset is being
amortized generally over ten years, beginning September 1, 1998.

REGULATORY TAX ASSET represents the expected future recovery from ratepayers of
the tax consequences of temporary differences between the recorded book bases
and the tax bases of assets and liabilities.  This amount is primarily timing
differences related to depreciation.  These amounts are amortized and recovered
as the related temporary differences reverse.  In January 1993, the PSC issued a
Statement of Interim Policy on Accounting and Ratemaking Procedures that
required adoption of SFAS No. 109 on a revenue-neutral basis.

INDEXED SWAP CONTRACT REGULATORY ASSET represents the fair value of the
difference between estimated future market prices and the indexed contract
prices for the notional quantities of power in the restated PPA contracts.  In
accordance with the MRA, this asset will be amortized over ten years ending in
June 2008, as notional quantities are settled.  The amount of this regulatory
asset will fluctuate as estimates of future market and contract prices change
over the term of the contracts.

DEFERRED ENVIRONMENTAL RESTORATION COSTS represent the Company's share of the
estimated costs to investigate and perform certain remediation activities at
both Company-owned sites and non-owned sites with which it may be associated.
The Company has recorded a regulatory asset representing the remediation
obligations to be recovered from ratepayers.  POWERCHOICE and the Company's gas
settlement provide for the recovery of these costs over the settlement periods.
The Company believes future costs, beyond the settlement periods, will continue
to be recovered in rates.  See Note 9. - "Environmental Contingencies."

UNAMORTIZED DEBT EXPENSE represents the costs to issue and redeem certain
long-term debt securities, which were retired prior to maturity.  These amounts
are amortized as interest expense ratably over the lives of the related issues
in accordance with PSC directives.

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS represent the excess of such costs
recognized in accordance with SFAS No. 106 over the amount received in rates.
In accordance with the PSC policy statement, postretirement benefit costs other
than pensions were phased into rates generally over a five-year period and
amounts deferred are being amortized and recovered over a period of
approximately 15 years.

Substantially all of the Company's regulatory assets described above are being
amortized to expense and recovered in rates over periods approved in the
Company's electric and gas rate cases, respectively.

NOTE 3.  NUCLEAR OPERATIONS

The Company is the owner and operator of the 613 MW Unit 1 and the operator and
a 41% co-owner of the 1,143 MW Unit 2.  The remaining ownership interests are
Long Island Power Authority (LIPA) - 18%; New York State Electric and Gas
Corporation (NYSEG) - 18%; Rochester Gas and Electric Corporation (RG&E) - 14%;
and Central Hudson Gas and Electric Corporation (Central Hudson) - 9%.  Unit 1
was placed in commercial operation in 1969 and Unit 2 in 1988.

In January 1999, the Company announced plans to pursue the sale of its nuclear
assets, which will require approval from the PSC.  The Company is unable to
predict if a sale will occur and the timing of such sale.

At December 31, 1998, the net book value of the Company's nuclear generating
assets was approximately $1.6 billion, excluding the reserve for
decommissioning.  In addition, the Company has other assets of approximately
$0.5 billion.  These assets include the decommissioning trusts and regulatory
assets, primarily due to the deferral of income taxes.

NUCLEAR PLANT DECOMMISSIONING:  The Company's site specific cost estimates for
decommissioning Unit 1 and its ownership interest in Unit 2 at December 31, 1998
are as follows:

<TABLE>
<CAPTION>

                                      Unit 1               Unit 2
                                 -----------------    ----------------
<S>                                    <C>                  <C>
Site Study (year). . . . . .           1995                 1995
End of Plant Life (year) . .           2009                 2026
Radioactive Dismantlement
   to Begin (year) . . . . .           2026                 2028
Method of Decommissioning. .         Delayed               Immediate
                                  Dismantlement          Dismantlement
                                 -----------------     ----------------
Cost of Decommissioning
(in January 1999 dollars). .             In millions of dollars

Radioactive Components . . .           $498                 $207
Non-radioactive Components .            121                   50
Fuel Dry Storage/Continuing
   Care. . . . . . . . . . .             80                   45
                                 -----------------    ----------------
                                       $699                 $302
                                 =================    ================

</TABLE>

The Company estimates that by the time decommissioning is completed, the above
costs will ultimately amount to $1.7 billion and $0.9 billion for Unit 1 and
Unit 2, respectively, using approximately 3.5% as an annual inflation factor.

In addition to the costs mentioned above, the Company expects to incur
post-shutdown costs for plant ramp down, insurance and property taxes.  In 1999
dollars, these costs are expected to amount to $123 million and $65 million for
Unit 1 and the Company's share of Unit 2, respectively.  The amounts will
escalate to $210 million and $190 million for Unit 1 and the Company's share of
Unit 2, respectively, by the time decommissioning is expected to be completed.

NRC regulations require owners of nuclear power plants to place funds into an
external trust to provide for the cost of decommissioning radioactive portions
of nuclear facilities and establish minimum amounts that must be available in
such a trust at the time of decommissioning.  The allowance for Unit 1 and the
Company's share of Unit 2 was approximately $25.2 million, for the year ended
December 31, 1998.  This is $1.5 million higher than 1997 when the NRC minimum
cost requirements were authorized in rates by the PSC.  POWERCHOICE, which was
implemented September 1, 1998, permits rate recovery for all radioactive and
non-radioactive cost components for both units, including post-shutdown costs,
based upon the amounts estimated in the 1995 site specific studies described
above, which are higher than the NRC minimum.  For 1999, the annual
decommissioning allowance will increase to $42 million of which $28 million is
for radioactive components and $14 million is for non-radioactive components.
There is no assurance that the decommissioning allowance recovered in rates will
ultimately aggregate a sufficient amount to decommission the units.  The Company
believes that if decommissioning costs are higher than currently estimated, the
costs would ultimately be included in the rate process.

Decommissioning costs recovered in rates are reflected in "Accumulated
depreciation and amortization" on the balance sheet and amount to $315.5 million
and $266.8 million at December 31, 1998 and 1997, respectively for both units.
Additionally at December 31, 1998, the fair value of funds accumulated in the
Company's external trusts were $192.4 million for Unit 1 and $64.9 million for
its share of Unit 2.  The trusts are included in "Other Property and
Investments."  Earnings on the external trust aggregated $81.1 million through
December 31, 1998, including $27.9 million of unrealized market gains, and,
because the earnings are available to fund decommissioning, have also been
included in "Accumulated depreciation and amortization."  Amounts recovered for
non-radioactive dismantlement are accumulated in an internal reserve fund, which
has an accumulated balance of $51.2 million at December 31, 1998.

NUCLEAR LIABILITY INSURANCE:  The Atomic Energy Act of 1954, as amended,
requires the purchase of nuclear liability insurance from the Nuclear Insurance
Pools in amounts as determined by the NRC.  At the present time, the Company
maintains the required $200 million of nuclear liability insurance.

With respect to a nuclear incident at a licensed reactor, the statutory limit
for the protection of the public under the Price-Anderson Amendments Act of 1988
which is in excess of the $200 million of nuclear liability insurance, is
currently $9.15 billion without the 5% surcharge discussed below.  This limit
would be funded by assessments of up to $83.9 million for each of the 109
presently licensed nuclear reactors in the United States, payable at a rate not
to exceed $10 million per reactor, per year, per incident.  Such assessments are
subject to periodic inflation indexing and to a 5% surcharge if funds prove
insufficient to pay claims.  With the 5% surcharge included, the statutory limit
is $9.6 billion.

The Company's interest in Units 1 and 2 could expose it to a maximum potential
loss, for each accident, of $124.2 million (with 5% assessment) through
assessments of $14.1 million per year in the event of a serious nuclear accident
at its own or another licensed U.S. commercial nuclear reactor.  The amendments
also provide, among other things, that insurance and indemnity will cover
precautionary evacuations, whether or not a nuclear incident actually occurs.

NUCLEAR PROPERTY INSURANCE:  The Nine Mile Point Nuclear Site has $500 million
primary nuclear property insurance with the American Nuclear Insurers (ANI).  In
addition, there is $2.25 billion in excess of the $500 million primary nuclear
insurance with Nuclear Electric Insurance Limited ("NEIL").  The total nuclear
property insurance is $2.75 billion.  NEIL also provides insurance coverage
against the extra expense incurred in purchasing replacement power during
prolonged accidental outages.  The insurance provides coverage for outages for
156 weeks, after a 21- week waiting period.  NEIL insurance is subject to
retrospective premium adjustment under which the Company could be assessed up to
approximately $9.9 million per loss.

LOW LEVEL RADIOACTIVE WASTE:  The Company currently uses the Barnwell, South
Carolina waste disposal facility for low level radioactive waste.  However,
continued access to Barnwell is not assured, and the Company has implemented a
low level radioactive waste management program so that Unit 1 and Unit 2 are
prepared to properly handle interim on-site storage of low level radioactive
waste for at least a ten-year period.

Under the Federal Low Level Waste Policy Amendment Act of 1985, New York State
was required by January 1, 1993 to have arranged for the disposal of all low
level radioactive waste within the state or in the alternative, contracted for
the disposal at a facility outside the state.  To date, New York State has made
no funding available to support siting for a disposal facility.

NUCLEAR FUEL DISPOSAL COST:  In January 1983, the Nuclear Waste Policy Act of
1982 (the "Nuclear Waste Act") established a cost of $.001 per KWh of net
generation for current disposal of nuclear fuel and provides for a determination
of the Company's liability to the DOE for the disposal of nuclear fuel
irradiated prior to 1983.  The Nuclear Waste Act also provides three payment
options for liquidating such liability and the Company has elected to delay
payment, with interest, until the year in which the Company initially plans to
ship irradiated fuel to an approved DOE disposal facility.  Progress in
developing the DOE facility has been slow and it is anticipated that the DOE
facility will not be ready to accept deliveries until at least 2010.  In July
1996, the United States Circuit Court of Appeals for the District of Columbia
ruled that the DOE has an obligation to accept spent fuel from the nuclear
industry by January 31, 1998 even though a permanent storage site would not be
ready by then. The DOE did not appeal this decision.  On January 31, 1997, the
Company joined a number of other utilities, states, state agencies and
regulatory commissions in filing a suit in the U.S. Court of Appeals for the
District of Columbia against the DOE.  The suit requested the court to suspend
the utilities payments into the Nuclear Waste Fund and to place future payments
into an escrow account until the DOE fulfills its obligation to accept spent
fuel.  The DOE did not meet its January 31, 1998 deadline and indicated it was
not obligated to provide a financial remedy for delay.  On November 14, 1997 the
United States Court of Appeals for the District of Columbia Circuit issued a
writ of mandamus precluding DOE from excusing its own delay on the grounds that
it has not yet prepared a permanent repository or interim storage facility.  On
December 11, 1997, 27 utilities, including the Company, petitioned the DOE to
suspend their future payments to the Nuclear Waste Fund until the DOE begins
moving fuel from their plant sites.  The petition further sought permission to
escrow payments to the waste fund beginning in February 1998.  On January 12,
1998, the DOE denied the petition.  In 1998, both the House and the U.S. Senate
passed legislation to reform the federal government's spent nuclear fuel
disposal policy. This legislation authorized DOE to construct an interim spent
fuel storage facility to accommodate acceptance of spent fuel beginning no later
than June 2003.  Additionally, this legislation required the payment of one-time
fees by electric utilities for the disposal of fuel irradiated prior to 1983 to
be paid to the Nuclear Waste Fund no later than September 30, 2001.  However,
this legislation was never sent to the President for approval.  It is expected
that similar legislation will be introduced in 1999.  As of December 31, 1998,
the Company has recorded a liability of $120.2 million for the disposal of
nuclear fuel irradiated prior to 1983.  The Company is unable to predict the
outcome of this matter.

The Company has several alternatives under consideration to provide additional
spent fuel storage facilities, as necessary.  Each alternative will likely
require NRC approval, may require other regulatory approvals and would likely
require incurring additional costs, which the Company has included in its
decommissioning estimates for both Unit 1 and its share of Unit 2.  In May 1998,
the Company requested approval from the NRC to add additional racks in the spent
fuel pool at Unit 1 that will allow almost 50% more spent fuel to be stored in
the pool.  The NRC is expected to make a decision during March 1999.  If
approved, the additional racks will provide Unit 1 with enough spent fuel
storage through the end of Unit 1's licensing period.  The Company does not
believe that the possible unavailability of the DOE disposal facility until 2010
will inhibit operation of either Unit.

NOTE 4.  JOINTLY-OWNED GENERATING FACILITIES

The following table reflects the Company's share of jointly owned generating
facilities at December 31, 1998.  The Company is required to provide its
respective share of financing for any additions to the facilities.  Power output
and related expenses are shared based on proportionate ownership.  The Company's
share of expenses associated with these facilities is included in the
appropriate operating expenses in the Consolidated Statements of Income. Under
POWERCHOICE, the Company will divest all of its fossil and hydro generation
assets with a net book value of $1.1 billion, including its interests in jointly
owned fossil facilities.

<TABLE>
<CAPTION>

                                                       In thousands of dollars
                                   Percent           Utility       Accumulated       Construction
                                  Ownership           Plant       Depreciation     Work In Progress
                           -----------------------  ----------    -------------    -----------------
<S>                                   <C>           <C>           <C>              <C>
ROSETON STEAM STATION
   Units No. 1 and 2 (a).             25            $   96,192    $      57,639    $        740
OSWEGO STEAM STATION
   Unit No. 6 (b) . . . .             76            $  270,316    $     133,678    $        140
NINE MILE POINT NUCLEAR
   Station Unit No. 2 (c)             41            $1,505,319    $     362,003    $      8,239

</TABLE>

(a)  The remaining ownership interests are Central Hudson Gas and Electric
     Corporation ("Central Hudson"), the operator of the plant (35%), and
     Consolidated Edison Company of New York, Inc. (40%).  Output of Roseton
     Units No. 1 and 2, which have a capability of 1,200,000 KW, is shared in
     the same proportions as the cotenants' respective ownership interests.
     Central Hudson intends to sell its generation assets and will include the
     Company's share of Roseton in its sale, which Central Hudson expects to
     conclude in 2000.

(b)  The Company is the operator.  The remaining ownership interest is
     Rochester Gas and Electric ("RG&E") (24%).  Output of Oswego Unit No. 6,
     which has a capability of 850,000 KW, is shared in the same proportions as
     the cotenants' respective ownership interests.  The Company will sell RG&E'
     share in its auction of fossil generation assets.

(c)  The Company is the operator.  The remaining ownership interests are
     Long Island Power Authority ("LIPA") (18%), New York State Electric & Gas
     Corporation ("NYSEG") (18%), RG&E (14%), and Central Hudson (9%).  Output
     of Unit 2, which has a capability of 1,143,000 KW, is shared in the same
     proportions as the cotenants' respective ownership interests.

<PAGE>

NOTE 5. CAPITALIZATION

CAPITAL STOCK

The Company is authorized to issue 250,000,000 shares of common stock, $1 par
value; 3,400,000 shares of preferred stock, $100 par value; 19,600,000 shares of
preferred stock, $25 par value; and 8,000,000 shares of preference stock, $25
par value. The table below summarizes changes in the capital stock issued and
outstanding and the related capital accounts for 1996, 1997 and 1998:

<TABLE>
<CAPTION>

                                                                   Preferred Stock
                                                           ---------------------------------
                                   Common Stock                    $100 par value
                                   $1 Par Value                        Non-
                               Shares       Amount*        Shares   Redeemable*   Redeemable*
---------------------------------------------------------------------------------------------
<S>                          <C>           <C>          <C>         <C>         <C>
DECEMBER 31, 1995. . . . .   144,332,123   $ 144,332    2,358,000   $ 210,000   $   25,800 (a)
Issued . . . . . . . . . .        33,091          33            -           -            - 
Redemptions. . . . . . . .                                (18,000)          -       (1,800)
Unrealized gain (loss) on
   securities (net of tax)
Foreign currency
   translation adjustment
                             -----------   ---------    ---------   ---------   ----------
DECEMBER 31, 1996. . . .     144,365,214   $ 144,365    2,340,000   $ 210,000   $   24,000 (a)
Issued . . . . . . . .            54,137          54            -           -            -
Redemptions. . . . . . . .                                (18,000)          -       (1,800)
Unrealized gain (loss) on
   securities (net of tax)
Foreign currency
   translation adjustment
                             -----------   ---------    ---------   ---------   ----------
DECEMBER 31, 1997. . . .     144,419,351   $ 144,419    2,322,000   $ 210,000   $   22,200 (a)
Issued . . . . . . . . .      42,945,512      42,946            -           -            - 
Redemptions. . . . . . . .                                (18,000)          -       (1,800)   
Unrealized gain (loss) on
   securities (net of tax)
Foreign currency
   translation adjustment
                             -----------   ---------    ---------   ---------   ----------
DECEMBER 31, 1998. . . . .   187,364,863   $ 187,365    2,304,000   $ 210,000   $   20,400 (a)
                             ===========   =========    =========   =========   ==========

                                      Preferred Stock
                              ---------------------------------  Capital Stock      Accumulated
                                       $25 par value              Premium and          Other
                                            Non-                    Expense        Comprehensive
                                Shares    Redeemable*    Redeemable*    (Net)*          Income*
-----------------------------------------------------------------------------------------------
<S>                           <C>          <C>          <C>             <C>           <C>
DECEMBER 31, 1995. . . . .    12,408,005   $ 230,000        80,200 (a)  $1,793,798    $ (9,551)
Issued . . . . . . . . . .            -            -             -             214 
Redemptions. . . . . . . .      (344,000)          -        (8,600)            203
Unrealized gain (loss) on                                                                 (231)
   securities (net of tax)
Foreign currency
   translation adjustment                                                                 (708)
                              ----------   ---------    ----------      ----------    ---------
DECEMBER 31, 1996. . . .      12,064,005   $ 230,000    $   71,600 (a)  $1,794,215    $(10,490)
Issued . . . . . . . .                 -           -             -             426
Redemptions. . . . . . . .      (282,801)          -        (7,070)             98
Unrealized gain (loss) on
   securities (net of tax)                                                                   6
Foreign currency  
   translation adjustment                                                               (4,567)
                              ----------   ---------    ----------      ----------    ---------
DECEMBER 31, 1997. . . .      11,781,204   $ 230,000    $   64,530 (a)  $1,794,739    $(15,051)
Issued . . . . . . . . .               -           -             -         563,540
Redemptions. . . . . . . .      (332,801)          -        (8,320)            101           -
Unrealized gain (loss) on
   securities (net of tax)                                                                 304
Foreign currency
   translation adjustment                                                               (6,896)
                              ----------   ---------    ----------      ---------     ---------
DECEMBER 31, 1998. . . . .    11,448,403   $ 230,000    $   56,210 (a)  $2,358,380    $(21,643)
                              ==========   =========    ==========      ==========    =========

</TABLE>

* In thousands of dollars

(a) Includes sinking fund requirements due within one year.

The cumulative amount of foreign currency translation adjustment at
December 31, 1998 was $ (22,344).

The cumulative amount of unrealized gain on securities at December 31, 1998 was
$ 701.

<PAGE>

NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)

The Company had certain issues of preferred stock, which provide for optional
redemption at December 31, as follows:

<TABLE>
<CAPTION>

                                                     Redemption price
                                                         per share
                         In thousands of dollars       (Before adding
Series         Shares        1998      1997         accumulated dividends)
------         ------    -----------------------    ----------------------
PREFERRED $100 PAR VALUE:
<S>          <C>          <C>       <C>                <C>
    3.40%      200,000    $ 20,000  $ 20,000           $103.50
    3.60%      350,000      35,000    35,000            104.85
    3.90%      240,000      24,000    24,000            106.00
    4.10%      210,000      21,000    21,000            102.00
    4.85%      250,000      25,000    25,000            102.00
    5.25%      200,000      20,000    20,000            102.00
    6.10%      250,000      25,000    25,000            101.00
    7.72%      400,000      40,000    40,000            102.36
PREFERRED $25 PAR VALUE:
    9.50%    6,000,000     150,000   150,000             25.00
Adjustable Rate -
   Series A  1,200,000      30,000    30,000             25.00
   Series C  2,000,000      50,000    50,000             25.00
                           -------   -------
                          $440,000  $440,000
                          ========  ========

</TABLE>

MANDATORILY REDEEMABLE PREFERRED STOCK

At December 31, the Company had certain issues of preferred stock, as detailed
below, which provide for mandatory and optional redemption.  These series
require mandatory sinking funds for annual redemption and provide optional
sinking funds through which the Company may redeem, at par, a like amount of
additional shares (limited to 120,000 shares of the 7.45% series).  The option
to redeem additional amounts is not cumulative.  The Company's five-year
mandatory sinking fund redemption requirements for preferred stock are as
follows:

<TABLE>
<CAPTION>

        Redemption
       Requirements
      (in thousands)
      ---------------
<S>     <C>
1999    $    7,620
2000         7,620
2001         7,620
2002         3,050
2003         3,050

</TABLE>

<TABLE>
<CAPTION>

                                                                                    Redemption price
                                                                                        per share
                                                                                      (Before adding
                                                                                  accumulated dividends)
                                        Shares         In thousands of dollars           Eventual
Series                             1998        1997       1998    1997           1998     Minimum
--------------------------------------------------------------------------------------------------------
<S>                             <C>         <C>        <C>      <C>              <C>      <C>
PREFERRED $100 PAR VALUE:
7.45%                             204,000     222,000  $20,400  $22,200          $101.45  $100.00
PREFERRED $25 PAR VALUE:
7.85%                             548,403     731,204   13,710   18,280            25.00    25.00
8.375%                                  -     100,000        -    2,500                -
   Adjustable Rate-
      Series B . . . . . . . .  1,700,000   1,750,000   42,500   43,750            25.00    25.00
                                                       -------  -------
                                                        76,610   86,730
Less sinking fund requirements                           7,620   10,120
                                                       -------  -------
                                                       $68,990  $76,610
                                                       =======  =======

</TABLE>

LONG-TERM DEBT

Long-term debt at December 31 consisted of the following:
<TABLE>
<CAPTION>

                              In thousands of dollars
Series                        Due      1998       1997
---------------------------------------------------------
<S>                          <C>   <C>         <C>
FIRST MORTGAGE BONDS:
6 1/2%                       1998  $       -   $   60,000
9 1/2%                       2000     150,000     150,000
6 7/8%                       2001     210,000     210,000
9 1/4%                       2001     100,000     100,000
5 7/8%                       2002     230,000     230,000
6 7/8%                       2003      85,000      85,000
7 3/8%                       2003     220,000     220,000
8%                           2004     300,000     300,000
6 5/8%                       2005     110,000     110,000
9 3/4%                       2005     150,000     150,000
7 3/4%                       2006     275,000     275,000
*6 5/8%                      2013      45,600      45,600
9 1/2%                       2021     150,000     150,000
8 3/4%                       2022     150,000     150,000
8 1/2%                       2023     165,000     165,000
7 7/8%                       2024     210,000     210,000
*8 7/8%                      2025        -         75,000
*5.15%                       2025      75,000        -
* 7.2%                       2029     115,705     115,705
                                   ----------  ----------
Total First Mortgage Bonds          2,741,305   2,801,305
                                   ----------  ----------
SENIOR NOTES:
6 1/2%                       1999     300,000       -
7%                           2000     450,000       -
7 1/8%                       2001     400,000       -
7 1/4%                       2002     400,000       -
7 3/8%                       2003     400,000       -
7 5/8%                       2005     400,000       -
7 3/4%                       2008     600,000       -
8 1/2%                       2010     500,000       -
  Unamortized discount
     on 8 1/2% Senior Note           (156,216)
                                   ----------  ----------
   Total Senior Notes               3,293,784       -
                                   ----------  ----------
PROMISSORY NOTES:
   *Adjustable Rate Series due
    2015                              100,000     100,000
    2023                               69,800      69,800
    2025                               75,000      75,000
    2026                               50,000      50,000
    2027                               25,760      25,760
    2027                               93,200      93,200
TERM LOAN AGREEMENT                   105,000     105,000
UNSECURED NOTES PAYABLE:
   Medium Term Notes, Various
    rates, due 2000-2004               20,000      20,000
   Other                              174,462     154,295
    Unamortized premium (discount)    (18,846)     (9,884)
                                   ----------  -----------
      TOTAL LONG-TERM DEBT          6,729,465   3,484,476

   Less long-term debt due
      within one year                 312,240      67,095
                                   ----------  ----------
                                   $6,417,225  $3,417,381
                                   ==========  ==========

</TABLE>

*Tax-exempt pollution control related issues

The Company's long-term debt increased significantly upon the closing of the MRA
on June 30, 1998.  The MRA was largely financed through the Senior Notes.  The
Senior Notes are unsecured obligations of the Company and rank pari passu in
right of payment to its First Mortgage Bonds, the senior bank financing and
unsecured medium term notes.  The Company's ability to make common stock
dividend payments may be restricted under certain covenants of the Senior Notes
relating to fixed charge coverages and operating cash flow as defined in the
indenture.  These restrictions are no longer applicable once the Senior Notes
become rated as investment grade.

In addition, the Company is obligated to use 85% of the net proceeds of the sale
of the generation assets to reduce its senior debt outstanding
within 180 days after the receipt of such proceeds.  As of December 31,1998, the
Company has entered into agreements for the sale of its two largest components
of its fossil and hydroelectric generating portfolio for $780 million.  It is
anticipated that transaction closings will occur in mid-1999 after receipt of
the necessary regulatory approvals.

Several series of First Mortgage Bonds and Promissory Notes were issued to
secure a like amount of tax-exempt revenue bonds issued by NYSERDA.
Approximately $414 million of such securities bear interest at a daily
adjustable interest rate (with a Company option to convert to other rates,
including a fixed interest rate which would require the Company to issue First
Mortgage Bonds to secure the debt) which averaged 3.39 % for 1998 and 3.63% for
1997 and are supported by bank direct pay letters of credit.  Pursuant to
agreements between NYSERDA and the Company, proceeds from such issues were used
for the purpose of financing the construction of certain pollution control
facilities at the Company's generating facilities or to refund outstanding
tax-exempt bonds and notes (see Note 6).  In November 1998, the Company
refinanced its 8-7/8% series of tax exempt bonds issued through NYSERDA at a
rate of 5.15%.

Other long-term debt in 1998 consists of obligations under capital leases of
approximately $26.3 million, a liability to the DOE for nuclear fuel disposal of
approximately $120.2 million and a liability for IPP contract terminations not
related to the MRA of approximately $28.0 million.  The aggregate maturities of
long-term debt for the five years subsequent to December 31, 1998, excluding
capital leases, in millions, are approximately $309, $719, $715, $635 and $705,
respectively and exclude acceleration of debt repayment associated with the sale
of fossil and hydro assets.

NOTE 6.  BANK CREDIT ARRANGEMENTS

The Company has an $804 million senior bank financing with a bank group
consisting of a $255 million term loan facility, a $125 million revolving credit
facility and $424 million for letters of credit.  The letter of credit facility
provides credit support for the adjustable rate pollution control revenue bonds
issued through the NYSERDA, discussed in Note 5.  As of December 31, 1998, the
amount outstanding under the senior bank financing was $529 million, consisting
of $105 million under the term loan facility and $424 million of letters of
credit, leaving the Company with $275 million of borrowing capability under the
financing.  The senior bank financing was amended as of June 30, 1998.  The
amendment, which included an extension of the term from June 30, 1999 to June 1,
2000, also accommodates the holding company structure and permits the auction of
the fossil and hydro generating assets.  In addition, the amendment limits the
annual amount of common stock dividend payments that can be paid by the
regulated business.  The limit is based upon the amount of net income each year,
plus a specified amount ranging from $50 million in 1998 to $100 million in
2000.  The interest rate applicable to the facility is variable based on certain
rate options available under the agreement and currently approximates 6.5% (but
capped at 15%). In addition, the Company's unregulated subsidiaries have an
agreement with banks for letters of credit totaling up to $25 million.  The
Company did not have any short-term debt outstanding at December 31, 1998 and
1997.

NOTE 7.  FEDERAL AND FOREIGN INCOME TAXES

See Note 9 - "Tax Assessments."

Components of United States and foreign income before income taxes:

<TABLE>
<CAPTION>

                                          In thousands of dollars
                                       1998         1997       1996
                                       ----------------------------
<S>                              <C>            <C>        <C>
United States . . . . . . .      $   (206,372)  $315,027   $269,128
Foreign . . . . . . . . . .             8,227     (1,621)    28,522
Consolidating eliminations.            10,592     (3,476)   (17,402)
                                 -------------  ---------  ---------
Income before extraordinary
   item and income taxes. .      $   (187,553)  $309,930   $280,248
                                 =============  ========   =========

</TABLE>

Following is a summary of the components of Federal and foreign income tax and
a reconciliation between the amount of Federal income tax expense reported in
the Consolidated Statements of Income and the computed amount at the statutory
tax rate:

<TABLE>
<CAPTION>

                                           In thousands of dollars
                                           1998      1997      1996
                                    ---------------------------------
COMPONENTS OF FEDERAL AND FOREIGN INCOME TAXES:
<S>                                 <C>            <C>       <C>
Current tax expense:
   Federal. . . . . . . . ..        $   (155,320)  $ 77,565  $ 96,011
   Foreign. . . . . . . .  .                   -          -     3,708
                                    -------------  --------  --------
                                        (155,320)    77,565    99,719
                                    -------------  --------  --------
Deferred tax expense:
   Federal. . . . . . . .                 84,466     47,836       382 *
   Foreign. . . . . . . . . .              4,126      1,194     2,393
                                    -------------  --------  --------
                                          88,592     49,030     2,775
                                    -------------  --------  --------
      Total . . . . . . . . . . .   $    (66,728)  $126,595  $102,494
                                    =============  ========  ========

</TABLE>

*     Does not include the deferred tax benefit of $36,273 in 1996 associated
      with the extraordinary item for the discontinuance of regulatory
      accounting principles.

RECONCILIATION BETWEEN FEDERAL AND FOREIGN INCOME TAXES AND THE TAX COMPUTED AT
PREVAILING U.S. STATUTORY RATE ON INCOME BEFORE INCOME TAXES:

<TABLE>
<CAPTION>

Computed tax                                         $(65,644)  $108,475    $98,087
---------------------------------------------------  ---------  ---------  ---------
<S>                                                  <C>        <C>        <C>
INCREASE (REDUCTION) ATTIBUTABLE TO FLOW-THROUGH OF
   CERTAIN TAX ADJUSTMENTS:

Depreciation. . . . . . . . . . . . . . . . . . . .    20,808     34,926     26,216 
Cost of removal . . . . . . . . . . . . . . . . . .    (7,859)    (8,168)    (8,849)
Allowance for funds used
      during construction . . . . . . . . . . . . .    (4,207)    (2,952)    (1,431)
Expiring foreign tax credits. . . . . . . . . . . .    10,053          -          - 
Pension settlement amortization . . . . . . . . . .    (3,317)    (2,391)    (4,721)
Debt premium & mortgage
      recording tax . . . . . . . . . . . . . . . .    (9,408)        23      1,252 
Deferred investment tax credit
   amortization . . . . . . . . . . . . . . . . . .    (7,454)    (7,454)    (8,018)
Other . . . . . . . . . . . . . . . . . . . . . . .       300      4,136        (42)
                                                     ---------  ---------  ---------
                                                       (1,084)    18,120      4,407 
                                                     ---------  ---------  ---------
Federal and foreign income
   taxes. . . . . . . . . . . . . . . . . . . . . .  $(66,728)  $126,595   $102,494 
                                                     =========  =========  =========

</TABLE>

At December 31, the deferred tax liabilities (assets) were comprised of the
following:

<TABLE>
<CAPTION>

                                        In thousands of dollars
                                          1998            1997
                                   -----------------------------
<S>                                <C>              <C>
Alternative minimum tax . . . . .  $    (82,621)    $  (17,448)
Unbilled revenue. . . . . . . . .       (81,685)       (88,859)
Non-utilized NOL carryforward . .    (1,161,898)             - 
Other . . . . . . . . . . . . . .      (290,035)      (247,438)
                                   -------------    -----------
   Total deferred tax assets. . .    (1,616,239)      (353,745)
                                   -------------    -----------
Depreciation related. . . . . . .     1,292,582      1,358,827
Investment tax credit related . .        76,418         79,858
MRA terminated IPP contracts. . .     1,415,977              -
Other . . . . . . . . . . . . . .       342,679        302,092
                                   -------------    ----------
   Total deferred tax liabilities     3,127,656      1,740,777
                                   ------------     ----------
Accumulated deferred income
   taxes. . . . . . . . . . . . .  $  1,511,417     $1,387,032
                                   ============     ==========

</TABLE>

In December 1998, the Company received a ruling from the IRS to the effect that
the amount of cash and the value of common stock that was paid to the terminated
IPP Parties will be currently deductible and generate a substantial net
operating loss for federal income tax purposes, such that the Company will not
pay federal income taxes for 1998.  Further, the Company has carried back unused
NOL to the years 1996 and 1997, and also for the years 1988 through 1990, which
has resulted in a refund of $130 million and $5 million, respectively, that were
received in January 1999.  In addition, the Company anticipates that it will be
able to utilize the remaining $3.3 billion NOL carryforward prior to its
expiration date in 2019.  The Company's ability to utilize the NOL generated as
a result of the MRA could be limited under the rules of section 382 of the
Internal Revenue Code if certain changes in the Company's common stock ownership
were to occur in the future.

NOTE 8.  PENSION AND OTHER RETIREMENT PLANS

During 1998, the Company's non-contributory defined benefit pension plan
covering substantially all employees was amended to include a cash balance
benefit in which the participant has an account to which amounts are credited
based on qualifying compensation and with interest determined annually based on
average annual 30-year Treasury bond yield.  Supplemental non-qualified,
non-contributory executive retirement programs provide additional defined
pension benefits for certain officers.  In addition, the Company provides
certain contributory health care and life insurance benefits for active and
retired employees and dependents.

The changes in benefit obligations, plan assets and plan funded status for these
pension and other retirement plans as of, and for the year ended December 31,
are summarized as follows:

<TABLE>
<CAPTION>

                                                         (In thousands of dollars)
                                                   Pension Benefits       Other Retirement Benefits
                                                  -------------------     -------------------------
<S>                                       <C>              <C>             <C>         <C>
CHANGE IN BENEFIT OBLIGATION:. . . . . .          1998           1997         1998         1997 
                                                  ----           ----         ----         ----
Benefit obligation at January 1. . . . .  $    1,172,428   $   1,027,781   $ 519,851   $ 470,730 
 Service cost. . . . . . . . . . . . . .          30,430          27,106      14,338      12,255 
 Interest cost . . . . . . . . . . . . .          79,748          74,984      35,338      34,829 
 Benefits paid to participants . . . . .         (75,650)        (57,100)    (32,917)    (28,602)
 Plan amendments . . . . . . . . . . . .          33,694           4,602      (6,579)          - 
 Actuarial (gain) loss . . . . . . . . .          61,547          95,055      17,589      30,639 
                                          ---------------  --------------  ----------  ----------
Benefit obligation at December 31. . . .       1,302,197       1,172,428     547,620     519,851 
                                          ---------------  --------------  ----------  ----------

CHANGE IN PLAN ASSETS:

Fair Value of plan assets at January 1 .       1,304,338       1,159,822     181,101     143,071 
  Contributions. . . . . . . . . . . . .          12,446          12,446       9,466      13,542 
  Net return on plan assets. . . . . . .         198,943         188,239      19,479      24,488 
  Benefits paid to participants. . . . .         (69,215)        (56,169)          -           - 
                                          ---------------  --------------  ----------  ----------
Fair value of plan assets at December 31       1,446,512       1,304,338     210,046     181,101 
                                          ---------------  --------------  ----------  ----------

Funded status. . . . . . . . . . . . . .         144,315         131,910    (337,574)   (338,750)
Unrecognized initial obligation. . . . .          16,887          19,446     152,460     163,350 
Unrecognized net gain from actual return
  on plan assets . . . . . . . . . . . .        (360,450)       (265,100)          -           - 
Unrecognized net loss (gain) from past
  experience different from that assumed          41,914         (19,920)     55,335      48,840 
Unrecognized prior service cost. . . . .          79,269          50,473     (27,532)    (30,460)
                                          ---------------  --------------  ----------  ----------
Benefits liability on the consolidated
  balance sheet. . . . . . . . . . . . .  $      (78,065)  $     (83,191)  $(157,311)  $(157,020)
                                          ===============  ==============  ==========  ==========

</TABLE>

The non-qualified executive pension plan has no plan assets due to the nature of
the plan, and therefore, has an accumulated benefit obligation in excess of plan
assets of $8,816 and $6,243 at December 31, 1998 and 1997, respectively.

The following table summarizes the components of the net annual benefit costs.

<TABLE>
<CAPTION>

                                                 (In thousands of dollars)
                                     Pension Benefits            Other Retirement Benefits
                        -------------------------------------   ---------------------------
                              1998         1997       1996       1998       1997       1996
                        -------------------------------------------------------------------
<S>                     <C>           <C>          <C>        <C>        <C>        <C>
Service Cost . . . . .  $    30,430   $   27,106   $ 24,951   $ 14,338   $ 12,255   $12,935 
Interest Cost. . . . .       79,748       74,984     71,729     35,338     34,829    37,495 
Expected return
  on plan assets . . .      (95,472)     (84,859)   (78,083)   (16,752)   (13,234)   (8,138)
Amortization of the
  initial obligation .        2,559        2,559      2,559     10,890     10,890    13,507 
Amortization of
  gains and losses . .       (8,408)      (9,226)    (6,540)     8,367      6,967     6,987 
Amortization of prior
  service costs. . . .        4,899        3,892      3,638     (9,508)    (8,745)   (5,830)
                        -----------   ----------   ---------  ---------  ---------  --------

Net benefit cost  (1).  $    13,756   $   14,456   $ 18,254   $ 42,673   $ 42,962   $56,956
                        ===========   ==========   ========   ========   ========   ========

</TABLE>

(1)  A portion of the benefit costs relates to construction labor, and
     accordingly, is allocated to construction projects.

<TABLE>
<CAPTION>

                                         Pension Benefits    Other Retirement Benefits
                                         ----------------    -------------------------
                                         1998     1997           1998      1997
                                         ----     ----           ----      ----
<S>                                      <C>      <C>            <C>       <C>
Weighted-average assumptions
  as of December 31:
    Discount rate . . . . . . . . .      6.75%    7.00%          6.75%     7.00%
    Expected return on plan assets.      9.25     9.25           9.25      9.25 
    Rate of compensation increase
         (plus merit increases) . .      2.50     2.50            N/A       N/A
    Health care cost trend rate:  
         Under age 65 . . . . . . .       N/A      N/A           7.00      7.00 
         Over age 65. . . . . . . .       N/A      N/A           6.00      6.00 

</TABLE>

The assumed health cost trend rates decline to 5% in 2000 and remain at that
level thereafter.  The assumed health cost trend rates can have a significant
effect on the amounts reported for the health care plans.  A
one-percentage-point change in assumed health care cost trend rates would have
the following effects:

<TABLE>
<CAPTION>

                                           1% Increase      1% Decrease
                                           -----------      -----------
<S>                                        <C>              <C>
Effect on total of service and interest
  cost components of net periodic
  postretirement health care benefit cost  $ 2,076          $ (1,799)

Effect on the health care component of
  the accumulated postretirement
  benefit obligation. . . . . . . . . . .   32,906           (28,465)

</TABLE>

The Company recognizes the obligation to provide postemployment benefits if the
obligation is attributable to employees' past services, rights to those benefits
are vested, payment is probable and the amount of the benefits can be reasonably
estimated.  At December 31, 1998 and 1997, the Company's postemployment benefit
obligation is approximately $15.3 million and $13.3 million, respectively.

NOTE 9.  COMMITMENTS AND CONTINGENCIES

LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At January 1, 1999, the
Company had long-term contracts to purchase electric power from the following
generating facilities owned by NYPA:

<TABLE>
<CAPTION>

                                   Expiration   Purchased       Estimated
                                    date of     capacity          annual
Facility                            contract      in MW       capacity cost
---------------------------------------------------------------------------
<S>                                 <C>         <C>           <C>
Niagara - hydroelectric
   project. . . . . . . . . .       2007          951         $27,667,000
St. Lawrence - hydroelectric
   project. . . . . . . . . .       2007          104           1,248,000
Blenheim-Gilboa - pumped
   storage generating station       2002          270           7,452,000
                                                -----         -----------
                                                1,325         $36,367,000
                                                =====         ===========

</TABLE>

The purchase capacities shown above are based on the contracts currently in
effect.  The estimated annual capacity costs are subject to price escalation and
are exclusive of applicable energy charges.  The total cost of purchases under
these contracts was approximately, in millions, $93.1, $91.0 and $93.3 for the
years 1998, 1997 and 1996, respectively.  The Company continues to have a
contract with NYPA's Fitzpatrick nuclear facility to purchase for resale up to
46 MW of power for NYPA's economic development customers.

Under the requirements of PURPA, the Company is required to purchase power
generated by IPPs, as defined therein.  The Company has 118 PPAs with 125
facilities, amounting to approximately 1,125 MW of capacity at December 31,
1998.  All of this amount is considered firm, but excludes PPAs that provide
energy only.  The following table shows the estimated payments for fixed costs
(capacity) and variable costs (capacity, energy and related taxes) the Company
estimates it will be obligated to make under these contracts, excluding the over
market obligation under the indexed swap contracts.  See Note 10. Fair Value of
Financial and Derivative Financial Instruments.  These payments have been
significantly reduced by the consummation of the MRA.  The MRA was consummated
on June 30, 1998 with 14 IPPs.  The MRA allowed the Company to terminate,
restate or amend 27 PPAs which represented approximately three quarters of the
Company's over-market purchase power obligations.  Under the terms of the MRA,
the Company terminated 18 PPAs representing 1,092 MW of electric generating
capacity, restated eight PPAs representing 535 MW of capacity and amended one
PPA representing 42 MW of capacity. In addition, the Company is continuing to
actively pursue other opportunities to reduce payments to IPPs that were not a
party to the MRA.

The payments are subject to the tested capacity and availability of the
facilities, scheduling and price escalation.

<TABLE>
<CAPTION>

                        (In thousands of dollars)
               Fixed Costs      Variable Costs
                                  Capacity,
Year           Capacity       Energy and Taxes   Total
------------------------------------------------------
<S>            <C>            <C>                <C>
1999           $  13,456      $  392,029         $405,485
2000              13,793         412,177          425,970
2001              13,989         413,482          427,471
2002              14,288         425,357          439,645
2003              14,635         437,731          452,366

</TABLE>

Fixed capacity costs (in the table above) relate to one 56 MW contract, where
the Company is required to make capacity payments, including payments when the
facility is not operating but available for service.  The terms of this contract
allows the Company to schedule energy deliveries and then pay for the energy
delivered. Contracts relating to the remaining facilities in service at December
31, 1998, require the Company to pay only when energy is delivered, except when
the Company decides that it would be better to pay a particular project a
reduced energy payment to have the project reduce its high priced energy
deliveries.  The Company paid approximately $785 million, $1,106 million and
$1,088 million in 1998, 1997 and 1996 for 9,700,000 MWh, 13,500,000 MWh and
13,800,000 MWh, respectively, of electric power under all IPP contracts.

SALE OF CUSTOMER RECEIVABLES:  The Company has established a single-purpose,
financing subsidiary, NM Receivables LLC, whose business consists of the
purchase and resale of an undivided interest in a designated pool of customer
receivables, including accrued unbilled revenues.  For receivables sold, the
Company has retained collection and administrative responsibilities as agent for
the purchaser.  As collections reduce previously sold undivided interests, new
receivables are customarily sold.  NM Receivables LLC has its own separate
creditors which, upon liquidation of NM Receivables LLC, will be entitled to be
satisfied out of its assets prior to any value becoming available to the
Company.  The sale of receivables are in fee simple for a reasonably equivalent
value and are not secured loans.  Some receivables have been contributed in the
form of a capital contribution to NM Receivables LLC in fee simple for
reasonably equivalent value, and all receivables transferred to NM Receivables
LLC are assets owned by NM Receivables LLC in fee simple and are not available
to pay the parent Company's creditors.

At December 31, 1998 and 1997, $150 million and $144.1 million, respectively, of
receivables had been sold by NM Receivables LLC to a third party.  The undivided
interest in the designated pool of receivables was sold with limited recourse.
The agreement provides for a formula based loss reserve pursuant to which
additional customer receivables are assigned to the purchaser to protect against
bad debts.  At December 31, 1998, the amount of additional receivables assigned
to the purchaser, as a loss reserve, was approximately $40.0 million.

To the extent actual loss experience of the pool receivables exceeds the loss
reserve, the purchaser absorbs the excess. Concentrations of credit risk to the
purchaser with respect to accounts receivable are limited due to the Company's
large, diverse customer base within its service territory.  The Company
generally does not require collateral, i.e., customer deposits.

TAX ASSESSMENTS:  The Internal Revenue Service ("IRS") conducted an examination
of the Company's federal income tax returns for the years 1989 and 1990 and
issued a Revenue Agents' Report (RAR).  The IRS raised an issue concerning the
deductibility of payments made to IPPs in accordance with certain contracts that
include a provision for a tracking account.  In late November 1998, the Company
received a final settlement letter from the IRS allowing the deduction of these
IPP payments.  The IRS also conducted an examination of the Company's federal
income tax returns for the years 1991 through 1993 and issued an RAR in the
second quarter of 1998.  Based upon the Company's review of the report, the
Company does not believe that the findings will have a material impact on its
financial position or results of operation.

ENVIRONMENTAL CONTINGENCIES:  The public utility industry typically utilizes
and/or generates in its operations a broad range of hazardous and potentially
hazardous wastes and by-products.  The Company believes it is handling
identified wastes and by-products in a manner consistent with federal, state and
local requirements and has implemented an environmental audit program to
identify any potential areas of concern and aid in compliance with such
requirements.  The Company is also currently conducting a program to investigate
and remediate, as necessary to meet current environmental standards, certain
properties associated with former gas manufacturing and other properties which
the Company has learned may be contaminated with industrial waste, as well as
investigating identified industrial waste sites as to which it may be determined
that the Company contributed.  The Company has also been advised that various
federal, state or local agencies believe certain properties require
investigation and has prioritized the sites based on available information in
order to enhance the management of investigation and remediation, if necessary.

The Company is currently aware of 136 sites with which it has been or may be
associated, including 82 which are Company-owned.  With respect to non-owned
sites, the Company may be required to contribute some proportionate share of
remedial costs.  Although one party can, as a matter of law, be held liable for
all of the remedial costs at a site, regardless of fault, in practice costs are
usually allocated among PRPs. The Company has denied any responsibility at
certain of these PRP sites and is contesting liability accordingly.

Investigations at each of the Company-owned sites are designed to (1) determine
if environmental contamination problems exist, (2) if necessary, determine the
appropriate remedial actions and (3) where appropriate, identify other parties
who should bear some or all of the cost of remediation.  Legal action against
such other parties will be initiated where appropriate.  After site
investigations are completed, the Company expects to determine site-specific
remedial actions and to estimate the attendant costs for restoration.  However,
since investigations are ongoing for most sites, the estimated cost of remedial
action is subject to change.

Estimates of the cost of remediation and post-remedial monitoring are based upon
a variety of factors, including identified or potential contaminants; location,
size and use of the site; proximity to sensitive resources; status of regulatory
investigation and knowledge of activities at similarly situated sites.
Additionally, the Company's estimating process includes an initiative where
these factors are developed and reviewed using direct input and support obtained
from the DEC. Actual Company expenditures are dependent upon the total cost of
investigation and remediation and the ultimate determination of the Company's
share of responsibility for such costs, as well as the financial viability of
other identified responsible parties since clean-up obligations are joint and
several.

As a consequence of site characterizations and assessments completed to date and
negotiations with PRPs, the Company has accrued a liability in the amount of
$220 million, which is reflected in the Company's Consolidated Balance Sheets at
December 31, 1998.  The potential high end of the range is presently estimated
at approximately $710 million, including approximately $340 million in the
unlikely event the Company is required to assume 100% responsibility at
non-owned sites.  The amount accrued at December 31, 1998, incorporates a method
to estimate the liability for 22 of the Company's largest sites, which relies
upon a decision analysis approach.   This method includes developing several
remediation approaches for each of the 22 sites, using the factors previously
described, and then assigning a probability to each approach.  The probability
represents the Company's best estimate of the likelihood of the approach
occurring using input received directly from the DEC.  The probable costs for
each approach are then calculated to arrive at an expected value. While this
approach calculates a range of outcomes for each site, the Company has accrued
the sum of the expected values for these sites.  The amount accrued for the
Company's remaining sites is determined through feasibility studies or
engineering estimates, the Company's estimated share of a PRP allocation or
where no better estimate is available, the low end of a range of possible
outcomes is used.  In addition, the Company has recorded a regulatory asset
representing the remediation obligations to be recovered from ratepayers.
POWERCHOICE provides for the continued application of deferral accounting for
cost differences resulting from this effort.

In October 1997, the Company submitted a draft feasibility study to the DEC,
which included the Company's Harbor Point site and five surrounding non-owned
sites.  The study indicates a range of viable remedial approaches, however, a
final determination has not been made concerning the remedial approach to be
taken.  This range consists of a low end of $21 million and a high end of $360
million, with an expected value calculation of $56 million, which is included in
the amounts accrued at December 31, 1998.  The range represents the total costs
to remediate the properties and does not consider contributions from other PRPs,
the amount of which the Company is unable to estimate.  The Company has received
comments from the DEC on the draft feasibility study, which will facilitate
completion of the feasibility study phase in the spring of 1999.  At this time,
the Company cannot definitively predict the nature of the DEC proposed remedial
action plan or the range of remediation costs the DEC will require.  While the
Company does not expect to be responsible for the entire cost to remediate these
properties, it is not possible at this time to determine its share of the cost
of remediation.

In May 1995, the Company filed a complaint pursuant to applicable Federal and
New York State law, in the U.S. District Court for the Northern District of New
York against several defendants seeking recovery of past and future costs
associated with the investigation and remediation of the Harbor Point and
surrounding sites.  The New York State Attorney General moved to dismiss the
Company's claims against the state of New York, the New York State Department of
Transportation and the Thruway Authority and Canal Corporation under the
Comprehensive Environmental Response, Compensation and Liability Act.  The
Company opposed this motion.  On April 3, 1998, the Court denied the New York
State Attorney General's motion as it pertains to the Thruway Authority and
Canal Corporation, and granted the motion relative to the state of New York and
the Department of Transportation.  On January 12, 1999, a pre-trial status
conference was convened by the Court.  The Court will be issuing an amended case
management order that is expected to call for the close of discovery by the end
of June 1999 and to establish December 1, 1999 as the trial ready date.  As a
result, the Company cannot predict the outcome of the pending litigation against
the defendants or the allocation of the Company's share of the costs to
remediate the Harbor Point and surrounding sites.

Where appropriate, the Company has provided notices of insurance claims to
carriers with respect to the investigation and remediation costs for
manufactured gas plant, industrial waste sites and sites for which the Company
has been identified as a PRP. The Company has reached settlements with a number
of insurance carriers, resulting in payments to the Company of approximately $39
million, net of costs incurred in pursuing recoveries. This amount is being
amortized in rates generally over a 10-year period.

CONSTRUCTION PROGRAM:  The Company is committed to an ongoing construction
program to assure delivery of its electric and gas services.  The Company
presently estimates that the construction program for the years 1999 through
2002, the period covered under the POWERCHOICE agreement, will require
approximately $981 million, excluding AFC and nuclear fuel.  For the years 1999
through 2002, the estimates, in millions, are $254, $240, $243, and $244,
respectively, which excludes amounts relating to the Company's fossil and hydro
generation assets. On December 3, 1998, the Company announced it had reached an
agreement with an affiliate of Orion Power Holding, Inc. to sell its 72
hydroelectric generating plants and on December 23, 1998, the Company announced
an agreement with NRG Energy, Inc. to sell its Huntley and Dunkirk coal-fired
electric generating stations. It is anticipated that transaction closings will
occur in mid-1999 after receipt of the necessary regulatory approvals.  The
Company continues to pursue the sale of its two oil and gas-fired plants in
Albany and Oswego. The Company is unable to predict the outcome or timing of the
divestiture of its two oil and gas-fired plants.

GAS SUPPLY, STORAGE AND PIPELINE COMMITMENTS:  In connection with its gas
business, the Company has long-term commitments with a variety of suppliers and
pipelines to purchase gas commodity, provide gas storage capability and
transport gas commodity on interstate gas pipelines.  The table below sets forth
the Company's estimated commitments at December 31, 1998, for the next five
years, and thereafter.

<TABLE>
<CAPTION>

                      (In thousands of dollars)
                                       Gas Storage/
Year               Gas Supply           Pipeline
---------------------------------------------------
<S>               <C>                <C>
1999 . . .        $  83,785          $  96,772
2000 . . .           48,939             80,052
2001 . . .           46,565             65,942
2002 . . .           35,272             33,894
2003 . . .           35,272             11,926
Thereafter           99,921             58,474

</TABLE>

With respect to firm gas supply commitments, the amounts are based upon volumes
specified in the contracts giving consideration for the minimum take provisions.
Commodity prices are based on New York Mercantile Exchange quotes and
reservation charges, when applicable.  For storage and pipeline capacity
commitments, amounts are based upon volumes specified in the contracts, and
represent demand charges priced at current filed tariffs.

At December 31, 1998, the Company's firm gas supply commitments extend through
October 2006, while the gas storage and transportation commitments extend
through October 2012.  Beginning in May 1996, as a result of a generic rate
proceeding, the Company was required to implement service unbundling, where
customers could choose to buy natural gas from sources other than the Company.
To date the migration has not resulted in any stranded costs since the PSC has
allowed utilities to assign the pipeline capacity to the customers choosing
another supplier.  This assignment is allowed during a three-year period ending
March 1999.

The PSC issued its Policy Statement in November 1998 concerning the future of
the Natural Gas Industry in New York State and Order Terminating Capacity
Assignment.  The PSC Policy Statement states that utilities may no longer
require capacity assignment or inclusion of capacity costs in transportation
rates beyond April 1, 1999 to customers migrating to marketers except where
specific operational and reliability requirements warrant.

In November 1998, the PSC approved the Company's proposed pilot program that
would, effective December 1, 1998, no longer require assigning pipeline capacity
and related costs upstream of the CNG Transmission System to customers migrating
to transportation.  However, the Company's proposed pilot program sought to
continue to assign capacity on the CNG system until October 31, 1999, the
expiration date of its current gas rate settlement agreement.  A stranded cost
recovery mechanism, in the form of a surcharge, was established to provide for
the recovery of the unassigned pipeline capacity costs until October 31, 1999.

In December 1998, the Company notified the PSC that the Company's specific
operational and reliability requirements continue to warrant certain mandatory
capacity assignment and inclusion of capacity costs in transportation rates
after April 1, 1999.  The PSC noted in its PSC Policy Statement that it will
provide LDCs with a reasonable opportunity to recover these strandable costs if
they can demonstrate compliance with the PSC's directives to minimize such
costs.  The Company believes that it has taken numerous actions to reduce its
capacity obligations and its potential stranded costs, but is unable to predict
the outcome of this matter.  The Company anticipates that this issue will be
addressed in the individual negotiations with the PSC anticipated to begin
during the second quarter of 1999.

NOTE 10.  FAIR VALUE OF FINANCIAL AND DERIVATIVE FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of
each class of financial instruments:

CASH AND SHORT-TERM INVESTMENTS:  The carrying amount approximates fair value
because of the short maturity of the financial instruments.

LONG-TERM DEBT AND MANDATORILY REDEEMABLE PREFERRED STOCK:  The fair value of
fixed rate long-term debt and redeemable preferred stock is estimated using
quoted market prices where available or discounting remaining cash flows at the
Company's incremental borrowing rate.  The carrying value of NYSERDA bonds and
other long-term debt are considered to approximate fair value.

DERIVATIVE FINANCIAL INSTRUMENTS:  The fair value of futures and forward
contracts are determined using quoted market prices and broker quotes.

INDEXED SWAP CONTRACTS: Indexed swap contracts are ten-year financial contracts
where the Company receives or makes payments to certain IPP Parties based upon
the differential between the contract price and a market reference price for
electricity.  The contract prices are fixed for the first two years changing to
an indexed pricing formula primarily related to gas prices, thereafter.
Contract quantities are fixed for each year of the full ten-year term of the
contracts and average 4.1 million MWh.  The indexed pricing structure ensures
that the price paid for energy and capacity will fluctuate relative to the
underlying market cost of gas and general indices of inflation.  At December 31,
1998, the Company projects that it will make the following payments to the IPP
Parties for the years 1999 to 2003:

<TABLE>
<CAPTION>

               Projected
                Payment
Year         (in thousands)
----         --------------
<S>          <C>
1999         $ 97,354
2000           97,688
2001          102,073
2002          103,552
2003          105,531

</TABLE>

The financial instruments held or issued by the Company are for purposes other
than trading.  The estimated fair values of the Company's financial instruments
are as follows:

<TABLE>
<CAPTION>

                                               (In thousands of dollars)
                                              1998                  1997
                                              ----                  ----
                                       CARRYING     FAIR       Carrying    Fair
At December 31,                         AMOUNT      VALUE       Amount     Value
----------------------------------------------------------------------------------
<S>                                 <C>         <C>         <C>         <C>
Cash and short-term
   investments                      $  172,998  $  172,998  $  378,232  $  378,232
Mandatorily redeemable
   preferred stock                      76,610      86,444      86,730      87,328
Long-term debt:
   First Mortgage bonds              2,741,305   2,905,141   2,801,305   2,878,368
   Senior Notes                      3,293,784   3,324,777           -           -
   Medium-term notes                    20,000      23,290      20,000      22,944
   Promissory notes                    413,760     413,760     413,760     413,760
   Other                               253,195     253,195     229,634     229,634
Indexed swap contracts
   regulatory asset                    693,363     693,363           -           -

</TABLE>

At December 31, 1998, the Company's energy marketing subsidiary had no open
trading positions.  At December 31, 1997, the fair value of its long and short
trading positions was approximately $54.7 million and $54.5 million,
respectively.  These fair values were less than the weighted average fair value
of open positions for the year ending December 31, 1998 and greater than the
weighted average fair value of open positions for the year ending December 31,
1997.

Transactions entered into for trading purposes are accounted for on a
market-to-market basis with changes in fair value recognized as a gain or loss
in the period of change.  At December 31, 1998, there were no open trading
positions.  At December 31, 1997, the open trading positions consisted of
off-balance sheet electric and gas forward contracts.  These positions
consisted of long and short electric forward contracts with fair values of
$45.3 million (1,878,000 MWhrs) and $44.3 million (1,778,000 MWhrs),
respectively, and long and short gas forward contracts with fair values
of $9.4 million (7.1 million Dth) and $10.2 million (7.3 million Dth),
respectively.  The effects of these trading activities on the Company's
1998 and 1997 results of operations were not material.

Activities for non-trading purposes generally consist of transactions entered
into to hedge the market fluctuations of contractual and anticipated
commitments.  Gas futures are used for hedging purposes.  Changes in market
value of futures contracts relating to hedged items are deferred until the
physical transaction occurs, at which time, income or loss is recognized.  At
December 31, 1998, the open non-trading positions consisted of long and short
gas futures contracts with fair values of $4.8 million (2.5 million Dth) and
$1.2 million (.7 million Dth), respectively.  At December 31, 1997, the open
non-trading positions consisted of long and short gas futures contracts with
fair values of $5.2 million (2.3 million Dth) and $3.1 million (1.3 million
Dth), respectively.  The fair value of open positions for non-trading purposes
at December 31, 1998, as well as the effect of these activities on the Company's
results of operations for the same period ending, was not material.

The fair value of futures and forward contracts are determined using quoted
market prices or broker's quotes.

The Company's investments in debt and equity securities consist of trust funds
for the purpose of funding the nuclear decommissioning of Unit 1 and its share
of Unit 2 (see Note 3 - "Nuclear Plant Decommissioning"), investments held by
Opinac North America, Inc. and a trust fund for certain pension benefits.
The Company has classified all investments in debt and equity securities
as available for sale and has recorded all such investments at their
fair market value at December 31, 1998.  The proceeds from the sale of
investments were $202.1 million, $159.7 million, and $99.4 million in 1998,
1997, and 1996, respectively.  Net realized and unrealized gains and losses
related to the nuclear decommissioning trust are reflected in "Accumulated
depreciation and amortization" on the Consolidated Balance Sheets, which is
consistent with the method used by the Company to account for the
decommissioning costs recovered in rates.  The unrealized gains and losses
related to the investments held by the pension trust and Opinac Energy for the
period ending December 31, 1998 are not material to the results of operations of
the Company.  The recorded fair values and cost basis of the Company's
investments in debt and equity securities is as follows:

<TABLE>
<CAPTION>
                                                     (In thousands of dollars)
                        ------------------------------------------------------------------------------------
AT DECEMBER 31,                         1998                                           1997
                                       GROSS UNREALIZED      FAIR                  Gross Unrealized    Fair
Security Type              COST        GAIN       (LOSS)     VALUE     Cost       Gain     (Loss)      Value
------------------------------------------------------------------------------------------------------------
<S>                     <C>          <C>        <C>        <C>        <C>        <C>       <C>       <C>
U.S. Government
   Obligations .        $  19,291    $ 2,621    $  (117)   $ 21,795   $ 14,136   $ 1,864   $   (4)   $ 15,996
Commercial Paper           82,930      1,269          -      84,199    106,035     1,542        -     107,577
Tax Exempt
   Obligations .          104,538      6,786       (164)    111,160     80,115     5,884      (55)     85,944
Corporate
   Obligations .          100,736     22,684     (2,856)    120,564     92,949    17,368     (830)    109,487
Other. . . . . .            6,666          -        -         6,666      3,025         -        -       3,025
                        ---------    -------    --------   --------   --------   -------   -------   --------
                        $ 314,161    $33,360    $(3,137)   $344,384   $296,260   $26,658   $ (889)   $322,029
                        =========    =======    ========   ========   ========   =======   =======   ========

</TABLE>

Using the specific identification method to determine cost, the gross realized
gains and gross realized losses were:

<TABLE>
<CAPTION>

                           (In thousands of dollars)
YEAR ENDED DECEMBER 31,    1998       1997      1996
----------------------     ----       ----      ----
<S>                        <C>        <C>       <C>
Realized gains. . . . .    $ 5,350    $3,487    $2,121
Realized losses . . .        2,221       686       806

</TABLE>

The contractual maturities of the Company's investments in debt securities is
as follows:

<TABLE>
<CAPTION>

At December 31, 1998     Fair Value      Cost
--------------------     -----------   --------
<S>                      <C>           <C>
Less than 1 year . .     $    78,438   $   77,135
1 year to 5 years. .          18,289       17,617
5 years to 10 years.          63,504       61,122
Due after 10 years .         126,363      120,838

</TABLE>

NOTE 11.  STOCK BASED COMPENSATION

Under the Company's stock compensation plans, stock units and stock appreciation
rights ("SARs") may be granted to officers, key employees and directors.  In
addition, the Company's plans allow for the grant of stock options to officers.
The table below sets forth the activity under the Company's stock compensation
plans for the years 1996 through 1998:
<TABLE>
<CAPTION>

                                     SARS       UNITS    OPTIONS
                                  ----------  ---------  --------
<S>                               <C>         <C>        <C>
OUTSTANDING AT DECEMBER 31, 1995    414,000    169,500   300,583 
Granted. . . . . . . . . . . . .    376,600    291,228         - 
Exercised. . . . . . . . . . . .          -          -         - 
Forfeited. . . . . . . . . . . .          -          -    (2,000)
                                  ----------  ---------  --------
OUTSTANDING AT DECEMBER 31, 1996    790,600    460,728   298,583 
Granted. . . . . . . . . . . . .    296,300    208,750         - 
Exercised. . . . . . . . . . . .          -     (2,514)        - 
Forfeited. . . . . . . . . . . .          -          -         - 
                                  ----------  ---------  --------
OUTSTANDING AT DECEMBER 31, 1997  1,086,900    666,964   298,583 
Granted. . . . . . . . . . . . .  1,723,500    488,428         - 
Exercised. . . . . . . . . . . .    (42,700)  (211,403)        - 
Forfeited. . . . . . . . . . . .    (28,000)   (10,550)  (12,000)
                                  ----------  ---------  --------
OUTSTANDING AT DECEMBER 31, 1998  2,739,700    933,439   286,583 
                                  ==========  =========  ========

</TABLE>

Stock units are payable in cash at the end of a defined vesting period,
determined at the date of the grant, based upon the Company's stock price for a
defined period.  SARs become exercisable, as determined at the grant date, and
are payable in cash based upon the increase in the Company's stock price from a
specified level.  As such, for these awards, compensation expense is recognized
over the vesting period of the award based upon changes in the Company's stock
price for that period.  Options were granted over the period 1992 to 1995 and
become exercisable in three years and expire ten years from the grant date.
These options are all considered to be antidilutive for EPS calculations.
Included in the results of operations for the years ending 1998, 1997 and 1996,
is approximately $9.8 million, $3.2 million and $2.6 million, respectively,
related to these plans.

As permitted by SFAS No. 123 - "Accounting for Stock-Based Compensation" ("SFAS
No. 123") the Company has elected to follow Accounting Principles Board Opinion
No. 25-"Accounting for Stock Issued to Employees" (APB No. 25) and related
interpretations in accounting for its employee stock options.  Under APB No. 25,
no compensation expense is recognized for stock options because the exercise
price of the Company's employee stock options equals the market price of the
underlying stock on the grant date.  Since stock units and SARs are payable in
cash, the accounting under APB No. 25 and SFAS No. 123 is the same.  Therefore,
the pro forma disclosure of information regarding net income, as required by
SFAS No. 123, relates only to the Company's outstanding stock options, the
effect of which is immaterial to the financial statements for the years ended
1998, 1997 and 1996.  There is no effect on earnings per share for these years
resulting from the pro-forma adjustments to net income.

NOTE 12.  SEGMENT INFORMATION

In 1998, the Company adopted SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information."  SFAS No. 131 supersedes SFAS No. 14,
"Financial Reporting for Segments of a Business Enterprise."  Prior years'
information has been restated to conform to SFAS No. 131.

The Company is organized between regulated and unregulated activities.  The
Company is pursuing formation of a holding company in 1999 that would further
separate these activities.  Within the regulated business, which has 99% of
total assets and 96% of total revenues, there are three principal business
units: Energy Delivery, Nuclear and Fossil/Hydro.  The Company has announced
plans to, and expects to, consummate sale of the fossil and hydro assets in
1999.  Although there are three identified business units, financial performance
and resource allocation are measured and managed at the regulated business
level.

The Company's unregulated activities do not meet the reporting thresholds of
SFAS No. 131, but comprise a substantial portion of "other" in the accompany
table.

<TABLE>
<CAPTION>

                                             Depreciation     Federal &
                               Total              &            Foreign        Economic     Construction   Identifiable
(In thousands of dollars)     Revenues      Amortization*    Income Taxes    Value Added   Expenditures      Assets
-------------------------  --------------  ---------------  --------------  -------------  -------------  -------------
<S>                        <C>             <C>              <C>             <C>            <C>            <C>
1998 
REGULATED COMPANY . . . .  $   3,826,373   $      484,250   $     (63,131)  $   (697,948)  $     392,200  $  13,733,055
OTHER . . . . . . . . . .        141,931              493          (3,597)       (31,471)              -        128,132
RECLASSIFICATION IN
   CONSOLIDATION. . . . .       (141,931)            (493)              -              -               -              -
                           --------------  ---------------  --------------  -------------  -------------  -------------
      TOTAL CONSOLIDATED.  $   3,826,373   $      484,250   $     (66,728)  $   (729,419)  $     392,200  $  13,861,187
=========================  ==============  ===============  ==============  =============  =============  =============
1997 
Regulated Company . . . .  $   3,966,404   $      339,641   $     125,401   $   (650,188)  $     290,757  $   9,431,763
Other . . . . . . . . . .        116,258              551           1,194        (32,009)              -        152,378
Reclassification in
   Consolidation. . . . .       (116,258)            (551)              -              -               -              -
                           --------------  ---------------  --------------  -------------  -------------  -------------
      Total Consolidated.  $   3,966,404   $      339,641   $     126,595   $   (682,197)  $     290,757  $   9,584,141
=========================  ==============  ===============  ==============  =============  =============  =============
1996 
Regulated Company . . . .  $   3,975,410   $      329,253   $      99,795   $   (637,444)  $     352,049  $   9,290,711
Other . . . . . . . . . .         37,595              688           2,699        (21,523)              -        136,924
Reclassification in
   Consolidation. . . . .        (22,352)            (114)              -              -               -              -
                           --------------  ---------------  --------------  -------------  -------------  -------------
      Total Consolidated.  $   3,990,653   $      329,827   $     102,494   $   (658,967)  $     352,049  $   9,427,635
=========================  ==============  ===============  ==============  =============  =============  =============

</TABLE>

*-Includes amortization of the MRA regulatory asset in 1998.

A reconciliation of total segment Economic Value Added to total consolidated net
income for the years ended December 31, 1998, 1997 and 1996 is as follows:

<TABLE>
<CAPTION>

(In thousands of dollars)                  1998         1997         1996
-------------------------------------  -----------  -----------  -----------
<S>                                    <C>          <C>          <C>
Economic Value Added:
    Operations. . . . . . . . . . . .  $ (248,624)  $ (266,459)  $ (230,613)
    IPP-Related . . . . . . . . . . .    (480,795)    (415,738)    (428,354)
                                       -----------  -----------  -----------
Total Economic Value Added. . . . . .    (729,419)    (682,197)    (658,967)
Charge for Use of Investor's Capital.   1,225,437    1,237,499    1,244,579 
Adjustments for Significant Items . .    (351,388)    (189,938)    (224,756)
Interest Charges (net of taxes) . . .    (265,455)    (182,029)    (183,102)
Extraordinary Item. . . . . . . . . .           -            -      (67,364)
                                       -----------  -----------  -----------
   Consolidated Net Income (loss) . .  $ (120,825)  $  183,335   $  110,390 
                                       ===========  ===========  ===========

</TABLE>

The Company implemented a shareholder value based management system. The metric
used to measure shareholder value creation is Economic Value Added (EVA).  EVA
is the financial measure used to evaluate projects, allocate resources and
report and incent performance.

EVA is calculated as Net Operating Profit after Taxes less a charge for the use
of capital employed.  The capital charge is determined by applying a rate
representing an estimate of investors' expected return given the risk of the
business and a targeted capital structure.  The rate is not the same as the
embedded cost of capital, including the return of equity that may be established
in a rate proceeding.  Certain adjustments to accounting data are made to more
closely reflect operating or economic results.  In each of the three years, an
adjustment is made to include the recognition of the off-balance sheet liability
for remaining future over-market contracts with IPPs and the corresponding
recognition of imputed interest on that liability.  In addition, there was a
significant adjustment in 1998 to reflect the re-capitalization for EVA purposes
of the POWERCHOICE charge and the incremental operating expense associated with
the January 1998 ice storm and the September 1998 windstorm.

EVA is further segmented between EVA from Operations and EVA due to the MRA and
the remaining over-market IPP contracts.  This distinction is used to allow
management to focus on operating performance versus shareholder value created as
the MRA is amortized, the corresponding debt is retired and remaining contracts
are restructured or otherwise expire.

NOTE 13.  QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating revenues, operating income, net income (loss) and earnings (loss) per
common share by quarters from 1998, 1997 and 1996, respectively, are shown in
the following table.  The Company, in its opinion, has included all adjustments
necessary for a fair presentation of the results of operations for the quarters.
Due to the seasonal nature of the utility business, the annual amounts are not
generated evenly by quarter during the year.  The Company's quarterly results of
operations reflect the seasonal nature of its business, with peak electric loads
in summer and winter periods.  Gas sales peak in the winter.

<TABLE>
<CAPTION>

                                        In thousands of dollars
                                  -----------------------------------
                                                                            Basic and
                                                                             Diluted
                                                                 Net         Earnings
                                  Operating       Operating     Income      (Loss) per
Quarter Ended                     Revenues      Income (Loss)   (Loss)     Common Share
---------------------------------------------------------------------------------------
<S>                     <C>     <C>             <C>           <C>            <C>
December 31,.           1998    $  886,432      $ 103,263     $ (17,433)      ($0.14)
                        1997       960,304         86,024         7,881        (0.01)
                        1996       971,106        117,832       (25,808)       (0.24)
-------------------------------------------------------------------------------------
September 30,           1998    $  930,631      $ 110,287     $  17,653      $  0.05 
                        1997       896,570        110,174        31,683         0.15 
                        1996       895,713         47,119       (12,916)       (0.16)
-------------------------------------------------------------------------------------
June 30,                1998    $  910,906      $(180,824)    $(141,408)      ($1.04)
                        1997       945,698        130,704        40,749         0.22 
                        1996       960,771        142,755        52,992         0.30 
-------------------------------------------------------------------------------------
March 31,               1998    $1,098,404      $ 134,297     $  20,363      $  0.08 
                        1997     1,163,832        231,937       103,022         0.65 
                        1996     1,163,063        214,632        96,122         0.60 
-------------------------------------------------------------------------------------

</TABLE>

In the first quarter of 1998, the Company expensed $70.2 million associated
with the January 1998 ice storm (of which $62.9 million was considered
incremental) or 28 cents per common share.  In the second quarter of 1998, the
Company recorded a non-cash write-off of $263.2 million ($1.18 per common share)
associated with the portion of the MRA disallowed in rates by the PSC.  In the
fourth quarter of 1996, the Company recorded an extraordinary item for the
discontinuance of regulatory accounting principles of $103.6 million (47 cents
per common share).  In the third quarter of 1996, the Company increased the
allowance for doubtful accounts by $68.5 million (31 cents per common share).

<PAGE>

REGULATED ELECTRIC AND GAS STATISTICS

ELECTRIC CAPABILITY

<TABLE>
<CAPTION>

                                           Thousands of KW
DECEMBER 31,                      1998           %    1997   1996
-----------------------------------------------------------------
<S>                              <C>     <C>      <C>      <C>
OWNED:
   Coal . . . . . . . . . .      1,360    17.5    1,360    1,333
   Oil* . . . . . . . . . .        850    11.0        -        -
   Dual Fuel- Oil/Gas . . .      1,346    17.4    1,346    1,336
   Nuclear. . . . . . . . .      1,082    14.0    1,082    1,082
   Hydro. . . . . . . . . .        661     8.5      661      617
                                 -----   -----    -----    ------
                                 5,299    68.4    4,449    4,368
                                 -----   -----    -----    ------
PURCHASED:
   New York Power Authority
      -Hydro. . . . . . . .      1,325    17.1    1,325    1,310
      -Nuclear. . . . . . .          -       -        -      110
   IPPs** . . . . . . . . .      1,125    14.5    2,382    2,406
                                 -----   -----    -----    -----
                                 2,450    31.6    3,707    3,826
                                 -----   -----    -----    -----
Total capability*** . . . .      7,749   100.0    8,156    8,194
                                 =====   =====   ======   ======

Electric peak load. . . . .      5,928            6,348    6,021
                                 =====            =====    =====

</TABLE>

*  In 1994, Oswego Unit No. 5 (an oil-fired unit with a capability of
   potentially up to 850,000 KW) was put into long-term cold standby.
   In June 1998, the unit was returned to service.

** On June 30, 1998, the MRA was consummated with 14 IPPs.  The MRA allowed
   the Company to terminate, restate or amend 27 PPAs.  The Company terminated
   18 PPAs for 1,092 MW of electric generating capacity, restated eight PPAs
   representing 535 MW of capacity and amended one PPA representing 42 MW of
   capacity.

***Available capability can be increased during heavy load periods by
   purchases from neighboring interconnected systems.

<PAGE>

REGULATED ELECTRIC STATISTICS

<TABLE>
<CAPTION>

                                                         1998        1997        1996
                                                      ----------  ----------  ----------
<S>                                                   <C>         <C>         <C>
REGULATED ELECTRIC SALES (MILLIONS OF KWH):
   Residential . . . . . . . . . . . . . . . . . . .       9,643       9,905      10,109
   Commercial. . . . . . . . . . . . . . . . . . . .      11,560      11,552      11,564
   Industrial. . . . . . . . . . . . . . . . . . . .       6,843       7,191       7,148
   Industrial-Special. . . . . . . . . . . . . . . .       4,568       4,507       4,326
   Other . . . . . . . . . . . . . . . . . . . . . .         241         235         246
   Other electric systems. . . . . . . . . . . . . .       3,577       3,746       5,431
   Subsidiary. . . . . . . . . . . . . . . . . . . .           -           -         303
                                                      ----------  ----------  ----------
                                                          36,432      37,136      39,127
                                                      ==========  ==========  ==========

REGULATED ELECTRIC REVENUES (THOUSANDS OF DOLLARS):
   Residential . . . . . . . . . . . . . . . . . . .  $1,201,697  $1,227,245  $1,252,165
   Commercial. . . . . . . . . . . . . . . . . . . .   1,220,067   1,233,417   1,237,385
   Industrial. . . . . . . . . . . . . . . . . . . .     480,942     531,164     524,858
   Industrial-Special. . . . . . . . . . . . . . . .      63,870      61,820      58,444
   Other . . . . . . . . . . . . . . . . . . . . . .      55,119      54,545      53,795
   Other electric systems. . . . . . . . . . . . . .      94,756      83,794     113,391
   Miscellaneous . . . . . . . . . . . . . . . . . .     144,693     117,456      53,698
   Subsidiary. . . . . . . . . . . . . . . . . . . .           -           -      15,243
                                                      ----------  ----------  ----------
                                                      $3,261,144  $3,309,441  $3,308,979
                                                      ==========  ==========  ==========

REGULATED ELECTRIC CUSTOMERS (AVERAGE):
   Residential . . . . . . . . . . . . . . . . . . .   1,401,178   1,404,345   1,405,083
   Commercial. . . . . . . . . . . . . . . . . . . .     146,034     146,039     145,149
   Industrial. . . . . . . . . . . . . . . . . . . .       1,905       1,970       2,045
   Industrial-Special. . . . . . . . . . . . . . . .         109          85          99
   Other . . . . . . . . . . . . . . . . . . . . . .       1,544       1,519       1,302
   Subsidiary. . . . . . . . . . . . . . . . . . . .           -           -      13,557
                                                      ----------  -----------  ---------
                                                       1,550,770   1,553,958   1,567,235
                                                      ==========  ==========  ==========

RESIDENTIAL (AVERAGE):
   Annual KWh use per customer . . . . . . . . . . .       6,882       7,053       7,195
   Cost to customer per KWh
      (in cents) . . . . . . . . . . . . . . . . . .       12.46       12.39       12.39
   Annual revenue per customer . . . . . . . . . . .  $   857.63  $   873.89  $   891.17

</TABLE>
REGULATED GAS STATISTICS

<TABLE>
<CAPTION>

                                                    1998        1997        1996
                                                 ----------  ----------  ----------
REGULATED GAS SALES (THOUSANDS OF DTH):
<S>                                              <C>         <C>         <C>
   Residential. . . . . . . . . . . . . . . . .      47,250      55,203      56,728
   Commercial . . . . . . . . . . . . . . . . .      17,023      22,069      25,353
   Industrial . . . . . . . . . . . . . . . . .         752       1,381       2,770
                                                 ----------  ----------  ----------
      Total sales . . . . . . . . . . . . . . .      65,025      78,653      84,851
                                                 ----------  ----------  ----------
   Other gas systems. . . . . . . . . . . . . .          17          28          30
   Spot market. . . . . . . . . . . . . . . . .       4,501       2,451      10,459
   Transportation of customer -
      owned gas . . . . . . . . . . . . . . . .     127,850     152,813     134,671
                                                 ----------  ----------  ----------
      Total gas delivered . . . . . . . . . . .     197,393     233,945     230,011
                                                 ==========  ==========  ==========
REGULATED GAS REVENUES (THOUSANDS OF DOLLARS):
   Residential. . . . . . . . . . . . . . . . .  $  378,150  $  436,136  $  417,348
   Commercial . . . . . . . . . . . . . . . . .     110,499     148,213     162,275
   Industrial . . . . . . . . . . . . . . . . .       3,618       6,549      13,325
   Other gas systems. . . . . . . . . . . . . .          69         130         138
   Spot market. . . . . . . . . . . . . . . . .       8,749       6,346      37,124
   Transportation of customer -
      owned gas . . . . . . . . . . . . . . . .      54,091      55,657      50,381
   Miscellaneous. . . . . . . . . . . . . . . .      10,053       3,932       1,083
                                                 ----------  ----------  ----------
                                                 $  565,229  $  656,963  $  681,674
                                                 ==========  ==========  ==========
REGULATED GAS CUSTOMERS (AVERAGE):
   Residential. . . . . . . . . . . . . . . . .     487,325     484,862     477,786
   Commercial . . . . . . . . . . . . . . . . .      39,779      40,955      41,266
   Industrial . . . . . . . . . . . . . . . . .         168         186         206
   Other. . . . . . . . . . . . . . . . . . . .           6           6           6
   Transportation . . . . . . . . . . . . . . .       3,355       2,557         713
                                                 ----------  ----------  ----------
                                                    530,633     528,566     519,977
                                                 ==========  ==========  ==========

RESIDENTIAL (AVERAGE):
   Annual dekatherm use
      per customer. . . . . . . . . . . . . . .        97.0       113.9       118.7
   Cost to customer per Dth . . . . . . . . . .  $     8.00  $     7.90  $     7.36
   Annual revenue per customer. . . . . . . . .  $   775.97  $   899.51  $   873.50
   Maximum day gas sendout (Dth). . . . . . . .   1,083,802   1,133,370   1,152,996

</TABLE>

<PAGE>

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURES

The Company has nothing to report for this item.

<PAGE>

                                PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Business Background of Directors

SALVATORE H. ALFIERO
-     Chairman and Chief Executive Officer, Mark IV Industries, Inc.
-     Director since 1998
-     Member of Corporate Public Policy & Environmental Affairs and Finance
      Committees of the Board

Mr. Alfiero, age 61, Chairman and Chief Executive Officer, Mark IV Industries,
Inc., a manufacturer of engineered systems and components for power
transmission, fluid power and transfer, and filtration applications, located in
Amherst, New York.  Mr. Alfiero founded Mark IV Industries, Inc. in 1969 and has
been Chairman and Chief Executive Officer since its inception.  Director of
Marine Midland Bank; Phoenix Home Life Mutual Insurance Company; and Southwire
Company.

WILLIAM F. ALLYN
-  President and Chief Executive Officer of Welch Allyn, Inc.
-  Director since 1988
-  Member of Audit, Compensation and Succession, and Nuclear Oversight
   Committees of the Board

Mr. Allyn, age 63, President and Chief Executive Officer of Welch Allyn, Inc.,
Skaneateles Falls, New York, a manufacturer of medical diagnostic
instrumentation, bar code readers and optical scanning devices.  Mr. Allyn
joined Welch Allyn, Inc. in 1962 and was elected to his present position in
1980.  Director of M&T Bank; Oneida Limited; and Perfex Corporation.

ALBERT J. BUDNEY JR.
-  President of the Company
-  Director since 1995

Mr. Budney, age 51, was elected President of the Company in 1995.  Mr. Budney
was previously employed by UtiliCorp United, Inc., an energy services company,
as Managing Vice President of the UtiliCorp Power Services Group and as
President of the Missouri Public Service Division.  Mr. Budney joined UtiliCorp
United, Inc., in 1993.  Prior to that, he was Vice President of Stone & Webster
Engineering Corp., where he managed the engineering firm's Boston Business
Development Department.  Director of Opinac NA; Niagara Mohawk Energy, Inc.; CNP
and Utilities Mutual Insurance Company.  President of Opinac NA and Opinac.

LAWRENCE BURKHARDT III
-  Retired Rear Admiral, United States Navy
-  Director since 1988
-  Chair of Nuclear Oversight Committee of the Board

Mr. Burkhardt, age 66, independent consultant to the nuclear industry since
1990.  Prior to his retirement in 1990, Mr. Burkhardt was employed by NMPC and
served as Executive Vice President of Nuclear Operations.  Director of MACTEC,
Inc.

DOUGLAS M. COSTLE
-  Distinguished Senior Fellow and Chairman of the Board of the Institute
   for Sustainable Communities
-  Director since 1991
-  Member of Executive, Audit, Corporate Public Policy & Environmental
   Affairs (Chair), and Nuclear Oversight Committees of the Board

Mr. Costle, age 59, Distinguished Senior Fellow and Chairman of the Board of the
Institute for Sustainable Communities, a non-profit organization located in
Montpelier, Vermont.  Mr. Costle has held his present position since 1991.
Former Dean of the Vermont Law School in South Royalton, Vermont and
Administrator of the U.S. Environmental Protection Agency.  Independent Trustee
of John Hancock Mutual Funds.

WILLIAM E. DAVIS
-  Chairman of the Board and Chief Executive Officer of the Company
-  Director since 1992
-  Chair of Executive Committee of the Board

Mr. Davis, age 56, was elected Chairman of the Board and Chief Executive of the
Company in 1993.  Mr. Davis joined the Company in 1990 and was elected Senior
Vice President in April 1992, serving in that capacity until elected
Vice-Chairman of the Board of NMPC in November 1992.  Director of Opinac North
America, Inc. ("Opinac NA"); Niagara Mohawk Energy, Inc. ("NM Energy"); Canadian
Niagara Power Company, Limited ("CNP"); and Utilities Mutual Insurance Company.
Mr. Davis is also the Chairman of the Board of NM Energy and holds the position
of Secretary, Utilities Mutual Insurance Company.  Opinac NA, a wholly-owned
subsidiary of the Company, holds 100 percent of Niagara Mohawk Energy and,
through its subsidiary, Opinac Energy Corporation ("Opinac"), a 50 percent
interest in CNP.

WILLIAM J. DONLON
-  Former Chairman of the Board and Chief Executive Officer of NMPC
-  Director since 1980

Mr. Donlon, age 68, retired in 1993 as Chairman of the Board and Chief Executive
Officer of NMPC with 45 years service as an active employee.  Director of the
Directors' Advisory Council--Syracuse Division for M&T Bank.

ANTHONY H. GIOIA
-  Chairman and Chief Executive Officer of Gioia Management, Inc.
-  Director since 1996
-  Member of Executive, Compensation and Succession and Nuclear Oversight
Committess of the Board

Mr. Gioia, age 57, Chairman and Chief Executive Officer of Gioia Management,
Inc., a holding company for several companies, including three packaging
companies located in Buffalo and Lockport, New York.  Mr. Gioia has held his
present position since 1987.  Director of Greater Buffalo Savings Bank.

DR. BONNIE G. HILL
-  President and Chief Executive Officer of The Times Mirror Foundation; Vice
   President of The Times Mirror Company and Sr. Vice President-Communications
   and Public Affairs of The Los Angeles Times
-  Director since 1991
-  Member of Audit, Corporate Public Policy & Environmental Affairs and
   Finance Committees of the Board

Dr. Hill, age 57, President and Chief Executive Officer of The Times Mirror
Foundation, a non-profit institution; Vice President of The Times Mirror
Company, a news and information company, and Sr. Vice President-Communications
and Public Affairs of The Los Angeles Times, located in Los Angeles, California.
Dr. Hill served as Dean and Professor of Commerce of the McIntire School of
Commerce at the University of Virginia from 1992-1996.  Prior to that, she
served as the Secretary of State and Consumer Services Agency for the State of
California.  Director of AK Steel Corporation; Hershey Foods Corporation; and
Louisiana-Pacific Corporation.

CLARK A. JOHNSON
-  Chairman, Pier 1 Imports, Inc.
-  Director since 1998
-  Member of Compensation and Succession and Finance Committees of the Board

Mr. Johnson, age 68, Chairman of Pier 1 Imports, Inc., a specialty retailer of
imported home furnishings, gifts and related items, located in Forth Worth,
Texas.  Mr. Johnson joined Pier 1 Imports, Inc. in 1985 and was elected Chairman
and Chief Executive Officer in 1987, serving in that capacity until elected
Chairman in 1998.   Director of Pier 1 Imports, Inc.; Albertson's, Inc.;
InterTAN Inc.; Metro Media International Group; and Land Care, Inc.

HENRY A. PANASCI JR.
-  Chairman of Cygnus Management Group, LLC
-  Director since 1988
-  Member of Compensation and Succession, Corporate Public Policy &
Environmental Affairs and Finance Committees of the Board

Mr. Panasci, age 70, Chairman of Cygnus Management Group, LLC, a consulting firm
specializing in venture capital and private investments headquartered in
Syracuse, New York.  Mr. Panasci retired in 1996 as Chairman of the Board and
Chief Executive Officer of Fay's Incorporated, a drug store chain.  Mr. Panasci
co-founded Fay's Drug Co., Inc. with his father in 1958.  Director of National
Association of Chain Drug Stores.

DR. PATTI MCGILL PETERSON
-  Executive Director of the Council for International Exchange of Scholars
   and Vice President of the Institute for International Education
-  Director since 1988
-  Member of Executive, Audit (Chair) and Corporate Public Policy &
   Environmental Affairs Committees of the Board

Dr. Peterson, age 55, Executive Director of the Council for International
Exchange of Scholars, Washington, D.C., and Vice President of the Institute for
International Education, New York, New York, affiliated non-profit institutions.
From 1996 to 1997, Dr. Peterson was a Senior Fellow of the Cornell Institute for
Public Affairs, Cornell University, Ithaca, New York.  Dr. Peterson also served
as President of St. Lawrence University from 1987-1996.  Prior to that, she was
President of Wells College.  She holds the title President Emerita at both
institutions.  Independent Trustee of John Hancock Mutual Funds.

DONALD B. RIEFLER
-  Financial Market Consultant
-  Director since 1978
-  Member of Executive, Audit, Finance (Chair) and Nuclear Oversight
   Committees of the Board

Mr. Riefler, age 71, financial market consultant and advisor to J. P. Morgan,
Florida FSB, Palm Beach, Florida, a private banking concern affiliated with J.
P. Morgan & Co., Inc.  Prior to his retirement in 1991, Mr. Riefler was Chairman
of the Market Risk Committee for J. P. Morgan & Co., Inc. and Morgan Guaranty
Trust Company of New York.

STEPHEN B. SCHWARTZ
-  Retired Senior Vice President, International Business Machines Corporation
-  Director since 1992
-  Member of Executive, Compensation and Succession (Chair) and Finance
   Committees of the Board

Mr. Schwartz, age 64, retired as Senior Vice President of International Business
Machines Corporation in 1992.  Mr. Schwartz joined IBM in 1957.  In 1984 he
served as President and Chief Executive Officer of Satellite Business Systems.
He returned to IBM in 1985 and was elected Senior Vice President in 1990.
Director of MFRI, Inc.

             SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

The rules of the SEC require that the Company disclose late filings of reports
of ownership and changes in ownership of the Company's equity securities by its
directors, executive officers and any other person subject to Section 16 of the
Securities and Exchange Act of 1934.  To the best of the Company's knowledge,
there were no late filings during 1998.

<PAGE>

ITEM 11.  EXECUTIVE COMPENSATION

   BOARD OF DIRECTORS' COMPENSATION AND SUCCESSION COMMITTEE REPORT ON EXECUTIVE
                                  COMPENSATION

The Compensation and Succession Committee of the Board of Directors (the
"Committee") is composed entirely of non-employee directors.  The Committee has
responsibility for recommending officer salaries and for the administration of
the Company's officer incentive compensation plans as described in this report.
The Committee makes recommendations to the Board of Directors which makes final
officer compensation determinations.

This Committee report describes the Company's executive officer compensation
policies, the components of the compensation program, and the manner in which
1998 compensation determinations were made for the Company's Chairman of the
Board and Chief Executive Officer, Mr. William E. Davis.

The 1998 Executive Officer Compensation Program was composed of base salary,
annual incentive compensation, and grants of stock units and stock appreciation
rights ("SARs") made pursuant to the Long-Term Incentive Plan ("LTIP") adopted
by the Board of Directors on September 25, 1996, as described later in this
report.

                                  BASE SALARY
 The Committee seeks to ensure that salaries of the Company's officers,
including executive officers, remain competitive with levels paid to comparable
positions among other U.S. electric and gas utilities with comparable revenues
(collectively referred to as the "Comparator Utilities").  The Committee
believes that competitive salaries provide the foundation of the Company's
officer compensation program and are essential for the Company to attract and
retain qualified officers, especially in light of the increasing competition
within the industry.  Each officer position has been assigned to a competitive
salary range.  The Committee intends to administer salaries within the 25th to
75th percentiles of practice with respect to those Comparator Utilities.  The
1998 average salary of the five named executive officers fell between the 25th
and 50th percentile competitive levels.

               ANNUAL OFFICER INCENTIVE COMPENSATION PLAN ("OICP")

On December 13, 1990, the Board of Directors adopted the Company's OICP for
officers and the Management Incentive Compensation Plan for management
employees.  The OICP is structured and administered so that a significant
component of each officer's annual cash compensation must be earned on the basis
of the Company's and the officer's annual performance.  Maximum incentive award
opportunities for 1998 were set by the Committee at 40% of salary for Mr. Davis
and at 25% to 40% for all other officers.  OICP award opportunities are intended
to position officer annual compensation (salary + OICP awards) within the 25th
to 75th percentile of Comparator Utility practice depending on company
financial, business and support unit performance.  In connection with a freeze
on award cash compensation instituted in late 1995, no awards were made to
officers under the OICP for plan years 1996 and 1997.  The OICP was reinstated
for the 1998 plan year.

For the 1998 plan year, awards were based on the degree to which certain
pre-established financial and operating objectives were met or exceeded.  The
objectives for the 1998 plan year included economic value added (EVA), business
unit financial objectives and business/support group operating objectives.
These objectives were weighted differently for each business/support unit, based
on the applicability of such objectives to the business or support unit.

Awards for the named executive officers averaged 30.6% of their 1998 salaries.
Their average annual compensation (salary + OICP awards) fell between the 25th
and 50th percentiles of comparator utility practice.  Refer to the Summary
Compensation Table for specific amounts which will be paid in early 1999 to
named executive officers under the 1998 OICP.

                            LONG-TERM INCENTIVE PLAN

To provide a continuous program of long-term stock incentives, on September 25,
1996 the Board of Directors adopted the LTIP and approved stock unit and SAR
grants for the 1996-1998 period.  Under the LTIP, dividends are credited (in an
amount equivalent to dividends paid, if any, on the Company's common stock) with
respect to stock unit grants, which would be reinvested at the prevailing stock
price, thereby increasing the number of stock units payable.  These stock unit
grants will be paid in cash in early 1999 based on the average fair market value
of the Company's common stock during the last 12 consecutive trading days in
1998 ($16.138).  The 1996 LTIP SAR grants became exercisable on January 2, 1999,
and may be exercised until they expire on December 31, 2005.

On January 29, 1997, the Board of Directors approved the grant of LTIP stock
units and SARs for the 1997-1999 performance period.  These stock units, and
accumulated dividend stock units, will be paid in early 2000 based on the
average fair market value of the Company's common stock during the last 12
consecutive trading days in 1999.  The SARs first become exercisable on  January
2, 2000, and can be exercised until they expire on December 31, 2006.

The size of both the 1996-1998 and 1997-1999 LTIP stock unit and SAR grants were
determined, based on the price of the Company's common stock at the time these
grants were made, so that the combination of the officers' current salaries plus
the grant date present value of December 14, 1995 stock unit and SAR grants made
under the 1995 Stock Incentive Plan ("SIP"), and LTIP grants for the 1996-1998
and 1997-1999 performance periods, would approximate the 50th percentile of
Comparator Utility total compensation practice for the three-year period 1995
through 1997.  The competitiveness of the actual compensation realized from
these grants is dependent on the market value of the Company's common stock at
the end of 1997, 1998, and 1999.

The Board of Directors also approved a January 19, 1998 grant of LTIP stock
units and SARs for the period 1998-2000.  These stock units, and any accumulated
dividend stock units, will be paid in early 2001 based on the average fair
market value of the Company's common stock during the last 12 consecutive
trading days in 2000.  The SARs will first become exercisable on January 2,
2001, and can be exercised until they expire on December 31, 2007.  The 1998
stock unit and SAR grants were determined so that the average current salary and
the average grant date present value of the 1998 LTIP grants for the five named
executive officers would approximate the 50th percentile of 1997 Comparator
Utility total compensation practice.

On August 25, 1998, the Board of Directors approved the accelerated granting of
LTIP stock units and SARs that would have normally been granted at the start of
1999 (for the 3-year period 1999-2001) and at the start of 2000 (for the 3-year
period 2000-2002).  These LTIP grants were accelerated so as to provide
additional motivation and incentive to officers and to increase the retention
value of LTIP grants.  The LTIP stock units granted with respect to the
1999-2001 period will not vest until the end of 2001, and the LTIP stock units
granted with respect to the 2000-2002 period will not vest until the end of
2002.  Similarly, accelerated 1999 SAR grants do not vest and become exercisable
until January 2, 2002 and expire on December 31, 2008.  Accelerated 2000 SAR
grants do not vest and become exercisable until January 2, 2003, and expire
December 31, 2009.  Thus, despite the acceleration of these two stock unit and
SAR grants, the accelerated LTIP stock units would not vest and be paid, and the
accelerated SAR grants would not vest, become exercisable or expire, any sooner
than would have been the case had they been made at the start of 1999 and 2000.
Since the 1999 and 2000 LTIP stock unit and SAR grants were accelerated,
additional LTIP grants for these periods are not anticipated.  The two
accelerated LTIP stock unit and SAR grants were determined so that the sum of
the average grant date value of the January 19, 1998 and the two accelerated
August 25, 1998 grants, in combination with the average salaries and incentive
award payments (at half maximum levels) of the proxy executive officers, would
approximate the 50th percentile of Comparator Utility total compensation
practice over the 3-year period, 1998-2000.

Through the combination of base salary, annual incentive compensation, stock
unit and SAR grants, the Committee seeks to focus the efforts of officers toward
improving, annually and over the longer-term, the financial returns for its
shareholders.

                COMPENSATION OF WILLIAM E. DAVIS, CHAIRMAN OF THE
                        BOARD AND CHIEF EXECUTIVE OFFICER

Mr. Davis became Chief Executive Officer on May 1, 1993.  During 1998, Mr.
Davis's salary was increased to its current annual rate of $570,000.  The
increase in Mr. Davis's salary reflected an evaluation of his performance and
the fact that his salary was well below the 25th percentile relative to salaries
paid to CEOs at electric and gas utilities with comparable revenues.  The
Committee has been advised by its consultant that Mr. Davis's current annual
salary approximates the 25th percentile of this comparison group.  With respect
to 1998, Mr. Davis earned an annual incentive compensation award in the amount
of $180,937, which represented 34.139% of the salary he received in 1998.  This
award will be paid in early 1999 pursuant to the terms of the OCIP and financial
and operating objectives approved by the Committee for 1998.  These objectives
related to economic value added (EVA), business unit financial performance, and
business/support group operating performance.  Mr. Davis's 1998 annual
compensation (salary + OICP award) fell between the 25th and 50th percentiles of
comparator utility practice.

As previously indicated, the Committee and the Board of Directors seek to
provide a continuous program of long-term stock incentives beyond 1997 when SIP
stock unit grants became payable and SIP SAR grants became exercisable.
Accordingly, on September 25, 1996, the Board of Directors approved a grant of
45,000 stock units and 90,000 SARs, with an exercise price of $8.00, for Mr.
Davis for the 1996-1998 performance period.  On January 29, 1997, the Board of
Directors approved a grant of 35,000 stock units and 70,000 SARs, with an
exercise price of $10.30, for the 1997-1999 performance period.  Both the
1996-1998 and 1997-1999 grants were made under the terms of the LTIP.  The size
of the 1996-1998 and 1997-1999 LTIP grants for Mr. Davis was determined so that
the grant date present value of both grants, in combination with his current
salary and his SIP grants, would approximate the 50th  percentile for comparator
utility chief executive officers during the 1995-1997 period.  The
competitiveness of the compensation Mr. Davis actually realizes from the SIP and
LTIP grants will depend on the market value of the Corporation's common stock at
the end of 1997, 1998, and 1999.

As previously indicated, the Board of Directors approved a January 19, 1998
grant of LTIP stock units and SARs for Mr. Davis for the period 1998-2000.  This
grant consisted of 35,000 stock units and 125,000 SARs with an exercise price of
$10.90.  The size of these grants was determined so that the sum of his current
salary plus the grant date present value of the 1998 stock unit and SAR grants
would fall approximately midway between the 25th and 50th percentiles of 1997
total compensation practice for electric/gas utilities of comparable size.

On August 25, 1998, the Board of Directors approved an accelerated grant of LTIP
stock units and SARs to Mr. Davis that would have normally been granted at the
start of 1999 (for the 3-year period 1999-2001) and at the start of 2000 (for
the 3-year period 2000-2002).  Each of these grants consisted of 28,000 stock
units and 100,000 SARs, with an exercise price of $15.36.  These grants were
accelerated in order to increase the incentive and retention value of these LTIP
grants.  Despite the acceleration of these grants, the stock units will not vest
and be paid, and the SARs will not vest, become exercisable or expire any sooner
than  would have been the case had they been granted at the start of 1999 and
2000.  Additional LTIP grants to Mr. Davis for these periods are not
anticipated.  The two accelerated LTIP stock unit and SAR grants were determined
so that the sum of the average grant date value of the January 19, 1998 and the
two August 25, 1998 LTIP grants, in combination with Mr. Davis's salary and
incentive award payment (at half maximum level) would approximate the 50th
percentile of Comparator Utility total compensation practice over the three-year
period 1998-2000.

Under Section 162(m) of the Internal Revenue Code, the Company may not deduct
certain forms of compensation in excess of $1,000,000 paid to a named executive
officer.  The Committee continually reviews executive compensation plans and 
programs for changes to comply with the limit, where appropriate.  The
Committee believes it is important to maintain flexibility in its executive
compensation plans in order to attract and retain high quality executives,
which may result in compensation being paid in a particular year in excess of 
the limit.  In 1998, a substantial increase in the value of a share of common 
stock resulted in a corresponding increase in the value of stock-based 
compensation.  As a result, the compensation of Mr. Davis exceeded the limit.

_______________

Submitted by the Compensation and Succession Committee of the Board of
Directors:

Stephen B. Schwartz, Chair
William F. Allyn
Anthony H. Gioia
Clark A. Johnson
Henry A. Panasci Jr.

<PAGE>

                             EXECUTIVE COMPENSATION

The following table shows, for the last three fiscal years, cash and other
compensation paid to the Chairman of the Board and Chief Executive Officer and
to each of the other four most highly compensated executive officers of the
Company for fiscal year ended December 31, 1998.

                           SUMMARY COMPENSATION TABLE
                        FISCAL YEARS 1998, 1997 AND 1996

<TABLE>
<CAPTION>

                                   Annual Compensation      Long-Term Compensation
                                                                    Awards
                                ------------------------  --------------------------
                                                   Other                  Securities    All
                                                  Annual    Restricted     Underlying   Other
                                                  Compen-     Stock         Options/   Compen-
Name and Principal              Salary     Bonus  sation      Awards         SARs      sation
      Position            Year  ($)(A)      ($)   ($)(B)      ($)(C)         (#)       ($)(E)
----------------------------------------------------------------------------------------------
<S>                       <C>   <C>      <C>       <C>       <C>           <C>         <C>
                          1998  530,001  180,937      218    1,256,500(D)  325,000(D)  44,539
W. E. Davis               1997  450,501        0      110      371,875      70,000     42,358
Chairman and CEO          1996  462,351        0        0      360,000      90,000     43,365
------------------------  ----  -------  -------   ------    ---------     -------     ------
                          1998  366,001  124,949      218      503,750(D)  170,000(D)  18,051
A. J. Budney Jr.          1997  315,002        0      110      185,938      35,000     16,436
President                 1996  315,002        0    2,956      180,000      45,000     24,975
------------------------  ----  -------  -------   ------    ---------     -------     ------
                          1998  256,334   79,942      218      371,100(D)  119,000(D)   9,583
D. D. Kerr                1997  210,001        0      110       85,000      16,000      7,953
Executive Vice President  1996  210,001        0        0       82,000      20,500      9,415
------------------------  ----  -------  -------   ------    ---------     -------     ------
                          1998  255,835   48,519   11,585      324,413(D)  104,000(D)  30,529
J. H. Mueller             1997        -        -        -            -           -          -
Senior Vice President     1996        -        -        -            -           -          -
------------------------  ----  -------  -------   ------    ---------     -------     ------
                          1998  222,001   63,936   16,370      290,313(D)   89,000(D)  29,283
G. J. Lavine              1997  191,502        0      110       85,000      16,000      8,565
Senior Vice President     1996  191,502        0        0       82,000      20,500      8,571
------------------------  ----  -------  -------   ------    ---------     -------     ------
<
</TABLE>

(A)  Includes all employee contributions to the Employees' Savings Fund Plan.

(B)  Other Annual Compensation for Mr. Budney in 1996 and for Mr. Mueller in
     1998 represents or includes amounts reimbursed for payment of taxes
     associated with relocation expenses.  1997 and 1998 Other Annual
     Compensation for Messrs. Davis, Budney, Kerr, Mueller and Lavine represents
     or includes amounts reimbursed for payment of taxes associated with
     non-cash compensation.  1998 Other Annual Compensation for Mr. Lavine
     includes amounts reimbursed for payment of taxes associated with
     Company-paid legal expenses.

(C)  In 1996, 88,000 stock units were granted to the above named executive
     officers pursuant to the LTIP adopted by the Board of Directors on
     September 25, 1996.  These stock units vested and became payable on
     December 31, 1998.  No dividend equivalents were credited on these stock
     units.  The 1996 values listed in the table were calculated by multiplying
     the stock units granted by $8.00, the price at the time these stock unit
     grants were determined.

     In 1997, 68,500 stock units were granted to the above named executive
     officers pursuant to the LTIP adopted by the Board of Directors on
     September 25, 1996.  These grants were made for the three-year period
     January 1, 1997, through December 31, 1999, and vest and become payable
     on December 31, 1999.  The 1997 values listed in the table were calculated
     by multiplying the stock units granted by $10.625, the price at the time
     these stock unit grants were determined.  Dividend equivalents, if any,
     will be credited on these grants and will be paid when the related stock
     units are paid.

     In 1998, 82,700 stock units were granted in January and 118,000 in August
     (consisting of two grants of 59,000 each) to the above named executive
     officers pursuant to the LTIP adopted by the Board of Directors on
     September 25, 1996.  The first grant was made for a three-year period
     January 1, 1998 through December 31, 2000, and vest and become payable
     on December 31, 2000; the second grant was made for a three-year period
     January 1, 1999 through December 31, 2001, and vest and become payable
     on December 31, 2001; and the third grant was made for a three-year period
     January 1, 2000 through December 31, 2002, and vest and become payable on
     December 31, 2002. The 1998 values listed in the table were calculated by
     multiplying the stock units granted in January by $12.00 and those granted
     in August by $15.5625, the prices at the time these stock unit grants were
     determined.  Dividend equivalents, if any, will be credited on these grants
     and will be paid when the related stock units are paid.

     As of the end of the 1998 fiscal year, based on a closing market price of
     $16.125, Mr. Davis held 171,000 stock units having a market value of
     $2,757,375; Mr. Budney held 77,500 stock units having a market value of
     $1,249,688; Ms. Kerr held 45,350 stock units having a market value of
     $731,269; Mr. Mueller held 24,100 stock units having a market value of
     $388,613; and Mr. Lavine held 39,250 stock units having a market value of
     $632,906.

(D)  This amount represents three distinct grants from the LTIP.  The first
     grant will vest and become payable (in the case of stock units) and 
     exercisable (in the case of SARs) after December 31, 2000; the second
     after December 31, 2001; and the third after December 31, 2002.  No
     additional grants for these periods are anticipated.

(E)  All Other Compensation for 1998 includes: employer contributions to the
     Company's Employees' Savings Fund Plan:  Mr. Davis ($4,793), Mr. Budney
     ($1,955), Ms. Kerr ($4,758), Mr. Mueller ($5,044), and Mr. Lavine ($4,797);
     taxable portion of life insurance premiums:  Mr. Davis ($15,935), Mr.
     Budney ($2,821), Ms. Kerr ($2,020), Mr. Mueller ($3,565), and Mr. Lavine
     ($3,243); payments under the Company's Relocation Policy:  Mr. Mueller
     ($21,673); employer contributions to the Company's Excess Benefit Plan:
     Mr. Davis ($10,811), Ms. Kerr ($2,805), and  Mr. Lavine ($1,747); 
     directors' fees received from Canadian Niagara Power Corporation:  Mr.
     Davis ($13,000) and Mr. Budney ($13,000); personal travel allowance:
     Mr. Budney ($275) and Mr. Mueller ($247); Company-paid legal expenses:
     Mr. Lavine ($19,496).

The following table discloses, for the Chairman of the Board and Chief Executive
Officer, Mr. William E. Davis, and the other named executive officers, the
number and terms of SARs granted during the fiscal year ended December 31, 1998.

                      OPTION/SAR GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>

                                 Individual Grants
                --------------------------------------------------
                Number of    % of Total                                    Grant
                Securities   Options/SARs   Exercise                        Date
                Underlying    Granted to       or                         Present
               Options/SARs  Employees in  Base Price   Expiration         Value
    Name        Granted (#)  Fiscal Year    ($/Sh)       Date (A)         ($)(B)
---------------------------------------------------------------------------------
<S>              <C>            <C>         <C>         <C>               <C>
W.E. Davis       125,000        7.37        10.90       12/31/2007        478,750
                 100,000        6.00        15.36       12/31/2008        773,000
                 100,000        6.00        15.36       12/31/2009        802,000

A.J. Budney Jr.  70,000         4.13        10.90       12/31/2007        268,100
                 50,000         2.95        15.36       12/31/2008        386,500
                 50,000         2.95        15.36       12/31/2009        401,000

D.D. Kerr        39,000         2.30        10.90       12/31/2007        149,370
                 40,000         2.36        15.36       12/31/2008        309,200
                 40,000         2.36        15.36       12/31/2009        320,800

J.H. Mueller     39,000         2.30        10.90       12/31/2007        149,370
                 32,500         1.92        15.36       12/31/2008        251,225
                 32,500         1.92        15.36       12/31/2009        260,650

G.J. Lavine      24,000         1.42        10.90       12/31/2007         91,920
                 32,500         1.92        15.36       12/31/2008        251,225
                 32,500         1.92        15.36       12/31/2009        260,650

</TABLE>

(A)  In 1998, the Board of Directors made three grants of SARs under the
     LTIP.  The first grant of SARs that expire on December 31, 2007 become
     exercisable January 2, 2001; the second grant of SARs that expire on
     December 31, 2008 become exercisable January 2, 2002; and the third grant
     of SARs that expire on December 31, 2009 become exercisable January 2,
     2003.  All SARs become exercisable upon a change in control.

(B)  The grant date present value of SARs is calculated using the
     Black-Scholes Option Pricing Model with the following assumptions:
    (1)  exercise price of rights that expire on December 31, 2007 ($10.90);
         stock volatility (29.57%); dividend yield (2.86%); risk free rate
         (6.25%); exercise term (10 years); Black-Scholes ratio (.3512);
         and Black-Scholes value ($3.83) for rights that expire on December
         31, 2007.  Stock volatility and dividend yield assumptions are based
         on 36 months of results for the period ending December 31, 1998.
    (2)  exercise price of rights that expire on December 31, 2008 ($15.36);
         stock volatility (31.10%); dividend yield (0.86%); risk free rate
         (6.25%); exercise term (10 1/3 years); Black-Scholes ratio (.5031);
         and Black-Scholes value ($7.73) for rights that expire on
         December 31, 2008.  Stock volatility and dividend yield assumptions
         are based on 36 months of results for the period ending December 31,
         1998.
    (3)  exercise price of rights that expire on December 31, 2009 ($15.36);
         stock volatility (31.10%); dividend yield (0.86%); risk free rate 
         (6.25%); exercise term (11 1/3 years); Black-Scholes ratio (.5224);
         and Black-Scholes value ($8.02) for rights that expire on December 31,
         2009.  Stock volatility and dividend yield assumptions are based on 36
         months of results for the period ending December 31, 1998.

The following table summarizes exercises of options by the Chairman of the
Board and Chief Executive Officer, Mr. William E. Davis, and the other named
executive officers, the number of unexercised options held by them and the
spread (the difference between the current market price of the stock and the
exercise price of the option, to the extent that market price at the end of the
year exceeds exercise price) on those unexercised options for fiscal year ended
December 31, 1998.

               AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
                      AND FISCAL YEAR-END OPTION/SAR VALUES

<TABLE>
<CAPTION>
                                          Number of Securities
                     Shares              Underlying Unexercised        Value of Unexercised
                    Acquired   Value   Options/SARs at Fiscal Year Options/SARs at Fiscal Year
                  on Exercise Realized           End (#)                 End ($)(A)
                                       --------------------------- ---------------------------
Name                 (#)       ($)     Exercisable  Unexercisable  Exercisable  Unexercisable
----------------------------------------------------------------------------------------------
<S>                 <C>       <C>        <C>           <C>           <C>          <C>
W.E. Davis              0          0     185,125       485,000       787,188      1,945,125

A.J. Budney Jr.         0          0      76,000       250,000       376,000      1,011,750

D.D. Kerr           6,000     28,320      31,500       155,500       125,063        524,738

J.H. Mueller            0          0           0       104,000             0        253,501

G.J. Lavine             0          0      37,500       125,500       157,313        434,889


</TABLE>

_______________
(A)  Calculated based on the closing market price of the Company's Common
     Stock on December 31, 1998 ($16.125).

<PAGE>

PERFORMANCE GRAPH

                        NIAGARA MOHAWK POWER CORPORATION
                 COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
                         VS. S&P 500 INDEX AND EEI INDEX

                      [ILLUSTRATION OF PERFORMANCE GRAPH ]

Data Points

                 1993       1994       1995       1996       1997       1998
                 ----       ----       ----       ----       ----       ----
NMPC            100.00      75.38      54.93      57.10      60.71      93.23
S&P 500 Index   100.00     101.32     139.40     171.40     228.59     293.91
EEI Index       100.00      87.12     110.96     110.27     142.54     165.62

Assumes $100 invested on December 31, 1993 in Niagara Mohawk stock, S&P 500 and
the Edison Electric Institute Combination Gas and Electric Investor-Owned
Utilities Index ("EEI Index").  All dividends assumed to be reinvested over the
five-year period.

                               RETIREMENT BENEFITS

NIAGARA MOHAWK PENSION PLAN

The Niagara Mohawk Pension Plan ("Basic Plan") is a noncontributory,
tax-qualified defined benefit plan and provides all employees of the Company
with a minimum retirement benefit.  This retirement benefit is related to
compensation--that is, base salary or pay--subject to the maximum annual limits
noted in the Retirement Benefits Table.

The participant's Basic Plan retirement benefit is based on one of two formulas
depending on age and years of service on July 1, 1998:
-  the cash balance formula; or
-  the highest five-year average compensation.

Effective July 1, 1998, the Basic Plan was amended to include a cash balance
formula.  Under a cash balance formula, a participant's retirement benefit grows
with pay credits (4% - 8% x salary) plus interest credits on a monthly basis.  A
non-represented (management) employee who was at least 45 years of age and has
10 years of service on July 1, 1998 will receive the higher of the two
formulas--the cash balance formula or the highest consecutive five-year
compensation.  All other non-represented employees' Basic Plan benefit will be
based on the cash balance formula only.  Directors who are not employees are not
eligible to participate in the Basic Plan.

SUPPLEMENTAL  EXECUTIVE  RETIREMENT  PLAN

The Supplemental Executive Retirement Plan ("SERP") is a noncontributory,
nonqualified defined benefit plan that provides additional retirement benefits
to officers of the Company who have obtained age 55 and who have 20 or more
years of employment.  The Committee may grant exceptions to the age and service
requirements.

The SERP provides a benefit equal to the greater of:

(i)  60% of base salary averaged over
     the final 36 months of employment, reduced by benefits payable under the
     Basic Plan; retirement benefits accrued during previous employment and
     one-half of the maximum security benefit to which the participant may be
     entitled at the time of retirement, or

(ii) benefits payable under the Basic Plan without regard to the annual
     benefit limitations imposed by the Internal Revenue Code.

Provided certain established criteria are met, participants in the SERP may
elect to receive their benefit in a lump sum payment.

The following table shows the maximum retirement benefit (adjusted for Social
Security) an officer can earn in aggregate under both the Basic Plan and the
SERP.

                           ANNUAL RETIREMENT ALLOWANCE

<TABLE>
<CAPTION>

3-Year
Average                               Year of Service
Annual      -------------------------------------------------------------------
Salary          10*         15*         20          25        30          35
-------------------------------------------------------------------------------
<S>         <C>         <C>        <C>         <C>         <C>         <C>
150,000     $21,090     $33,885    $ 81,762    $ 81,762    $ 81,762    $ 81,762

225,000      21,670      34,815     126,762     126,762     126,762     126,762

300,000      21,670      34,815     171,762     171,762     171,762     171,762

375,000      21,670      34,815     216,762     216,762     216,762     216,762

450,000      21,670      34,815     261,762     261,762     261,762     261,762

525,000      21,670      34,815     306,762     306,762     306,762     306,762

</TABLE>

*Subject to the Basic Plan benefit.

The benefit calculations assume the officer has selected a straight life annuity
and retired on December 31, 1998 at age 65.  Annual compensation limits
($150,000 in 1996; $160,000 for 1997 and 1998) under a tax-qualified plan will
reduce the benefit amount collectible under the Basic Plan for some highly
compensated officers.

As of December 31, 1998, the persons named in the Summary Compensation Table had
the following estimated credited years of benefit service for purposes of the
pension program:  Mr. Davis, 9 years; Mr. Budney, 4 years; Ms. Kerr, 26 years;
Mr. Mueller, 3 years; and Mr. Lavine, 12 years.

<PAGE>

                               EMPLOYEE AGREEMENTS

The Company entered into employment agreements with Messrs. Davis, Budney,
Lavine, Mueller and Ms. Kerr, which have a rolling three-year term.  In the
event of a change in control (as defined in the agreement), the agreement will
remain in effect for a period of at least 36 months thereafter unless a notice
not to extend the term of the agreement was given at least 18 months prior to
the change in control.  The agreements provide that the executive will receive a
base salary equal to the executive's annual salary at the effective date of the
agreements or such greater amount determined by the Company, that the executive
will be able to participate in the Company's incentive compensation plans and
that the executive is entitled to vacation, fringe benefits, insurance coverage
and other terms and conditions of the agreement as are provided to employees of
the Company with comparable rank and seniority.  If the executive has completed
eight years of service and attained age 55 at the time of the executive's
termination of employment, the executive (and eligible dependents) will be
entitled to coverage for medical, prescription drug, dental and hospitalization
benefits for the remainder of the executive's life with all premiums therefor
paid by the Company.  If an executive has completed eight years of service but
has not attained age 55 upon terminating employment, such benefits will be
provided when the executive attains age 55.

The employment agreements also provide that the executive's benefits under the
SERP will be based on the executive's salary, annual incentive awards and SIP
awards, as applicable.  Further, if the executive's employment is terminated by
the Company without cause at any time, or by the executive for good reason after
a change in control (as such terms are defined in the agreement), or after
completing eight years of service, the agreements provide that the executive
will be deemed fully vested under the SERP without reduction for early
commencement.  If the executive is under age 55, the executive will be entitled
to a fully vested SERP benefit upon attaining age 55, without reduction for
early commencement.

If the executive's employment is terminated by the Company without cause prior
to a change in control, the executive will be entitled to a lump sum severance
benefit in an amount equal to two times the executive's base salary plus an
amount equal to two times the greater of the executive's (i) most recent annual
incentive award or (ii) average annual incentive award paid over the previous
three years.  In addition, the executive will receive a pro rata portion of the
incentive award which would have been payable to the executive for the fiscal
year in which termination of employment occurs, provided that the executive has
been employed for 180 days in such fiscal year.  The executive will also be
entitled to continued participation in the Company's employee benefit plans for
two years, coverage for the balance of the executive's life under a life
insurance policy providing a death benefit equal to 2.5 times the executive's
base salary at termination and payment by the Company of fees and expenses or
any executive recruiting or placement firm in seeking new employment.

If, following a change in control, the executive's employment is terminated by
the Company without cause or by the executive for good reason, the executive
will be entitled to a lump sum severance benefit equal to four times the
executive's base salary.  The executive will also be entitled to the additional
benefits referred to in the last sentence of the preceding paragraph, except
that employee benefit plan coverage for medical, prescription drug, dental and
hospitalization benefits will continue for the remainder of the executive's life
with all premiums therefor paid by the Company and coverage under other employee
benefit plans will continue for four years.  In the event that the payments to
the executive upon termination of employment following a change in control would
subject the executive to the excise tax on excess parachute payments under the
Internal Revenue Code, the Company will reimburse the executive for such excise
tax (and the income tax and excise tax on such reimbursement). In the event of a
dispute over an executive's rights under the executive's agreement following a
change in control of the Company, the Company will pay the executive's
reasonable legal fees with respect to the dispute unless the executive's claims
are found to be frivolous.

                              DIRECTOR COMPENSATION

ANNUAL CASH RETAINER FEES

Directors who are not employees of the Company receive an annual retainer of
$20,000.  Non-employee directors who chair any of the Board Committees receive
an additional annual fee of $3,000.

MEETING FEES

Directors who are not employees of the Company receive a fee of $1,000 for
attending each Board meeting and $850 for each Committee meeting.  Directors are
reimbursed for their travel, lodging and related expenses.

OUTSIDE DIRECTOR DEFERRED STOCK UNIT PLAN

In 1996, the Board of Directors adopted an Outside Director Deferred Stock Unit
Plan.

Each outside director is credited with deferred stock units ("DSUs") on an
annual basis equal in value to $15,000 ($17,000 for Committee Chairs).
Accordingly, all outside directors were credited with 1,011 DSUs (1,145 for
Committee Chairs) based on the average of the opening and closing price of a
share of common stock on June 30, 1998 ($14.84375).  The beneficial stock
ownership table in Item 12, shows the total number of DSUs credited to each of
the outside directors under this plan as of March 12, 1999.

When a director ceases to be an outside director, the amount of DSUs credited to
him or her is paid in a lump sum or in five equal annual installments.  The
first DSU installment payment would be made shortly after the director's service
ends and the other installments would be paid on the first through fourth
anniversaries of such date, based on the prevailing stock price at that time.

HEALTH AND LIFE INSURANCE BENEFITS

 The Company provides certain health and life insurance benefits to directors
who are not employees of the Company.  Each outside director who elected
coverage under the Company's health care plans contributes a portion of the
monthly costs associated with these plans.  During 1998, the following health
and life insurance benefits were received by the following directors:  Mr.
Alfiero ($138), Mr. Burkhardt ($5,448), Mr. Costle ($3,980), Mr. Donlon ($288),
Mr. Gioia ($7,665), Dr. Hill ($4,040), Mr. Panasci ($187), Dr. Peterson
($3,114), Mr. Riefler ($6,163) and Mr. Schwartz ($552).

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

                 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The following table indicates the number of shares of Common Stock owned by
persons known to the Company to own beneficially more than 5% of the outstanding
Common Stock as of December 31, 1998.

<TABLE>
<CAPTION>

                                   Name and Address of Beneficial  Amount and Nature of       Percent
Title of Class                                 Owner               Beneficial Ownership       of Class
--------------------------         -----------------------------   --------------------       --------

<S>                                     <C>                             <C>                   <C>
Common Stock. . . . . . . . . . .       Tiger Management LLC            12,714,700(a)         6.8%
                                        101 Park Avenue
                                        New York, NY 10178

Common Stock. . . . . . . . . . .       FMR Corp.                       10,877,491(b)         5.805%
                                        82 Devonshire Street
                                        Boston, Massachusetts 02109

Common Stock. . . . . . . . . . .       Fidelity Management Trust Co.   10,074,275(c)         5.377%
                                        82 Devonshire Street
                                        Boston, Massachusetts 02109

</TABLE>

(a)  Tiger Management L.L.C. has shared voting power pursuant to Schedule
     13G, dated February 12, 1999, filed with the SEC.

(b)  Includes 1,271,991 shares with respect to which FMR Corp. has sole
     voting power and 10,877,491 with sole power to dispose or to direct
     disposition as reported on Schedule 13G, dated February 1, 1999, filed
     with the Securities and Exchange Commission.

(c)  The above represents shares in the Company's Non-Represented and
     Represented Employees' Savings Fund Plans.  Fidelity Management Trust
     Company serves as Trustee.  The Trustee will vote all shares of Common
     Stock held in the Trusts established for the Plans in accordance with
     the directions received from the employees participating in the Plans.
     The Trustee will vote shares for which it receives no instructions in the
     same proportion as it votes shares for which it receives instructions.

Approximately 83.8% or 156,937,575 shares of the Company's common stock
outstanding as of December 31, 1998, are held by shareholders who elected to
hold their shares, not in their own names, but in the names of banking or
financial intermediaries.  These shares are registered in the nominee name of
The Depository Trust Company, Cede & Co.

SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS

 The following table indicates the number of shares of the Company's Common
Stock beneficially owned as of December 31, 1998, by each director of the
Company, each of the executive officers named in the Summary Compensation Table
below and the current directors and executive officers of the Company as a
group.  The table also lists the number of stock units credited to directors,
named executive officers and the directors and executive officers of the Company
as a group pursuant to the Company's compensation and benefit programs as of
December 31, 1998.  No voting rights are associated with stock units.

<TABLE>
<CAPTION>

TITLE OF                              AMOUNT AND NATURE OF      PERCENT        STOCK UNITS
CLASS    NAME OF BENEFICIAL OWNER     BENEFICIAL OWNERSHIP*    OF CLASS           HELD
------------------------------------------------------------------------------------------
<S>                                       <C>                    <C>            <C>
Common Stock
         DIRECTORS:
         Salvatore H. Alfiero. . . .       5,000                 **               1,011(6)
         William F. Allyn. . . . . .       1,000                 **              10,169(6)
         Albert J. Budney Jr.. . . .      10,625(1)              **              77,500(7)
         Lawrence Burkhardt III. . .         452                 **               3,918(6)
         Douglas M. Costle . . . . .         500                 **              10,696(6)
         William E. Davis. . . . . .      45,431(2)              **             171,000(7)
         William J. Donlon . . . . .       2,010                 **                 337(6)
         Anthony H. Gioia. . . . . .         500                 **               3,322(6)
         Bonnie G. Hill. . . . . . .       1,000                 **               9,088(6)
         Clark A. Johnson. . . . . .           0                 **               1,011(6)
         Henry A. Panasci Jr.. . . .       2,500                 **               3,322(6)
         Patti McGill Peterson . . .         500                 **              12,344(6)
         Donald B. Riefler . . . . .       1,000                 **              27,022(6)
         Stephen B. Schwartz . . . .         500                 **              12,349(6)
         NAMED EXECUTIVES:
         Darlene D. Kerr . . . . . .      15,972(3)              **              45,350(7)
         John H. Mueller . . . . . .         342                 **              24,100(7)
         Gary J. Lavine. . . . . . .      17,555(4)              **              39,250(7)
         All Directors and Executive
         Officers (24) as a group. .     157,967(5)              **             506,850 

</TABLE>

*  Based on information furnished to the Company by the Directors and Executive
   Officers.  Includes shares of Common Stock credited under the Employees'
   Savings Fund Plan as of December 31, 1998.
** Less than one percent.

(1)  Includes presently exercisable options for 10,000 shares of Common Stock.
(2)  Includes presently exercisable options for 42,625 shares of Common Stock.
(3)  Includes presently exercisable options for  9,000 shares of Common Stock.
(4)  Includes presently exercisable options for 12,000 shares of Common Stock.
(5)  Includes presently exercisable options for 106,375 shares of Common Stock.
(6)  Represents deferred stock units granted pursuant to the Outside Director
     Deferred Stock Unit Plan.  For additional information regarding deferred
     stock units, refer to Item 11, Director Compensation.
(7)  Represents stock units granted in 1997, 1998 and 1999 pursuant to the
     Long-Term Incentive Plan.  For additional information regarding stock units
     granted to named executives, refer to Item 11, Long-Term Incentive Plan.

In addition to the shares of the Company's common stock, Albert J. Budney Jr.
indirectly owns 100 shares of preferred stock, 9 % Series.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

COMPENSATION AND SUCCESSION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

No person serving during 1998 as a member of the Compensation and Succession
Committee of the Board served as an officer or employee of the Company or any of
its subsidiaries during or prior to 1998.

No person serving during 1998 as an executive officer of the Company  is or was
a director or a member of the compensation committee of any other entity that
has an executive officer who is or was a member of the Compensation and
Succession Committee or a member of the Board of Directors of Niagara Mohawk
Holdings, Inc.

                              RELATED TRANSACTIONS

Lawrence Burkhardt III received a consulting fee of $18,000 during 1998.

                                     PART IV

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

(a)  Certain documents filed as part of the Form 10-K

(1)  INDEX OF FINANCIAL STATEMENTS

-    Report of Management

-    Report of Independent Accountants

-    Consolidated Statements of Income and Retained Earnings for each of the
     three years in the period ended December 31, 1998

-    Consolidated Statements of Comprehensive Income for each of the three years
     in the period ended December 1998

-    Consolidated Balance Sheets at December 31, 1998 and 1997

-    Consolidated Statements of Cash Flows for each of the three years in the
     period ended December 31, 1998

-    Notes to Consolidated Financial Statements

-    Separate financial statements of the Company have been omitted since it is
     primarily an operating company and all consolidated subsidiaries are wholly
     owned directly or by subsidiaries.

(2)  The following financial statement schedules of the Company for the years
     ended December 31, 1998, 1997 and 1996 are included:

-    Report of Independent Accountants on Financial Statement Schedule

-    Consolidated Financial Statement Schedule:

     II--Valuation and Qualifying Accounts and Reserves

     The Financial Statement Schedule above should be read in conjunction with
     the Consolidated Financial Statements in Part II, Item 8 (Financial
     Statements and Supplementary Data).

     Schedules other than those mentioned above are omitted because the
     conditions requiring their filing do not exist or because the required
     information is given in the financial statements, including the notes
     thereto.

(3)  List of Exhibits:

     See Exhibit Index.

(b)  Reports on Form 8-K:

     Form 8-K Reporting Date - December 3, 1998
     Items reported:
         (1)  Item 5. Other Events.
              Registrant filed press release regarding the Company's agreement
              to sell its hydroelectric generating plants.
         (2)  Item 7. Financial Statement and Exhibits.
              Exhibits required to be filed by Item 601 of Regulation S-K.

     Form 8-K Reporting Date - December 23, 1998
     Items reported:
         (1)  Item 5. Other Events.
              (a)  Registrant filed press release regarding a favorable ruling
                   from the Internal Revenue Service regarding current
                   deductibility of consideration paid to certain IPPs to
                   terminate power contracts under the MRA.
              (b)  Registrant filed press release regarding the Company's
                   agreement to sell its two coal-fired electric generating
                   plants.
         (2)  Item 7. Financial Statements and Exhibits.
              Exhibits required to be filed by Item 601 of Regulation S-K.

     Form 8-K Reporting Date - January 28, 1999
     Items reported:
         (1)  Item 5. Other Events
              (a)  Registrant filed press release announcing plans to pursue
                   the sale of the Company's Unit 1 nuclear and plant and its
                   41% ownership in the Unit 2 nuclear plant.
              (b)  Registrant filed a press release regarding annual and fourth
                   quarter earnings for 1998.
         (2)  Item 7. Financial Statements and Exhibits.
              Exhibits required to be filed by Item 601 of Regulation S-K.

(c)  Exhibits.

     See Exhibit Index.

(d)  Financial Statement Schedule

     See (a)(2) above.

<PAGE>

REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE

To the Board of Directors of
Niagara Mohawk Power Corporation

Our audits of the consolidated financial statements of Niagara Mohawk Power
Corporation referred to in our report dated January 28, 1999 appearing in this
Form 10-K also included an audit of the Financial Statement Schedule listed in
Item 14(a) of this Form 10- K.  In our opinion, this Financial Statement
Schedule presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements.




/s/PricewaterhouseCoopers LLP
-----------------------------
PricewaterhouseCoopers LLP
Syracuse, New York
January 28, 1999

<PAGE>

            NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
          SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
          ------------------------------------------------------------

<TABLE>
<CAPTION>

(In thousands of dollars)
Column A                    Column B            Column C             Column D    Column E
-------------------------  ----------         -----------           ----------   ---------
                                                Additions
                                         -----------------------
                           Balance at    Charged to   Charged to                  Balance
                            Beginning     Costs and     Other       Deductions     at End
Description                 of Period     Expenses     Accounts         (a)      of Period
-------------------------  ----------    ----------   ----------    ----------   ---------
<S>                        <C>           <C>          <C>           <C>          <C>
Allowance for Doubtful
Accounts - Deducted from
Accounts Receivable in
the Consolidated
Balance Sheets

1998. . . . . . . . . . .  $   62,548    $ 31,727     $  5,000 (b)  $  51,412    $ 47,863
1997. . . . . . . . . . .      52,096      46,549        3,000 (b)     39,097      62,548
1996. . . . . . . . . . .      20,000     127,648          800 (b)     96,352      52,096

</TABLE>

(a)  Uncollectible accounts written off net of recoveries of $14,734,
    $14,416, and $12,842 in 1998, 1997 and 1996, respectively.

(b)  The Company has recorded a regulatory asset, which reflects the amount
     of doubtful accounts reserved for what the Company expects to recover in
     rates.  In 1996, regulatory asset increased by $800 to $17,200; in 1997,
     the regulatory asset was increased by $3,000 to $20,200; and in 1998, the
     regulatory asset was increased by $5,000 to $25,200.

            NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
          SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
          ------------------------------------------------------------
<TABLE>
<CAPTION>

(In thousands of dollars)
Column A                    Column B           Column C            Column D     Column E
-------------------------  ----------        -----------         -----------   -----------
                                               Additions
                                        -----------------------
                           Balance at   Charged to   Charged to                  Balance
                            Beginning    Costs and      Other                     at End
Description                 of Period    Expenses     Accounts    Deductions   of Period (c)
-------------------------  ----------   ----------  -----------  -----------   --------------
<S>                        <C>          <C>          <C>         <C>           <C>
Miscellaneous
Valuation Reserves

1998. . . . . . . . . . .  $   45,261   $      769   $     -     $    12,967   $    33,063
1997. . . . . . . . . . .      47,103        2,207         -           4,049        45,261
1996. . . . . . . . . . .      48,789       10,261         -          11,947        47,103

</TABLE>

(c)  The reserves relate primarily to certain inventory and non-rate base
     properties.

NOTE:  The 1996 and 1997 balances have been restated to reflect the inclusion
       of the reserve for loss on the Company's investment in NM Uranium, Inc.

<PAGE>

                        NIAGARA MOHAWK POWER CORPORATION

                                  EXHIBIT INDEX
                                  -------------

In the following exhibit list, NMPC refers to the Company and CNYP refers to
Central New York Power Corporation, a predecessor company.  Each document
referred to below is incorporated by reference to the files of the Commission,
unless the reference to the document in the list is preceded by an asterisk.
Previous filings with the Commission are indicated as follows:

Reference               Report Name
---------               -----------

A          NMPC Registration Statement No. 2-8214
C          NMPC Registration Statement No. 2-8634
F          CNYP Registration Statement No. 2-3414
G          CNYP Registration Statement No. 2-5490
V          NMPC Registration Statement No. 2-10501
X          NMPC Registration Statement No. 2-12443
Z          NMPC Registration Statement No. 2-13285
CC         NMPC Registration Statement No. 2-16193
DD         NMPC Registration Statement No. 2-18995
GG         NMPC Registration Statement No. 2-25526
HH         NMPC Registration Statement No. 2-26918
II         NMPC Registration Statement No. 2-29575
JJ         NMPC Registration Statement No. 2-35112
KK         NMPC Registration Statement No. 2-38083
OO         NMPC Registration Statement No. 2-49570
QQ         NMPC Registration Statement No. 2-51934
SS         NMPC Registration Statement No. 2-52852
TT         NMPC Registration Statement No. 2-54017
VV         NMPC Registration Statement No. 2-59500
CCC        NMPC Registration Statement No. 2-70860
III        NMPC Registration Statement No. 2-90568
OOO        NMPC Registration Statement No. 33-32475
PPP        NMPC Registration Statement No. 33-38093
QQQ        NMPC Registration Statement No. 33-47241
RRR        NMPC Registration Statement No. 33-59594
SSS        NMPC Registration Statement No. 33-49541
b          NMPC Annual Report on Form 10-K for year ended December 31, 1990
c          NMPC Annual Report on Form 10-K for year ended December 31, 1992
d          NMPC Annual Report on Form 10-K for year ended December 31, 1993
e          NMPC Annual Report on Form 10-K for year ended December 31, 1994
f          NMPC Annual Report on Form 10-K for year ended December 31, 1995
g          NMPC Annual Report on Form 10-K for year ended December 31, 1996
h          NMPC Annual Report on Form 10-K for year ended December 31, 1997
i          NMPC Quarterly Report on Form 10-Q for quarter ended March 31, 1993
j          NMPC Quarterly Report on Form 10-Q for quarter ended September 30,
           1993
k          NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1995
l          NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1997
m          NMPC Quarterly Report on Form 10-Q for quarter ended September
           30, 1997
n          NMPC Quarterly Report on Form 10-Q for quarter ended March 31, 1998
o          NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1998
p          NMPC Quarterly Report on Form 10-Q for quarter ended September
           30, 1998
q          NMPC Report on Form 8-K dated July 9, 1997
r          NMPC Report on Form 8-K dated October 10, 1997

In accordance with Paragraph 4(iii) of Item 601 (b) of Regulation S-K, the
Company agrees to furnish to the Securities and Exchange Commission, upon
request, a copy of the agreements comprising the $804 million senior bank
financing that the Company completed with a bank group during March 1996 and
subsequently amended (effective June 30, 1998).  The total amount of long-term
debt authorized under such agreement does not exceed 10 percent of the total
consolidated assets of the Company and its subsidiaries.

<PAGE>

                                                    INCORPORATION BY REFERENCE
                                                    --------------------------
                                                    PREVIOUS   PREVIOUS EXHIBIT
EXHIBIT NO.      DESCRIPTION OF INSTRUMENT           FILING      DESIGNATION
----------       -------------------------          --------   ----------------

3(a)(1)      Certificate of Consolidation of New
             York Power and Light Corporation,
             Buffalo Niagara Electric Corporation
             and Central New York Power Corporation,
             filed in the office of the New York
             Secretary of State, January 5, 1950         e          3(a)(1)

3(a)(2)      Certificate of Amendment of Certificate
             of Incorporation of NMPC, filed in the
             office of the New York Secretary of
             State, January 5, 1950                      e          3(a)(2)

3(a)(3)      Certificate of Amendment of Certificate
             of Incorporation of NMPC, pursuant to
             Section 36 of the Stock Corporation Law of
             New York, filed August 22, 1952, in the
             office of the New York Secretary of State   e          3(a)(3)

3(a)(4)      Certificate of NMPC pursuant to Section
             11 of the Stock Corporation Law of New
             York filed May 5, 1954 in the office of
             the New York Secretary of State             e          3(a)(4)

3(a)(5)      Certificate of Amendment of Certificate of
             Incorporation of NMPC, pursuant to Section
             36 of the Stock Corporation Law of New
             York, filed January 9, 1957 in the office
             of the New York Secretary of State          e          3(a)(5)

3(a)(6)      Certificate of NMPC pursuant to Section
             11 of the Stock Corporation Law of New
             York, filed May 22, 1957 in the office of
             the New York Secretary of State             e          3(a)(6)

3(a)(7)      Certificate of NMPC pursuant to Section
             11 of the Stock Corporation Law of New
             York, filed February 18, 1958 in the office
             of the New York Secretary of State          e          3(a)(7)

3(a)(8)      Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed May 5, 1965 in the office
             of the New York Secretary of State          e          3(a)(8)

3(a)(9)      Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of New
             York, filed August 24, 1967 in the office
             of the New York Secretary of State          e          3(a)(9)

3(a)(10)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of New
             York, filed August 19, 1968 in the office
             of the New York Secretary of State          e          3(a)(10)

3(a)(11)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of New
             York, filed September 22, 1969 in the office
             of the New York Secretary of State          e          3(a)(11)

3(a)(12)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of New
             York, filed May 12, 1971 in the office of
             the New York Secretary of State             e          3(a)(12)

3(a)(13)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed August 18, 1972 in the
             office of the New York Secretary of State   e          3(a)(13)

3(a)(14)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed June 26, 1973 in the
             office of the New York Secretary of State   e          3(a)(14)

3(a)(15)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed May 9, 1974 in the
             office of the New York Secretary of State   e          3(a)(15)

3(a)(16)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed March 12, 1975 in the
             office of the New York Secretary of State   e          3(a)(16)

3(a)(17)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed May 7, 1975 in the
             office of the New York Secretary of State   e          3(a)(17)

3(a)(18)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed August 27, 1975 in the
             office of the New York Secretary of State   e          3(a)(18)

3(a)(19)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York, filed May 7, 1976 in the
             office of the New York Secretary of State   e          3(a)(19)

3(a)(20)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed September 28, 1976 in the
             office of the New York Secretary of State   e          3(a)(20)

3(a)(21)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed January 27, 1978 in the
             office of the New York Secretary of State   e          3(a)(21)

3(a)(22)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed May 8, 1978 in the
             office of the New York Secretary of State   e          3(a)(22)

3(a)(23)     Certificate of Correction of the
             Certificate of Amendment filed May 7,
             1976 of the Certificate of Incorporation
             under Section 105 of the Business
             Corporation Law of New York filed
             July 13, 1978 in the office of the
             New York Secretary of State                 e          3(a)(23)

3(a)(24)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed July 17, 1978 in the
             office of the New York Secretary of State   e          3(a)(24)

3(a)(25)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed March 3, 1980 in the
             office of the New York Secretary of State   e          3(a)(25)

3(a)(26)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed March 31, 1981 in the
             office of the New York Secretary of State   e          3(a)(26)

3(a)(27)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed March 31, 1981 in the
             office of the New York Secretary of State   e          3(a)(27)

3(a)(28)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed April 22, 1981 in the
             office of the New York Secretary of State   e          3(a)(28)

3(a)(29)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed May 8, 1981 in the office
             of the New York Secretary of State          e          3(a)(29)

3(a)(30)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed April 26, 1982 in the
             office of the New York Secretary of State   e          3(a)(30)

3(a)(31)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed January 24, 1983 in the
             office of the New York Secretary of State   e          3(a)(31)

3(a)(32)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed August 3, 1983 in the
             office of the New York Secretary of State   e          3(a)(32)

3(a)(33)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed December 27, 1983 in the
             office of the New York Secretary of State   e          3(a)(33)

3(a)(34)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed December 27, 1983 in the
             office of the New York Secretary of State   e          3(a)(34)

3(a)(35)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed June 4, 1984 in the
             office of the New York Secretary of State   e          3(a)(35)

3(a)(36)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed August 29, 1984 in the
             office of the New York Secretary of State   e          3(a)(36)

3(a)(37)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed April 17, 1985, in the
             office of the New York Secretary of State   e          3(a)(37)

3(a)(38)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed May 3, 1985, in the
             office of the New York Secretary of State   e          3(a)(38)

3(a)(39)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed December 24, 1986 in the
             office of the New York Secretary of State   e          3(a)(39)

3(a)(40)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed June 1, 1987 in the
             office of the New York Secretary of State   e          3(a)(40)

3(a)(41)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed July 16, 1987 in the
             office of the New York Secretary of State   e          3(a)(41)

3(a)(42)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed May 27, 1988 in the
             office of the New York Secretary of State   e          3(a)(42)

3(a)(43)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed September 27, 1990 in the
             office of the New York Secretary of State   e          3(a)(43)

3(a)(44)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed October 18, 1991 in the
             office of the New York Secretary of State   e          3(a)(44)

3(a)(45)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed May 5, 1994 in the
             office of the New York Secretary of State   e          3(a)(45)

3(a)(46)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section
             805 of the Business Corporation Law of
             New York filed August 5, 1994 in the
             office of the New York Secretary of State   e          3(a)(46)

3(a)(47)     Certificate of Amendment of Certificate
             of Incorporation of NMPC under Section 805
             of the Business Corporation Law of New
             York filed June 29, 1998 in the office of
             the New York Secretary of State             o          3

3(b)(1)      By-Laws of NMPC, as amended April 23, 1998  n          3(i)

4(a)         Agreement to furnish certain debt
             instruments                                 e          4(b)

4(b)(1)      Mortgage Trust Indenture dated as of
             October 1, 1937 between NMPC (formerly
             CNYP) and Marine Midland Bank, N.A.
             (formerly named The Marine Midland Trust
             Company of New York), as Trustee            F          **

4(b)(2)      Supplemental Indenture dated as of
             December 1, 1938, supplemental to
             Exhibit 4(1)                                VV         2-3

 4(b)(3)     Supplemental Indenture dated as of
             April 15, 1939, supplemental to
             Exhibit 4(1)                                VV         2-4

4(b)(4)      Supplemental Indenture dated as of
             July 1, 1940, supplemental to
             Exhibit 4(1)                                VV         2-5

4(b)(5)      Supplemental Indenture dated as of
             October 1, 1944, supplemental to
             Exhibit 4(1)                                G          7-6

4(b)(6)      Supplemental Indenture dated as of
             June 1, 1945, supplemental to
             Exhibit 4(1)                                VV         2-8

4(b)(7)      Supplemental Indenture dated as of
             August 17, 1948, supplemental to
             Exhibit 4(1)                                VV         2-9

4(b)(8)      Supplemental Indenture dated as of
             December 31, 1949, supplemental to
             Exhibit 4(1)                                A          7-9

4(b)(9)      Supplemental Indenture dated as of
             January 1, 1950, supplemental to
             Exhibit 4(1)                                A          7-10
4(b)(10)     Supplemental Indenture dated as of
             October 1, 1950, supplemental to
             Exhibit 4(1)                                C          7-11

4(b)(11)     Supplemental Indenture dated as of
             October 19, 1950, supplemental to
             Exhibit 4(1)                                C          7-12

4(b)(12)     Supplemental Indenture dated as of
             February 20, 1953, supplemental to
             Exhibit 4(1)                                V          4-16

4(b)(13)     Supplemental Indenture dated as of
             April 25, 1956, supplemental to
             Exhibit 4(1)                                X          4-19

4(b)(14)     Supplemental Indenture dated as of
             March 15, 1960, supplemental to
             Exhibit 4(1)                                CC         2-23

4(b)(15)     Supplemental Indenture dated as of
             October 1, 1966, supplemental to
             Exhibit 4(1)                                GG         2-27

4(b)(16)     Supplemental Indenture dated as of
             July 15, 1967, supplemental to
             Exhibit 4(1)                                HH         4-29

4(b)(17)     Supplemental Indenture dated as of
             August 1, 1967, supplemental to
             Exhibit 4(1)                                HH         4-30

4(b)(18)     Supplemental Indenture dated as of
             August 1, 1968, supplemental to
             Exhibit 4(1)                                II         2-30

4(b)(19)     Supplemental Indenture dated as of
             March 15, 1977, supplemental to
             Exhibit 4(1)                                VV         2-39

4(b)(20)     Supplemental Indenture dated as of
             August 1, 1977, supplemental to
             Exhibit 4(1)                                CCC        4(b)(40)

4(b)(21)     Supplemental Indenture dated as of
             March 1, 1978, supplemental to
             Exhibit 4(1)                                CCC        4(b)(42)

4(b)(22)     Supplemental Indenture dated as of
             June 15, 1980, supplemental to
             Exhibit 4(1)                                CCC        4(b)(46)

4(b)(23)     Supplemental Indenture dated as of
             November 1, 1985, supplemental to
             Exhibit 4(1)                                III        4(b)(64)

4(b)(24)     Supplemental Indenture dated as of
             October 1, 1989, supplemental to
             Exhibit 4(1)                                OOO        4(b)(73)

4(b)(25)     Supplemental Indenture dated as of
             June 1, 1990, supplemental to
             Exhibit 4(1)                                PPP        4(b)(74)

4(b)(26)     Supplemental Indenture dated as of
             November 1, 1990, supplemental to
             Exhibit 4(1)                                PPP        4(b)(75)

4(b)(27)     Supplemental Indenture dated as of
             March 1, 1991, supplemental to
             Exhibit 4(1)                                QQQ        4(b)(76)

4(b)(28)     Supplemental Indenture dated as of
             October 1, 1991, supplemental to
             Exhibit 4(1)                                QQQ        4(b)(77)

4(b)(29)     Supplemental Indenture dated as of
             April 1, 1992, supplemental to
             Exhibit 4(1)                                QQQ        4(b)(78)

4(b)(30)     Supplemental Indenture dated as of
             June 1, 1992, supplemental to
             Exhibit 4(1)                                RRR        4(b)(79)

4(b)(31)     Supplemental Indenture dated as of
             July 1, 1992, supplemental to
             Exhibit 4(1)                                RRR        4(b)(80)

4(b)(32)     Supplemental Indenture dated as of
             August 1, 1992, supplemental to
             Exhibit 4(1)                                RRR        4(b)(81)

4(b)(33)     Supplemental Indenture dated as of
             April 1, 1993, supplemental to
             Exhibit 4(1)                                i          4(b)(82)

4(b)(34)     Supplemental Indenture dated as of
             July 1, 1993, supplemental to
             Exhibit 4(1)                                j          4(b)(83)

4(b)(35)     Supplemental Indenture dated as of
             September 1, 1993, supplemental to
             Exhibit 4(1)                                j          4(b)(84)

4(b)(36)     Supplemental Indenture dated as of
             March 1, 1994, supplemental to
             Exhibit 4(1)                                d          4(b)(85)

4(b)(37)     Supplemental Indenture dated as of
             July 1, 1994, supplemental to
             Exhibit 4(1)                                e          4(86)

4(b)(38)     Supplemental Indenture dated as of
             May 1, 1995, supplemental to
             Exhibit 4(1)                                k          4(87)

4(b)(39)     Supplemental Indenture dated
             as of March 20, 1996, supplemental
             to Exhibit 4(1)                             SSS        4(a)(39)

4(b)(40)     Agreement dated as of August 16, 1940,
             between CNYP, The Chase National Bank
             of the City of New York, as Successor
             Trustee, and The Marine Midland Trust
             Company of New York, as Trustee             G          7-23

4(c)         Form of Indenture relating to the Senior
             Notes dated June 30, 1998                   SSS        4(a)(41)

10-1         Agreement dated March 1, 1957 between
             the Power Authority of the State of
             New York and NMPC as to sale,
             transmission and disposition of St.
             Lawrence power                              Z          13-11

10-2         Agreement dated February 10, 1961
             between the Power Authority of the
             State of New York and NMPC as to sale,
             transmission and disposition of
             Niagara redevelopment power                 DD         13-6

10-3         Agreement dated July 26, 1961
             between the Power Authority of the
             State of New York and NMPC
             supplemental to Exhibit 10-2                DD         13-7

10-4         Agreement dated as of March 23, 1973
             between the Power Authority of the
             State of New York and NMPC as to
             the sale, transmission and disposition
             of Blenheim-Gilboa power                    OO         5-8

10-5         Agreement dated January 23, 1970
             between Consolidated Gas Supply
             Corporation (formerly named New York
             State Natural Gas Corporation) and NMPC     KK         5-8

10-6a        New York Power Pool Agreement
             dated as of February 1, 1974
             between NMPC and six other New York
             utilities and the Power Authority
             of the State of New York                    QQ         5-10

10-6b        New York Power Pool Agreement
             dated as of April 27, 1975 between
             NMPC and six other New York electric
             utilities and the Power Authority of
             the State of New York (the parties
             to the Agreement have petitioned
             the Federal Power Commission for an
             order permitting such Agreement,
             which increases the reserve factor
             of all parties from .14 to .18,
             to supersede the New York Power
             Agreement dated as of
             February 1, 1974)                           TT         5-10b

10-7         Agreement dated as of October 31, 1968
             between NMPC, Central Hudson Gas &
             Electric Corporation and Consolidated
             Edison Company of New York, Inc. as
             to Joint Electric Generating Plant
             (the Roseton Station)                       JJ         5-10

10-8a        Memorandum of Understanding dated as
             of May 30, 1975 between NMPC and
             Rochester Gas & Electric Corporation
             with respect to Oswego Unit No.6            SS         5-13

10-8b        Memorandum of Understanding dated as
             of May 30, 1975 between NMPC and
             Rochester Gas and Electric Corporation
             with respect to Oswego Unit No. 6           SS         5-13

10-8c        Basic Agreement dated as of September 22,
             1975 between NMPC and Rochester Gas and
             Electric Corporation with respect to
             Oswego Unit No. 6                           VV         5-13b

10-9a        Memorandum of Understanding dated
             as of May 30, 1975 between NMPC and
             four other New York electric utilities
             with respect to Nine Mile Point Nuclear
             Station Unit No. 2                          SS         5-14

10-9b        Basic Agreement dated as of
             September 22, 1975 between NMPC and
             four other New York electric utilities
             with respect to Nine Mile Point
             Nuclear Station Unit No. 2                  VV         5-14b

10-9c        Nine Mile Point Nuclear Station Unit
             No. 2 Operating Agreement                   c          10-19

10-10        Master Restructuring Agreement, dated as
             of July 9, 1997, between the Company and
             the sixteen independent power producers
             signatory thereto                           q          10.28

10-11        POWERCHOICE settlement filed with the PSC
             on October 10, 1997                         r          99-9

10-12        PSC Opinion and Order regarding approval    h          10-13
             of the POWERCHOICE settlement agreement
             with PSC, issued and effective
             March 20, 1998

10-13        Preferred Consent, December, 1997           h          10-14

10-14        Amendments to the Master Restructuring
             Agreement                                   n          10(c)

(A)10-15     NMPC Officers' Incentive Compensation
             Plan - Plan Document                        b          10-16

(A)10-16     NMPC Long Term Incentive Plan - Plan
             Document.                                   l          10-1

(A)10-17     NMPC Management Incentive Compensation
             Plan - Plan Document.                       b          10-17

(A)10-18     CEO Special Award Plan                      l          10-2

(A)10-19     NMPC Deferred Compensation Plan             d          10-16

(A)10-20     Amendment to NMPC Deferred
             Compensation Plan                           h          10-20

(A)10-21     NMPC Performance Share Unit Plan            d          10-17

(A)10-22     NMPC 1992 Stock Option Plan                 d          10-18

(A)10-23     NMPC 1995 Stock Incentive Plan              f          10-31

(A)10-24     Employment Agreement between NMPC
             and David J. Arrington, Sr. Vice President,
             Human Resources, dated December
             20, 1996                                    g          10-17

(A)10-25     Employment Agreement between NMPC
             and Albert J. Budney Jr., President and
             Chief Operating Officer, December
             20, 1996                                    g          10-18

(A)10-26     Employment Agreement between NMPC
             and William E. Davis, Chairman of the Board
             and Chief Executive Officer, dated December
             20, 1996                                    g          10-19

(A)10-27     Employment Agreement between NMPC
             and Darlene D. Kerr, Sr. Vice President,
             Energy Distribution, dated December
             20, 1996                                    g          10-20

(A)10-28     Employment Agreement between NMPC and
             Gary J. Lavine, Sr. Vice President,
             Legal and Corporate Relations, dated
             December 20, 1996                           g          10-21

(A)10-29     Employment Agreement between NMPC and
             B. Ralph Sylvia, Executive Vice
             President, Electric Generation and
             Chief Nuclear Officer, dated
             December 20, 1996                           g          10-23

(A)10-30     Employment Agreement between NMPC and
             Theresa A. Flaim, Vice President -
             Corporate Strategic Planning, dated
             December 20, 1996                           g          10-24

(A)10-31     Employment Agreement between NMPC and
             Steven W. Tasker, Vice President -
             Controller, dated December 20, 1996         g          10-25

(A)10-32     Employment Agreement between NMPC and
             Kapua A. Rice, Corporate Secretary,
             dated December 20, 1996                     g          10-26

(A)10-33     Amendment to Employment Agreement between
             NMPC and David J. Arrington, Albert J.
             Budney Jr., William E. Davis, Darlene D.
             Kerr, Gary J. Lavine, John W. Powers and
             B. Ralph Sylvia, dated June 9, 1997         l          10-3

(A)10-34     Employment Agreement between NMPC and
             William F. Edwards, dated September
             25, 1997                                    m          10-4

(A)10-35     Employment Agreement between NMPC and
             John H. Mueller, dated January 19, 1998     h          10-36

(A)10-36     Deferred Stock Unit Plan for Outside
             Directors                                   g          10-27

(A)10-37     Amendment to the Deferred Stock Unit        o          10
             Plan for Outside Directors

(A)10-38     Amendment to the Deferred Stock Unit        p          10
             Plan for Outside Directors

*(A)10-39    Employment Agreement between NMPC
             and Thomas H. Baron, dated October 22, 1998

*(A)10-40    Employment Agreement between NMPC
             and Edward J. Dienst, dated October 22, 1998

*(A)10-41    Amendment to the NMPC Officers
             Incentive Compensation Plan

*11          Statement setting forth the computation of
             average number of shares of common stock
             outstanding

*12          Statements Showing Computations of
             Certain Financial Ratios

*21          Subsidiaries of the Registrant

*23          Consent of PricewaterhouseCoopers LLP,
             independent accountants

*27          Financial Data Schedule

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

**Filed October 15, 1937 after effective date of Registration Statement No.
  2-3414.

(A)  Management contract or compensatory plan or arrangement required to be
    filed as an exhibit pursuant to Item 601 of Regulation S-K.

<PAGE>


               EXHIBIT (A) 10-39                                             
          
          
          
          
                                     EMPLOYMENT AGREEMENT
          
          
          
          
 Agreement made as of the 22nd day of October, 1998, between NIAGARA
 MOHAWK POWER CORPORATION (the "Company"), and Thomas H. Baron (the
 "Executive").
          
 WHEREAS, the Company desires to employ the Executive, and the Executive
 desires to accept/continue employment with the Company, on the terms and
 conditions hereinafter set forth.
          
 NOW, THEREFORE, in consideration of the mutual covenants and agreements
 hereinafter set forth, the Company and the Executive hereby agree as follows:
                   
  1.   Term of Agreement.  The Company shall employ the Executive, and
 the Executive shall serve the Company, for the period beginning October 22,
 1998 and expiring on December 31, 2001, subject to earlier termination as
 provided under paragraph 4 hereof.  This Agreement shall be extended 
automatically by one year commencing on January 1, 2000 and on January 1st of 
each year thereafter, unless either party notifies the other to the contrary not
later than sixty (60) days prior to such date. Notwithstanding any such 
notice by the Company, this Agreement shall remain in effect for a period of
thirty-six months from the date of a "Change in Control" (as that term is
 defined in Schedule B hereto, unless such notice was given
 at least 18 months prior to the date of the Change in Control). 
         
 2.   Duties.  The Executive shall serve the Company as its Senior Vice
 President - Field Operations.  During the term of this Agreement, the Executive
 shall, except during vacation or sick leave, devote the whole of the 
 Executive's time, attention and skill to the business of the Company during
 usual business hours (and outside those hours when reasonably necessary to 
 the Executive's duties hereunder); faithfully and diligently perform such 
 duties and exercise such powers as may be from time to time assigned to or
 vested in the Executive by the Company's Board of Directors (the "Board") or by
 any officer of the Company superior to the Executive; obey the directions of 
 the Board and of any officer of the Company superior to the Executive; and 
 use the Executive's best efforts to promote the interests of the Company. The 
 Executive may be required in pursuance of the Executive's duties hereunder
 to perform services for any company controlling, controlled by or under 
 common control with the Company (such companies hereinafter collectively 
 called "Affiliates") and to accept such offices in any Affiliates as the 
 Board may require.  The Executive shall obey all policies of the Company and
 applicable policies of its Affiliates.
          
 3.   Compensation.  During the term of this Agreement:
 a.   The Company shall pay the Executive a base salary at an annual rate of
 $215,000, which shall be payable periodically in accordance with the
 Company's then prevailing payroll practices, or such greater amount as the 
 Company may from time to time determine;
 b.   The Executive shall be entitled to participate in the Company's
 Supplemental Executive Retirement Plan ("SERP") according to its terms, as
 modified by Schedule A hereto;
 c.   The Executive shall be entitled to participate in the Company's
 Officers Incentive Compensation Plan, 1995 Stock Incentive Plan, and Long
 Term Incentive Plan, and any successors thereto, in accordance with the terms
 thereof; and  
 d.   The Executive shall be entitled to such expense accounts,
 vacation time, sick leave, perquisites of office, fringe benefits, insurance
 coverage, and other terms and conditions of employment as the Company generally
 provides to its employees having rank and seniority at the Company comparable
 to the Executive.
          
 4.   Termination.  The Company shall continue to employ the Executive,
 and the Executive shall continue to work for the Company, during the term of 
 this Agreement, unless the Agreement is terminated in accordance with the
 following provisions:
 a.   This Agreement shall terminate automatically upon the death of the
 Executive.  Any right or benefit accrued on behalf of the Executive or to
 which the Executive became entitled under the terms of this Agreement prior to
 death (other than payment of base salary in respect of the period following the
 Executive's death), and any obligation of the Company to the Executive in 
 respect of any such right or benefit, shall not be extinguished by reason of 
 the Executive's death.  Any base salary earned and unpaid as of the date of the
 Executive's death shall be paid to the Executive's estate in accordance with 
 paragraph 4g below.
 b.   By notice to the Executive, the Company may terminate this Agreement
 upon the "Disability" of the Executive. The Executive shall be deemed to
 incur a Disability when (i) a physician selected by the Company advises the 
 Company that the Executive's physical or mental condition has rendered the 
 Executive unable to perform the essential functions of the Executive's position
 in a reasonable manner, with or without reasonable accommodation and will 
 continue to render him unable to perform the essential functions of the 
 Executive's position in such manner, for a period exceeding 12 consecutive 
 months, or (ii) due to a physical or mental condition, the Executive has not  
 performed the essential functions of the Executive's position in a 
 reasonable manner, with or without reasonable accommodation, for a period of 12
 consecutive months. Following termination of this Agreement pursuant to 
 clause (i) of the preceding sentence of this paragraph, the Executive shall
 continue to receive his base salary under paragraph 3a hereof for a period 
 of 12 months from the date of his Disability, reduced by any benefits payable
 during such period under the Company's short-term disability plan and long-term
 disability plan. Thereafter, or in the event of termination of this Agreement
 pursuant to clause (ii) of the preceding sentence, the Executive shall receive
 benefits under the Company's long-term disability plan in lieu of any further
 base salary under paragraph 3a hereof.   
 c.   By notice to the Executive, the Company may terminate the Executive's
 employment at any time for "Cause".  The Company must deliver such
 notice within ninety (90) days after the Board both (i) has or should have had
 knowledge of conduct or an event allegedly constituting Cause, and (ii) has 
 reason to believe that such conduct or event could be grounds for Cause.  For 
 purposes of this Agreement ACause@ shall mean  (i) the Executive is convicted 
 of, or has plead guilty or nolo contendere to, a felony; (ii) the willful and 
 continued failure by the Executive to perform substantially his duties with 
 the Company (other than any such failure resulting from incapacity due to 
 physical or mental illness) after a demand for substantial performance is 
 delivered to the Executive by the Company which specifically identifies the 
 manner in which the Company believes the Executive has not substantially 
 performed his duties; (iii) the Executive engages in conduct that constitutes
 gross neglect or willful misconduct in carrying out his duties under this 
 Agreement involving material economic harm to the Company or any of its
 subsidiaries; or (iv) the Executive has engaged in a material breach of 
 Sections 6 or 7 of this Agreement.  In the event the termination notice is 
 based on clause (ii) of the preceding sentence, the Executive shall have ten
 (10) business days following receipt of the notice of termination to cure his
 conduct, to the extent such cure is possible, and if the Executive does not
 cure within the ten (10) business day period, his termination of employment 
 in accordance with such termination notice shall be deemed to be for Cause. 
 The determination of Cause shall be made by the Board upon the recommendation
 of the Compensation and Succession Committee of the Board.  Following a Change
 in Control, such determination shall be made in a resolution duly adopted by
 the affirmative vote of not less than three-fourths (3/4) of the membership 
 of the Board, excluding members who are employees of the Company, at a meeting
 called for the purpose of determining that Executive has engaged in conduct
 which constitutes Cause (and at which Executive had a reasonable opportunity, 
 together with his counsel, to be heard before the Board prior to such
 vote).  The Executive shall not be entitled to the payment of any additional
 compensation from the Company, except to the extent provided in paragraph 4h 
 hereof, in the event of the termination of his employment for Cause.
 d.   If any of the following events, any of which shall constitute "Good
 Reason", occurs within thirty-six months after a Change in Control, the
 Executive, by notice of the Company, may voluntarily terminate the Executive's
 employment for Good Reason within ninety (90) days after the Executive both (i)
 has or should have had knowledge of conduct or an event allegedly constituting
 Good Reason, and (ii) has reason to believe that such conduct or event could be
 grounds for Good Reason.  In such event, the Executive shall be entitled to the
 severance benefits set forth in paragraph 4g below.
 (i) the Company assigns any duties to the Executive which are materially
 inconsistent in any adverse respect with the Executive's position, duties, 
 offices, responsibilities or reporting requirements immediately prior to a
 Change in Control,including any diminution of such duties or responsibilities;
 or
 (ii)  the Company reduces the Executive's base salary, including salary
 deferrals, as in effect immediately prior to a Change in Control; or
 (iii)  the Company discontinues any bonus or other compensation plan or
 any other benefit, retirement plan (including the SERP), stock ownership plan,
 stock purchase plan, stock option plan, life insurance plan, health plan, 
 disability plan or similar plan (as the same existed immediately prior to the
 Change in Control) in which the Executive participated or was eligible to 
 participate in immediately prior to the Change in Control and in lieu thereof 
 does not make available plans providing at least comparable benefits; or
 (iv)  the Company takes action which adversely affects the Executive's
 participation in, or eligibility for, or materially reduces the Executive's 
 benefits under, any of the plans described in (iii) above, or deprives the
 Executive of any material fringe benefit enjoyed by the Executive immediately 
 prior to the Change in Control, or fails to provide the Executive with the 
 number of paid vacation days to which the Executive was entitled immediately 
 prior to the Change in Control; or 
 (v)  the Company requires the Executive to be based at any office or location
 other than one within a 50-mile radius of the office or location at which
 the Executive was based immediately prior to the Change in Control; or
 (vi)  the Company purports to terminate the Executive's employment
 otherwise than as expressly permitted by this Agreement; or
 (vii)  the Company fails to comply with and satisfy Section 5 hereof,
 provided that such successor has received prior written notice from the 
 Company or from the Executive of the requirements of Section 5 hereof.
 The Executive shall have the sole right to determine, in good
 faith, whether any of the above events has occurred.
 e.   The Company may terminate the Executive's employment at any
 time without Cause. 
 f.   In the event that the Executive's employment is terminated by the
 Company without Cause prior to a Change in Control, the Company shall pay the
 Executive a lump sum severance benefit, equal to two years' base salary at the
 rate in effect as of the date of termination, plus the greater of (i) two times
 the most recent annual bonus paid to the Executive under the Corporation's 
 Annual Officers Incentive Compensation Plan (the AOICP@) or any similar annual
 bonus plan (excluding the pro rata bonus referred to in the next sentence) or
 (ii) two times the average annual bonus paid to the Executive for the three 
 prior years under the OICP or such similar plan (excluding the pro rata annual
 bonus referred to in the next sentence). If one hundred eighty (180) days or 
 more have elapsed in the Company's fiscal year in which such termination 
 occurs, the Company shall also pay the Executive in a lump sum, within 
 ninety (90) days after the end of such fiscal year, a pro rata portion
 of Executive's annual bonus in an amount equal to (A) the bonus which would 
 have been payable to Executive under OICP or any similar plan for the fiscal
 year in which Executive's termination occurs, multiplied by (B) a fraction, the
 numerator of which is the number of days in the fiscal year in which the 
 termination occurs through the termination date and the denominator of which is
 three hundred sixty-five (365).  For purposes of the first sentence of this 
 paragraph 4f, there shall be taken into account as bonus paid to the Executive
 for each of the years 1996 and 1997 under the OICP one-half of the sum of (x)
 cash payments with respect to Restricted Stock Units (and related Dividend 
 Equivalents) granted to the Executive under the Corporation's 1995 Stock 
 Incentive Plan and (y) the result of multiplying the number of Stock 
 Appreciation Rights granted to the Executive under the Corporation's 1995 
 Stock Incentive Plan by the difference between (1) the value of one share of 
 the Corporation's common stock on December 31, 1997 and (2) the Base
 Value ($10.75). 
 In addition, in the event that the Executive=s employment is terminated by
 the Company without cause prior to a Change in Control, the Executive (and his
 eligible dependents) shall be entitled to continue participation in the 
 Company's employee benefit plans for a two-year period from the date of 
 termination, provided, however, that if Executive cannot continue to 
 participate in any of the benefit plans, the Company shall otherwise provide 
 equivalent benefits to the Executive and his dependents on the same after-tax 
 basis as if continued participated had been permitted.  Notwithstanding the 
 foregoing, in the event Executive becomes employed by another employer and 
 becomes eligible to participate in an employee benefit plan of such employer, 
 the benefits described herein shall be secondary to such benefits during the
 period of Executive's eligibility, but only to the extent that the
 Company reimburses Executive for any increased cost and provides any additional
 benefits necessary to give Executive the benefits provided hereunder.
   Furthermore, in the event that the Executive's employment is terminated by 
 the Company without Cause prior to a Change in Control, the Executive shall be
 entitled to (i) be covered by a life insurance policy providing a death 
 benefit, equal to 2.5 times the Executive's base salary at the rate in effect 
 as of the time of termination, payable to a beneficiary or beneficiaries 
 designated by the Executive, the premiums for which will be paid by the Company
 for the balance of the Executive's life and (ii) payment by the Company of all
 fees and expenses of any executive recruiting, counseling or placement firm 
 selected by the Executive for the purposes of seeking new employment 
 following his termination of employment.
 g.   In the event that the Executive's employment is terminated following
 following a Change in Control, either by the Company without Cause or by the
 Executive for Good Reason, the Company shall pay the Executive a lump sum 
 severance benefit, equal to four years' base salary at the rate in effect as of
 the date of termination.
     In addition, in the event that the Executive's employment is terminated
 by the Company without Cause or by the Executive for Good Reason following a 
 Change in Control, the (i) Executive (and his eligible dependents) shall be
 entitled to continue participation (the premiums for which will be paid by the
 Company) in the Company's employee benefit plans providing medical, 
 prescription drug, dental, and hospitalization benefits for the remainder of
 the Executive's life (ii) the Executive shall be entitled to continue 
 participation (the premiums for which will be paid by the Company) in the 
 Company's other employee benefit plans for a four year period from the date of 
 termination; provided, however, that if Executive cannot continue to 
 participate in any of the benefit plans, the Company shall otherwise provide 
 equivalent benefits to the Executive and his dependents on the same 
 after-tax basis as if continued participation had been permitted. 
     Notwithstanding the foregoing, in the event Executive becomes employed by 
 another employer and becomes eligible to participate in an employee benefit 
 plan of such employer, the benefits described herein shall be secondary to such
 benefits during the period of Executive's eligibility, but only to the extent 
 that the Company reimburses Executive for any increased cost and provides any 
 additional benefits necessary to give Executive the benefits provided 
 hereunder.
     Furthermore, in the event that the Executive's employment is terminated
 following a Change in Control, either by the Company without Cause or by the
 Executive for Good Reason, the Executive shall be entitled to (i) be covered by
 a life insurance policy providing a death benefit, equal to 2.5 times the 
 Executive's base salary at the rate in effect as of the time of termination, 
 payable to a beneficiary or beneficiaries designated by the Executive, the 
 premiums for which will be paid by the Company for the balance of the 
 Executive's life and (ii) payment by the Company of all fees and expenses of
 any executive recruiting, counseling or placement firm selected by the 
 Executive for the purposes of seeking new employment following his 
 termination of employment.
  h.   Upon termination pursuant to paragraphs 4a, b, c, d, or e above, the 
 Company shall pay the Executive or the Executive's estate any base salary
 earned and unpaid to the date of termination.
  i.   Anything in this Agreement to the contrary notwithstanding, in the
 event it shall be determined that any payment, award, benefit or distribution
 (or any acceleration of any payment, award, benefit or distribution) by the 
 Company or any entity which effectuates a Change in Control (or any of its 
 affiliated entities) to or for the benefit of the Executive (whether pursuant 
 to the terms of this Agreement or otherwise, but determined without regard to 
 any additional payments required under this paragraph 4i)(the "Payments") 
 would be subject to the excise tax imposed by Section 4999 of the Internal 
 Revenue Code of 1986, as amended (the "Code"), or any interest or penalties are
 incurred by the Executive with respect to such excise tax (such excise tax, 
 together with any such interest and penalties, are hereinafter collectively 
 referred to as the "Excise Tax"), then the Company shall pay to the 
 Executive (or to the Internal Revenue Service on behalf of the Executive) an
 additional payment (a "Gross-Up Payment") in an amount such that
 after payment by the Executive of all taxes (including any Excise Tax) 
 imposed upon the Gross-Up Payment, the Executive retains (or has had paid to 
 the Internal Revenue Service on his behalf) an amount of the Gross-Up Payment 
 equal to the sum of (x) the Excise Tax imposed upon the Payments and (y) the
 product of any deductions disallowed because of the inclusion of the Gross-Up
 Payment in the Executive's adjusted gross income and the highest applicable 
 marginal rate of federal income taxation for the calendar year in which the 
 Gross-up Payment is to be made.  For purposes of determining the amount of the
 Gross-up Payment, the Executive shall be deemed (i) pay federal income taxes at
 the highest marginal rates of federal income taxation for the calendar year in
 which the Gross-up Payment is to be made, (ii) pay applicable state and local
 income taxes at the highest marginal rate of taxation for the calendar year
 in which the Gross-up Payment is to be made, net of the maximum reduction
 federal income taxes which could be obtained from deduction of such
 state and local taxes and (iii) have otherwise allowable deductions for federal
 income tax purposes at least equal to the Gross-up Payment.
 j.   All determinations required to be made under such paragraph 4i,
 including whether and when a Gross-up Payment is required, the amount of such
 Gross-up Payment and the assumptions to be utilized in arriving at such
 determinations, shall be made by the public accounting firm that is retained by
 the Company as of the date immediately prior to the Change in Control (the 
 "Accounting Firm") which shall provide detailed supporting calculations both to
 the Company and the Executive within fifteen (15) business days of the receipt
 of notice from the Company or the Executive that there has been a Payment, or 
 such earlier time as is requested by the Company (collectively, the
 "Determination").  In the event that the Accounting Firm is serving as 
 accountant or auditor for the individual, entity or group effecting the Change
 in Control, the Executive may appoint another nationally recognized public 
 accounting firm to make the determinations required hereunder
 (which accounting firm shall then be referred to as the Accounting Firm 
 hereunder). All fees and expenses of the Accounting Firm shall be borne solely
 by the Company and the Company shall enter into any agreement requested by the
 Accounting Firm in connection with the performance of the services
 hereunder.  The Gross-up Payment under subparagraph 4i with respect to any
 Payments shall be made no later than thirty (30) days following such Payment. 
 If the Accounting Firm determines that no Excise Tax is payable by the
 Executive, it shall furnish the Executive with a written opinion to such 
 effect, and to the effect that failure to report the Excise
 Tax, if any, on the Executive's applicable federal income tax return will not
 result in the imposition of a negligence or similar penalty.  The 
 Determination by the Accounting Firm shall be binding upon the Company and the
 Executive.
     As a result of the uncertainty in the application of Section 4999 of the
 Code at the time of the Determination, it is possible that Gross-up Payment 
 which will not have been made by the Company should have been made
 ("Underpayment") or Gross-up Payments are made by the Company which should not
 have been made ("Overpayment"), consistent with the calculations required to be
 made hereunder.  In the event that the Executive thereafter is required to make
 payment of any Excise Tax or additional Excise Tax, the Accounting Firm shall 
 determine the amount of the Underpayment that has occurred and any such 
 Underpayment (together with interest at the rate provided in Section 1274(b) 
 (2) (B) of the Code) shall be promptly paid by the Company to or for the 
 benefit of the Executive.  In the event the amount of Gross-up Payment exceeds
 the amount necessary to reimburse the Executive for his Excise Tax, the 
 Accounting Firm shall determine the amount of the Overpayment that
 has been made and any such Overpayment (together with interest at the rate 
 provided in Section 1274(b) (2) of the Code) shall be promptly paid by 
 Executive (to the extent he has received a refund if the applicable Excise Tax
 has been paid to the Internal Revenue Service) to or for the benefit of the 
 Company.  The Executive shall cooperate, to the extent his expenses are 
 reimbursed by the Company, with any reasonable requests by the Company in 
 connection with any contests or disputes with the Internal Revenue Service 
 in connection with the Excise Tax.
 k.   Upon the occurrence of a Change in Control the Company shall
 pay promptly as incurred, to the full extent permitted by law, all legal fees
 and expenses which the Executive may reasonably thereafter incur as a result of
 any contest, litigation or arbitration (regardless of the outcome thereof) by
 the Company, or by the Executive of the validity of, or liability under, this
 Agreement or the SERP (including any contest by the Executive about the amount
 of any payment pursuant to this Agreement or pursuant to the SERP), plus in 
 each case interest on any delayed payment at the rate of 150% of the Prime 
 Rate posted by the Chase Manhattan Bank, N.A. or its successor, provided, 
 however, that the Company shall not be liable for the Executive's legal fees
 and expenses if the Executive's position in such contest, litigation or 
 arbitration is found by the neutral decision-maker to be frivolous.
 l.   Notwithstanding anything contained in this Section 4 to the contrary,
 upon termination of the Executive=s employment after completion of ten
 (10) years of continuous service with the Company (as determined pursuant to 
 the SERP), the Executive and his eligible dependents shall be entitled to 
 receive medical, prescription drug, dental and hospitalization benefits for the
 remainder of the Executive's life, the cost of which shall be paid in full by 
 the Company (if applicable, on the same after-tax basis to the executive as if
 the Executive had continued participation in the Company's employee benefit 
 plans providing such benefits).  If the Executive is less than age 55 at the 
 date of such termination of employment, the Executive shall be entitled to 
 receive such benefits upon attaining age 55 and prior thereto the Executive, if
 applicable, shall be entitled to the medical, prescription drug, dental and 
 hospitalization benefits provided by paragraphs 4f or g above.
          
  5.   Successor Liability.  The Company shall require any successor (whether
 direct or indirect, by purchase, merger, consolidation or otherwise) to all
 or substantially all of the business and/or assets of the Company to assume
 expressly and to agree to perform this Agreement in the same manner and to the
 same extent that the Company would be required to perform.  As used in this 
 Agreement, "Company" shall mean the company as hereinbefore defined and any 
 successor to its business and/or assets as aforesaid which assumes and agrees 
 to perform this Agreement by operation of law, or otherwise.
          
 6.   Confidential Information.  The Executive agrees to keep secret and
 retain in the strictest confidence all confidential matters which relate to the
 Company, its subsidiaries and affiliates, including, without limitation, 
 customer lists, client lists, trade secrets, pricing policies and other
 business affairs of the Company, its subsidiaries and affiliates learned by him
 from the Company or any such subsidiary or affiliate or otherwise before or 
 after the date of this Agreement, and not to disclose any such confidential 
 matter to anyone outside the Company or any of its subsidiaries or affiliates, 
 whether during or after his period of service with the Company, except (i) as
 such disclosure may be required or appropriate in connection with his work as
 an employee of the Company or (ii) when required to do so by a court of law, by
 any governmental agency having supervisory authority over the business of the 
 Company or by any administrative or legislative body (including a committee 
 thereof) with apparent jurisdiction to order him to divulge, disclose or make
 accessible such information.  The Executive agrees to give the
 Company advance written notice of any disclosure pursuant to clause (ii) of the
 preceding sentence and to cooperate with any efforts by the Company to limit 
 the extent of such disclosure.  Upon request by the Company, the Executive
 agrees to deliver promptly to the Company upon termination of his services for 
 the Company, or at any time thereafter as the Company may request, all Company 
 subsidiary or affiliate memoranda, notes, records, reports, manuals, drawings, 
 designs, computer file in any media and other documents (and all copies 
 thereof) relating to the Company's or any subsidiary's or affiliate's business
 and all property of the Company or any subsidiary or affiliate associated 
 therewith, which he may then possess or have under his direct control, other 
 than personal notes, diaries, Rolodexes and correspondence.
          
  7.   Non-Compete and Non-Solicitation.  During the Executive's employment 
 by the Company and for a period of one year following the termination 
 thereof for any reason (other than following a Change in Control), the 
 Executive covenants and agrees that he will not for himself or on
 behalf of any other person, partnership, company or corporation, directly or
 indirectly, acquire any financial or beneficial interest in (except as provided
 in the next sentence), provide consulting services to, be employed by, or own, 
 manage, operate or control any business which is in competition with a business
 engaged in by the Company or any of its subsidiaries or affiliates in any state
 of the United States in which any of them are engaged in business at the time
 of such termination of employment for as long as they carry on a business 
 therein.  Notwithstanding the preceding sentence, the Executive shall not be 
 prohibited from owning less than five (5%) percent of any publicly traded 
 corporation, whether or not such corporation is in competition with the 
 Company.
      The Executive hereby covenants and agrees that, at all times during the
 period of his employment and for a period of one year immediately following the
 termination thereof for any reason (other than following a Change in Control), 
 the Executive shall not employ or seek to employ any person employed at that
 time by the Company or any of its subsidiaries, or otherwise encourage or 
 entice such person or entity to leave such employment.
      It is the intention of the parties hereto that the restrictions
 contained in this Section be enforceable to the fullest extent permitted by
 applicable law.  Therefore, to the extent any court of competent jurisdiction 
 shall determine that any portion of the foregoing restrictions is excessive, 
 such provision shall not be entirely void, but rather shall be limited or 
 revised only to the extent necessary to make it enforceable.  Specifically, if 
 any court of competent jurisdiction should hold that any portion of the 
 foregoing description is overly broad as to one or more states of the United 
 States, then that state or states shall be eliminated from the territory to 
 which the restrictions of paragraph (a) of this Section applies and the 
 restrictions shall remain applicable in all other states of the United States.
          
 8.   No Mitigation.  The Executive shall not be required to mitigate
 the amount of any payments or benefits provided for in paragraph 4f or 4g 
 hereof by seeking other employment or otherwise and no amounts earned by the 
 Executive shall be used to reduce or offset the amounts payable hereunder, 
 except as otherwise provided in paragraph 4f or 4g.
          
 9.   Ownership of Work Product.  Any and all improvements, inventions,
 discoveries, formulae, processes, methods, know-how, confidential data, trade
 secrets and other proprietary information (collectively, "Work Products")
 within the scope of any business of the Company or any Affiliate which the 
 Executive may conceive or make or have conceived or made during the Executive's
 employment with the Company shall be and are the sole and exclusive property of
 the Company, and that the Executive, whenever requested to do so by the 
 Company, at its expense, shall execute and sign any and all applications, 
 assignments or other instruments and do all other things which the Company may
 deem necessary or appropriate (i) to apply for, obtain, maintain, enforce, or 
 defend letters patent of the United States or any foreign country for any Work
 Product, or (ii) to assign, transfer, convey or otherwise make available to the
 Company the sole and exclusive right, title and interest in and to any Work 
 Product.
          
 10.   Arbitration.  Any dispute or controversy between the parties
 relating to this Agreement (except any dispute relating to Sections 6 or 7 
 hereof) or relating to or arising out of the Executive's employment with the
 Company, shall be settled by binding arbitration in the City of Syracuse, State
 of New York, pursuant to the Employment Dispute Resolution Rules of the 
 American Arbitration Association and shall be subject to the provisions of 
 Article 75 of the New York Civil Practice Law and Rules.  Judgment upon the 
 award may be entered in any court of competent jurisdiction.  Notwithstanding 
 anything herein to the contrary, if any dispute arises between the parties 
 under Sections 6 or 7 hereof, or if the Company makes any claim under Sections 
 6 or 7, the Company shall not be required to arbitrate such dispute or claim 
 but shall have the right to institute judicial proceedings in any court of 
 competent jurisdiction with respect to such dispute or claim.  If such 
 judicial proceedings are instituted, the parties agree that such
 proceedings shall not be stayed or delayed pending the outcome of any 
 arbitration proceedings hereunder.
          
 11.  Notices.  Any notice or other communication required or permitted
 under this Agreement shall be effective only if it is in writing and delivered
 personally or sent by certified mail, postage prepaid, or overnight delivery
 addressed as follows:
                   
                   
                   
                   
                   
If to the Company:
          
Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse, New York  13202
          
ATTN: Corporate Secretary
          
          
          
If to the Executive:
          
4953 Bryn Mawr Drive
Syracuse, NY   13215
          
          
          
or to such other address as either party may designate by notice to the other,
and shall be deemed to have been given upon receipt.
          
12.   Entire Agreement.  This Agreement constitutes the entire agreement
between the parties hereto, and supersedes, and is in full substitution
for any and all prior understandings or agreements, oral or written, with 
respect to the Executive's employment.
          
13.   Amendment.  This Agreement may be amended only by an instrument in
writing signed by the parties hereto, and any provision hereof may be waived 
only by an instrument in writing signed by the party or parties against whom or
which enforcement of such waiver is sought.  The failure of either party hereto
at any time to require the performance by the other party hereto of any 
provision hereof shall in no way affect the full right to require
such performance at any time thereafter, nor shall the waiver by either party
hereto of a breach of any provision hereof be taken or held to be a waiver of
any succeeding breach of such provision or a waiver of the provision itself 
or a waiver of any other provision of this Agreement.
          
14.   Obligation to Provide Benefits.  The company may utilize certain
financing vehicles, including a trust, to provide a source of funding for the
Company's obligations under this Agreement.  Any such financing vehicles will be
subject to the claims of the general creditors of the Company.  No such 
financing vehicles shall relieve the Company, or its successors, of its 
obligation to provide benefits under this Agreement, except to the extent the 
Executive receives payments directly from such financing vehicle.
          
15.   Miscellaneous.  This Agreement is binding on and is for the benefit
of the parties hereto and their respective successors, heirs, executors,
administrators and other legal representatives.  Neither this Agreement nor any
right or obligation hereunder may be assigned by the Company (except to an
Affiliate) or by the Executive without the prior written consent of the other 
party.  This Agreement shall be binding upon any successor to the Company, 
whether by merger, consolidation, reorganization, purchase of all or 
substantially all of the stock or assets of the Company, or by operation of law.
          
16.   Severability.  If any provision of this Agreement, or portion
thereof, is so broad, in scope or duration, so as to be unenforceable, such
provision or portion thereof shall be interpreted to be only so broad as is
enforceable.
          
17.   Governing Law.  This Agreement shall be governed by and construed
in accordance with the laws of the State of New York without reference to 
principles of conflicts of law.
          
18.   Counterparts.  This Agreement may be executed in several
counterparts, each of which shall be deemed an original, but all of which shall
constitute one and the same instrument.
          
19.   Performance Covenant.  The Executive represents and warrants to
the Company that the Executive is not party to any agreement which would 
prohibit the Executive from entering into this Agreement or performing fully the
Executive's obligations hereunder.
          
20.   Survival of Covenants.  The obligations of the Executive set
forth in Sections 6, 7, 9 and 10 represent independent covenants by which the
Executive is and will remain bound notwithstanding any breach by the Company, 
and shall survive the termination of this Agreement.
          
          
          
          
IN WITNESS WHEREOF, the Company and the Executive have executed this
Agreement as of the date first written above.
          
          
 _____________________________             NIAGARA MOHAWK POWER CORPORATION
        Thomas H. Baron
          
          
                                            By:______________________________
                                                    DAVID J. ARRINGTON
                                                    Senior Vice President -
                                                    Human Resources
          

          <PAGE>
    


                  SCHEDULE A
          
        Modifications in Respect of Thomas H. Baron ("Executive")
                                    to the
              Supplemental Executive Retirement Plan ("SERP")
                                   of the
                     Niagara Mohawk Power Corporation ("Company")        
                                                              
          
I.   Subsection 1.8 of Section I of the SERP is hereby modified to provide that 
the term "Earnings" shall mean the sum of the (i) Executive's base annual 
salary, whether or not deferred and including any elective before-tax 
contributions made by the Executive to a plan qualified under Section 401(k) of 
the Internal Revenue Code, averaged over the final 36 months of the Executive's 
employment with the Company and (ii) the average of the annual bonus earned
by the Executive under the Corporation's Annual Officers Incentive Compensation
Plan ("OICP"), whether or not deferred, in respect of the final 36 months of the
Executive's employment with the Company.  If the Executive is an employee of
the Company on December 31, 1997, there shall be taken into account for
purposes of the preceding sentence as an annual bonus under the OICP, the sum
of (x) cash payments made with respect to Stock Units (and related Dividend
Equivalents) granted to the Executive under the SIP and (y) the result of
multiplying the number of Stock Appreciation Rights granted to the Executive
under the SIP, prorated if applicable to Article 9 of the SIP, by the
difference between (1) the value of one share of the Corporation's common
stock on December 31, 1997 and (2) the Base Value ($10.75). 
         
II.  Subsection 2.1 of Section II of the SERP is hereby modified to provide that
full SERP benefits are vested following ten (10) years of continuous service
with the Company  (i.e., 60% of Earnings (as modified above) without reduction
for an Early Commencement Factor) regardless of the Executive's years of
continuous service with the Company.  If the Executive is less than age 55 at
the date of such termination of employment, the Executive shall be entitled to
receive benefits commencing no earlier than age 55, calculated pursuant to
Section III of the SERP without reduction for an Early Commencement Factor.
          
III. Subsection 4.3 of Section IV of the SERP is hereby modified to provide that
in the event of (x) the Executive's involuntary termination of employment by the
Company, at any time, other than for Cause, (y) the termination of this
Agreement on account of the Executive's Disability or (z) the Executive's
termination of employment for Good Reason within the 36 full calendar month
period following a Change in Control (as defined in Schedule B of this
Agreement), the Executive shall be 100% vested in his full SERP benefit (i.e.,
60% of Earnings (as modified above) without reduction for an Early
Commencement Factor) regardless of the Executive's years of continuous service
with the Company.  If the Executive is less than age 55 at the date of such
termination of employment, the Executive shall be entitled to receive benefits
commencing no earlier than age 55, calculated pursuant to Section III of the
SERP without reduction for an Early Commencement Factor.
          
IV.  Except as provided above, the provisions of the SERP shall apply and 
control participation therein and the payment of benefits thereunder.
                    <PAGE>
          
          
          
                         SCHEDULE B
          
          
For purposes of this Agreement, the term "Change in Control" shall mean:
          
(1)  The acquisition by any individual, entity or group
(within the meaning of Sections 13(d)(3) or 14(d)(2) of the Securities
Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of
beneficial ownership (within the meaning of Rule 13d-3 promulgated under
the Exchange Act) of 20% or more of either (i) the then outstanding
shares of common stock of the Company (the "Outstanding Company Common
Stock") or (ii) the combined voting power of the then outstanding voting
securities of the Company entitled to vote generally in the election of
directors (the "Outstanding Company Voting Securities"); provided,
however, that the following acquisitions shall not constitute a Change
of Control:  (i) any acquisition directly from the Company (excluding an
acquisition by virtue of the exercise of a conversion privilege), (ii)
any acquisition by the Company, (iii) any acquisition by any employee
benefit plan (or related trust) sponsored or maintained by the Company
or any corporation controlled by the Company or (iv) any acquisition by
any corporation pursuant to a reorganization, merger or consolidation,
if, following such reorganization, merger or consolidation, the
conditions described in clauses (i), (ii) and (iii) of subparagraph (3)
of this Schedule B are satisfied; or
         
(2)  Individuals who, as of the date hereof, constitute the
Company's Board of Directors (the "Incumbent Board") cease for any
reason to constitute at least a majority of the Board; provided,
however, that any individual becoming a director subsequent to the date
hereof whose election, or nomination for election by the Company's
shareholders, was approved by a vote of at least a majority of the
directors then comprising the Incumbent Board shall be considered as
though such individual were a member of the Incumbent Board, but
excluding, for this purpose, any such individual whose initial
assumption of office occurs as a result of either an actual or
threatened election contest (as such terms are used in Rule 14a-11 of
Regulation 14A promulgated under the Exchange Act) or other actual or
threatened solicitation of proxies or consents by or on behalf of a
Person other than the Board; or
          
(3)  Approval by the shareholders of the Company of a reorganization, merger
or consolidation, in each case, unless, following such reorganization, merger
or consolidation, (i) more than 75% of, respectively, the then outstanding 
shares of common stock of the corporation resulting from such reorganization, 
merger or consolidation and the combined voting power of the then outstanding 
voting securities of such corporation entitled to vote generally in the election
of directors is then beneficially owned, directly or indirectly, by all or
substantially all of the individuals and entities who were the beneficial 
owners, respectively, of the Outstanding Company Common Stock and Outstanding 
Company Voting Securities immediately prior to such reorganization, merger or 
consolidation in substantially the same proportions as their ownership, 
immediately prior to such reorganization, merger or consolidation, of the
Outstanding Company Common Stock and Outstanding Company Voting Securities, as 
the case may be, (ii) no Person (excluding the Company, any employee benefit 
plan (or related trust) of the Company or such corporation resulting from such 
reorganization, merger or consolidation and any Person beneficially owning, 
immediately prior to such reorganization, merger or consolidation, directly 
or indirectly, 20% or more of the Outstanding Company Common
stock or Outstanding Voting Securities, as the case may be) beneficially owns,
directly or indirectly, 20% or more of, respectively, the then outstanding 
shares of common stock of the corporation resulting from such reorganization, 
merger or consolidation or the combined voting power of the then outstanding 
voting securities of such corporation entitled to vote generally in the election
of directors and (iii) at least a majority of the members of the board of 
directors of the corporation resulting from such reorganization, merger or
consolidation were members of the Incumbent Board at the time of the execution 
of the initial agreement providing for such reorganization, merger or 
consolidation; or

(4)  Approval by the shareholders of the Company of (i) a complete
liquidation or dissolution of the Company or (ii) the sale or other disposition
of all or substantially all of the assets of the Company, other than to a 
corporation, with respect to which following such sale or other disposition, (A)
more than 75% of, respectively, the then outstanding shares of common stock of 
such corporation and the combined voting power of the then outstanding voting 
securities of such corporation entitled to vote generally in the election of 
directors is then beneficially owned, directly or indirectly, by all or 
substantially all of the individuals and entities who were the beneficial 
owners, respectively, of the Outstanding Company Common Stock and Outstanding 
Company Voting Securities immediately prior to such sale or other disposition in
substantially the same proportion as their ownership, immediately prior to such
sale or other disposition, of the Outstanding Company Common Stock and 
Outstanding Company Voting Securities, as the case may be, (B) no Person 
(excluding the Company and any employee benefit plan (or related trust) of the
Company or such corporation and any Person beneficially owning, immediately
prior to such sale or other disposition, directly or indirectly, 20% or more
of the Outstanding Company Common Stock or Outstanding Company Voting 
Securities, as the case may be) beneficially owns, directly or indirectly, 
20% or more of, respectively, the then outstanding shares of common
stock of such corporation and the combined voting power of the then outstanding
voting securities of such corporation entitled to vote generally in the election
of directors and (C) at least a majority of the members of the board of 
directors of such corporation were members of the Incumbent Board at the time of
the execution of the initial agreement or action of the Board providing for such
sale or other disposition of assets of the Company.
          


<PAGE>



EXHIBIT (A) 10-40





	EMPLOYMENT AGREEMENT




Agreement made as of the 22nd day of October, 1998, between NIAGARA MOHAWK 
POWER CORPORATION (the "Company"), and Edward J. Dienst (the "Executive").

WHEREAS, the Company desires to employ the Executive, and the Executive desires
to accept/continue employment with the Company, on the terms and conditions 
hereinafter set forth.

NOW, THEREFORE, in consideration of the mutual covenants and agreements 
hereinafter set forth, the Company and the Executive hereby agree as follows:

1.	Term of Agreement.  The Company shall employ the Executive, and the 
Executive shall serve the Company, for the period beginning October 22, 1998
and expiring on December 31, 200l, subject to earlier termination as provided
under paragraph 4 hereof. This Agreement shall be extended automatically
by one year commencing on January 1, 2000 and on January 1st of
each year thereafter, unless either party notifies the other to the 
contrary not later than sixty (60) days prior to such date. Notwithstanding any
such notice by the Company, this Agreement shall remain in effect for a period
of thirty-six months from the date of a "Change in Control" (as that term is
defined in Schedule B hereto, unless such notice was given at least 18 months 
prior to the date of the Change in Control). 


2.	Duties.  The Executive shall serve the Company as its Senior Vice President 
- Customer Delivery & Asset Management. During the term of this Agreement, the
Executive shall, except during vacation or sick leave, devote the whole of the
Executive's time, attention and skill to the business of the Company during
usual business hours (and outside those hours when reasonably necessary to the
Executive's duties hereunder); faithfully and diligently perform such duties and
exercise such powers as may be from time to time assigned to or vested in the 
Executive by the Company's Board of Directors (the "Board") or by any officer
of the Company superior to the Executive; obey the directions of the
Board and of any officer of the Company superior to the Executive; and use the 
Executive's best efforts to promote the interests of the Company.  The Executive
may be required in pursuance of the Executive's duties hereunder to perform 
services for any company controlling, controlled by or under common control with
the Company (such companies hereinafter collectively called "Affiliates") and to
accept such offices in any Affiliates as the Board may require.  The Executive 
shall obey all policies of the Company and applicable policies of its 
Affiliates.

3.	Compensation.  During the term of this Agreement:
a.	The Company shall pay the Executive a base salary at an annual rate of 
$215,000, which shall be payable periodically in accordance with the Company's
then prevailing payroll practices, or such greater amount as the Company may 
from time to time determine;

b.	The Executive shall be entitled to participate in the Company's 
Supplemental Executive Retirement Plan ("SERP") according to its terms, as 
modified by Schedule A hereto;

c.	The Executive shall be entitled to participate in the Company's Officers
Incentive Compensation Plan, 1995 Stock Incentive Plan, and Long Term Incentive 
Plan, and any successors thereto, in accordance with the terms thereof; and  

d.	The Executive shall be entitled to such expense accounts, vacation 
time, sick leave, perquisites of office, fringe benefits, insurance coverage, 
and other terms and conditions of employment as the Company generally provides
to its employees having rank and seniority at the Company comparable to the 
Executive.

4.	Termination.  The Company shall continue to employ the Executive, and the 
Executive shall continue to work for the Company, during the term of this
Agreement, unless the Agreement is terminated in accordance with the following 
provisions:
a.	This Agreement shall terminate automatically upon the death of the 
Executive.  Any right or benefit accrued on behalf of the Executive or to which
the Executive became entitled under the terms of this Agreement prior to death 
(other than payment of base salary in respect of the period following the 
Executive's death), and any obligation of the Company to the Executive in 
respect of any such right or benefit, shall not be extinguished by reason of
the Executive's death.  Any base salary earned and unpaid as of the
date of the Executive's death shall be paid to the Executive's estate in 
accordance with paragraph 4g below. 

b.   By notice to the Executive, the Company may terminate this Agreement 
upon the "Disability" of the Executive. The Executive shall be deemed to incur
a Disability when (i) a physician selected by the Company advises the Company
that the Executive's physical or mental condition has rendered the Executive 
unable to perform the essential functions of the Executive's position in a
reasonable manner, with or without reasonable accommodation and will continue 
to render him unable to perform the essential functions of the
Executive's position in such manner, for a period exceeding 12 consecutive
months, or (ii) due to a physical or mental condition, the Executive has not  
performed the essential functions of the Executive's position in a reasonable 
manner, with or without reasonable accommodation, for a period of 12 consecutive
months. Following termination of this Agreement pursuant to clause (i) of the
preceding sentence of this paragraph, the Executive shall continue to receive 
his base salary under paragraph 3a hereof for a period of 12 months from the 
date of his Disability, reduced by any benefits payable during such period under
the Company's short-term disability plan and long-term disability plan.
Thereafter, or in the event of termination of this Agreement pursuant to 
clause (ii) of the preceding sentence, the Executive shall receive benefits 
under the Company's long-term disability plan in lieu of any further base salary
under paragraph 3a hereof.   

c.	By notice to the Executive, the Company may terminate the Executive's 
employment at any time for "Cause".  The Company must deliver such notice within
ninety (90) days after the Board both (i) has or should have had knowledge of 
conduct or an event allegedly constituting Cause, and (ii) has reason to 
believe that such conduct or event could be grounds for Cause.  For purposes
of this Agreement "Cause" shall mean  (i) the Executive is convicted
of, or has plead guilty or nolo contendere to, a felony; (ii) the willful
and continued failure by the Executive to perform substantially his duties with 
the Company (other than any such failure resulting from incapacity due to 
physical or mental illness) after a demand for substantial performance is
delivered to the Executive by the Company which specifically identifies the 
manner in which the Company believes the Executive has not substantially 
performed his duties; (iii) the Executive engages in conduct that constitutes 
gross neglect or willful misconduct in carrying out his duties under
this Agreement involving material economic harm to the Company or any of its 
subsidiaries; or (iv) the Executive has engaged in a material breach of 
Sections 6 or 7 of this Agreement.  In the event the termination notice is based
on clause (ii) of the preceding sentence, the Executive shall have ten (10) 
business days following receipt of the notice of termination to cure his 
conduct, to the extent such cure is possible, and if the Executive does not 
cure within the ten (10) business day period, his termination of employment 
in accordance with such termination notice shall be deemed to be for Cause.  
The determination of Cause shall be made by the Board upon the recommendation 
of the Compensation and Succession Committee of the Board.  Following a Change
in Control, such determination shall be made in a resolution duly adopted by 
the affirmative vote of not less than three-fourths (3/4) of the membership of
the Board, excluding members who are employees of the Company, at a meeting 
called for the purpose of determining that Executive has engaged in conduct 
which constitutes Cause (and at which Executive had a reasonable opportunity, 
together with his counsel, to be heard before the Board prior to such vote).
The Executive shall not be entitled to the payment of any additional 
compensation from the Company, except to the extent provided in paragraph 4h
hereof, in the event of the termination of his employment for Cause.
d.	If any of the following events, any of which shall constitute "Good 
Reason", occurs within thirty-six months after a Change in Control, the 
Executive, by notice of the Company, may voluntarily terminate the 
Executive's employment for Good Reason within ninety (90) days after the 
Executive both (i) has or should have had knowledge of conduct or an event 
allegedly constituting Good Reason, and (ii) has reason to believe that such
conduct or event could be grounds for Good Reason.  In such event, the
Executive shall be entitled to the severance benefits set forth in paragraph 4g
below.
(i) the Company assigns any duties to the Executive which are materially 
inconsistent in any adverse respect with the Executive's position, duties, 
offices, responsibilities or reporting requirements immediately prior to a 
Change in Control, including any diminution of such duties or 
responsibilities; or
(ii)  the Company reduces the Executive's base salary, including salary 
deferrals, as in effect immediately prior to a Change in Control; or

(iii)  the Company discontinues any bonus or other compensation plan or any 
other benefit, retirement plan (including the SERP), stock ownership plan, 
stock purchase plan, stock option plan, life insurance plan, health plan, 
disability plan or similar plan (as the same existed immediately prior to the 
Change in Control) in which the Executive participated or was eligible
to participate in immediately prior to the Change in Control and in 
lieu thereof does not make available plans providing at least comparable 
benefits; or

(iv)  the Company takes action which adversely affects the Executive's 
participation in, or eligibility for, or materially reduces the Executive's
benefits under, any of the plans described in (iii) above, or deprives the 
Executive of any material fringe benefit enjoyed by the Executive immediately
prior to the Change in Control, or fails to provide the Executive with the 
number of paid vacation days to which the Executive was entitled immediately
prior to the Change in Control; or 

(v)  the Company requires the Executive to be based at any office or location 
other than one within a 50-mile radius of the office or location at which the
Executive was based immediately prior to the Change in Control; or

(vi)  the Company purports to terminate the Executive's employment otherwise 
than as expressly permitted by this Agreement; or

(vii)  the Company fails to comply with and satisfy Section 5 hereof, provided 
that such successor has received prior written notice from the Company or from
the Executive of the requirements of Section 5 hereof.
     The Executive shall have the sole right to determine, in good faith, 
whether any of the above events has occurred.

e.	The Company may terminate the Executive's employment at any time 
without Cause. 

f.	In the event that the Executive's employment is terminated by the Company
without Cause prior to a Change in Control, the Company shall pay the Executive
a lump sum severance benefit, equal to two years' base salary at the rate in 
effect as of the date of termination, plus the greater of (i) two times the most
recent annual bonus paid to the Executive under the Corporation's Annual 
Officers Incentive Compensation Plan (the "OICP") or any similar annual 
bonus plan (excluding the pro rata bonus referred to in the next
sentence) or (ii) two times the average annual bonus paid to the Executive for 
the three prior years under the OICP or such similar plan (excluding the pro 
rata annual bonus referred to in the next sentence).  If one hundred eighty 
(180) days or more have elapsed in the Company's fiscal year in which such 
termination occurs, the Company shall also pay the Executive in a lump sum, 
within ninety (90) days after the end of such fiscal year, a pro rata portion 
of Executive's annual bonus in an amount equal to (A) the bonus 
which would have been payable to Executive under OICP or any similar plan for 
the fiscal year in which Executive's termination occurs, multiplied by (B) a
fraction, the numerator of which is the number of days in the fiscal year in 
which the termination occurs through the termination date and the denominator 
of which is three hundred sixty-five (365).  For purposes of the first sentence
of this paragraph 4f, there shall be taken into account as bonus paid to the
Executive for each of the years 1996 and 1997 under the OICP one-half of 
the sum of (x) cash payments with respect to Restricted Stock Units (and 
related Dividend Equivalents) granted to the Executive under the Corporation's
1995 Stock Incentive Plan and (y) the result of multiplying the number of 
Stock Appreciation Rights granted to the Executive under the Corporation's
1995 Stock Incentive Plan by the difference between (1) the value of
one share of the Corporation's common stock on December 31, 1997 and (2) the 
Base Value ($10.75). 
     In addition, in the event that the Executive's employment is terminated by
the Company without cause prior to a Change in Control, the Executive (and his
eligible dependents) shall be entitled to continue participation in the 
Company's employee benefit plans for a two-year period from the date of 
termination, provided, however, that if Executive cannot continue to
participate in any of the benefit plans, the Company shall otherwise
provide equivalent benefits to the Executive and his dependents on the same
after-tax basis as if continued participated had been permitted.  
Notwithstanding the foregoing, in the event Executive becomes employed by 
another employer and becomes eligible to participate in an employee benefit 
plan of such employer, the benefits described herein shall be secondary to such
benefits during the period of Executive's eligibility, but only to the
extent that the Company reimburses Executive for any increased cost and 
provides any additional benefits necessary to give Executive the 
benefits provided hereunder.
     Furthermore, in the event that the Executive's employment is terminated by
the Company without Cause prior to a Change in Control, the Executive shall be
entitled to (i) be covered by a life insurance policy providing a death benefit,
equal to 2.5 times the Executive's base salary at the rate in effect as of the
time of termination, payable to a beneficiary or beneficiaries designated by 
the Executive, the premiums for which will be paid by the Company for the 
balance of the Executive's life and (ii) payment by the Company of all fees
and expenses of any executive recruiting, counseling or placement firm 
selected by the Executive for the purposes of seeking new employment 
following his termination of employment.

g.	In the event that the Executive's employment is terminated following a 
Change in Control, either by the Company without Cause or by the Executive 
for Good Reason, the Company shall pay the Executive a lump sum severance 
benefit, equal to four years' base salary at the rate in effect as of the 
date of termination.

In addition, in the event that the Executive's employment is terminated by the 
Company without Cause or by the Executive for Good Reason following a Change in
Control, the (i) Executive (and his eligible dependents) shall be entitled to 
continue participation (the premiums for which will be paid by the Company)
in the Company's employee benefit plans providing medical, prescription drug, 
dental, and hospitalization benefits for the remainder of the Executive's 
life (ii) the Executive shall be entitled to continue participation (the 
premiums for which will be paid by the Company) in the Company's other
employee benefit plans for a four year period from the date of 
termination; provided, however, that if Executive cannot continue to participate
in any of the benefit plans, the Company shall otherwise provide equivalent 
benefits to the Executive and his dependents on the same after-tax basis as if
continued participation had been permitted.  Notwithstanding the foregoing, 
in the event Executive becomes employed by another employer and becomes 
eligible to participate in an employee benefit plan of such employer, the 
benefits described herein shall be secondary to such benefits during the 
period of Executive's eligibility, but only to the extent that the Company 
reimburses Executive for any increased cost and provides any additional 
benefits necessary to give Executive the benefits provided hereunder.
     Furthermore, in the event that the Executive's employment is terminated
following a Change in Control, either by the Company without Cause or by the
Executive for Good Reason, the Executive shall be entitled to (i) be covered
by a life insurance policy providing a death benefit, equal to 2.5 times the
Executive's base salary at the rate in effect as of the time of termination,
payable to a beneficiary or beneficiaries designated by the Executive, the
premiums for which will be paid by the Company for the balance of the
Executive's life and (ii) payment by the Company of all fees and expenses of
any executive recruiting, counseling or placement firm selected by the Executive
for the purposes of seeking new employment following his termination of 
employment.

h.	Upon termination pursuant to paragraphs 4a, b, c, d, or e above, the 
Company shall pay the Executive or the Executive's estate any base salary earned
and unpaid to the date of termination.

i.	Anything in this Agreement to the contrary notwithstanding, in the event
it shall be determined that any payment, award, benefit or distribution (or any 
acceleration of any payment, award, benefit or distribution) by the Company or 
any entity which effectuates a Change in Control (or any of its affiliated 
entities) to or for the benefit of the Executive (whether pursuant to the terms
of this Agreement or otherwise, but determined without regard to any additional
payments required under this paragraph 4i)(the "Payments") would be subject
to the excise tax imposed by Section 4999 of the Internal Revenue Code of 
1986, as amended (the "Code"), or any interest or penalties are incurred
by the Executive with respect to such excise tax (such excise tax, together 
with any such interest and penalties, are hereinafter collectively referred 
to as the "Excise Tax"), then the Company shall pay to the Executive (or to the
Internal Revenue Service on behalf of the Executive) an additional payment (a 
"Gross-Up Payment") in an amount such that after payment by the Executive of
all taxes (including any Excise Tax) imposed upon the Gross-Up Payment, the
Executive retains (or has had paid to the Internal Revenue Service on his 
behalf) an amount of the Gross-Up Payment equal to the sum of (x) the 
Excise Tax imposed upon the Payments and (y) the product of any deductions 
disallowed because of the inclusion of the Gross-Up Payment in the
Executive's adjusted gross income and the hightest applicable marginal
rate of federal income taxation for the calendar year in which the
Gross-up Payment is to be made.  For purposes of determining the amount of the
Gross-up Payment, the Executive shall be deemed (i) pay federal income taxes at
the highest marginal rates of federal income taxation for the calendar year in
which the Gross-up Payment is to be made, (ii) pay applicable state and local
income taxes at the highest marginal rate of taxation for the calendar year
in which the Gross-up Payment is to be made, net of the maximum reduction in
federal income taxes which could be obtained from deduction of such
state and local taxes and (iii) have otherwise allowable deductions 
for federal income tax purposes at least equal to the Gross-up Payment.

j.	All determinations required to be made under such paragraph 4i, including
whether and when a Gross-up Payment is required, the amount of such Gross-up 
Payment and the assumptions to be utilized in arriving at such determinations,
shall be made by the public accounting firm that is retained by the Company as
of the date immediately prior to the Change in Control (the "Accounting 
Firm") which shall provide detailed supporting calculations both to
the Company and the Executive within fifteen (15) business days of
the receipt of notice from the Company or the Executive that there has been
a Payment, or such earlier time as is requested by the Company (collectively, 
the "Determination").  In the event that the Accounting Firm is serving as
accountant or auditor for the individual, entity or group effecting the 
Change in Control, the Executive may appoint another nationally recognized
public accounting firm to make the determinations required hereunder (which
accounting firm shall then be referred to as the Accounting Firm hereunder).
All fees and expenses of the Accounting Firm shall be borne solely by the
Company and the Company shall enter into any agreement requested by the 
Accounting Firm in connection with the performance of the services hereunder. 
The Gross-up Payment under subparagraph 4i with respect to any Payments shall 
be made no later than thirty (30) days following such Payment.  If the 
Accounting Firm determines that no Excise Tax is payable by the
Executive, it shall furnish the Executive with a written opinion to 
such effect, and to the effect that failure to report the Excise Tax, if any, 
on the Executive's applicable federal income tax return will not result in the
imposition of a negligence or similar penalty.  The Determination by the 
Accounting Firm shall be binding upon the Company and the Executive.

     As a result of the uncertainty in the application of Section 4999 of the 
Code at the time the Determination, it is possible that Gross-up
Payment which will not have been made by the Company should have
been made ("Underpayment") or Gross-up Payments are made by the Company
which should not have been made ("Overpayment"), consistent with the 
calculations required to be made hereunder.  In the event that the Executive
thereafter is required to make payment of any Excise Tax or additional Excise 
Tax, the Accounting Firm shall determine the amount of the Underpayment that
has occurred and any such Underpayment (together with interest at the rate 
provided in Section 1274(b) (2) (B) of the Code) shall be promptly
paid by the Company to or for the benefit of the Executive.  In the event the 
amount of Gross-up Payment exceeds the amount necessary to reimburse the 
Executive for his Excise Tax, the Accounting Firm shall determine the amount
of the Overpayment that has been made and any such Overpayment (together with
interest at the rate provided in Section 1274(b) (2) of the Code) shall be
promptly paid by Executive (to the extent he has received a refund if
the applicable Excise Tax has been paid to the Internal Revenue Service)
to or for the benefit of the Company.  The Executive shall cooperate, to the 
extent his expenses are reimbursed by the Company, with any reasonable 
requests by the Company in connection with any contests or disputes with the
Internal Revenue Service in connection with the Excise Tax.

k.	Upon the occurrence of a Change in Control the Company shall pay 
promptly as incurred, to the full extent permitted by law, all legal fees and
expenses which the Executive may reasonably thereafter incur as a result of
any contest, litigation or arbitration (regardless of the outcome thereof) by
the Company, or by the Executive of the validity of, or liability under,
this Agreement or the SERP (including any contest by the Executive
about the amount of any payment pursuant to this Agreement or pursuant to 
the SERP), plus in each case interest on any delayed payment at the rate of
150% of the Prime Rate posted by the Chase Manhattan Bank, N.A. or its 
successor, provided, however, that the Company shall not be liable for the 
Executive's legal fees and expenses if the Executive's position in such 
contest, litigation or arbitration is found by the neutral decision-maker
to be frivolous.

l.   Notwithstanding anything contained in this Section 4 to the contrary, 
upon termination of the Executive's employment after completion of ten (10)
years of continuous service with the Company (as determined pursuant to the
SERP), the Executive and his eligible dependents shall be entitled to receive
medical, prescription drug, dental and hospitalization benefits for the 
remainder of the Executive's life, the cost of which shall be paid in full by
the Company (if applicable, on the same after-tax basis to the executive
as if the Executive had continued participation in the Company's employee 
benefit plans providing such benefits).  If the Executive is less than age 55 
at the date of such termination of employment, the Executive shall be
entitled to receive such benefits upon attaining age 55 and prior thereto 
the Executive, if applicable, shall be entitled to the medical, prescription
drug, dental and hospitalization benefits provided by paragraphs 4f or g above.

5.	Successor Liability.  The Company shall require any successor (whether 
direct or indirect, by purchase, merger, consolidation or otherwise) to all or 
substantially all of the business and/or assets of the Company to assume
expressly and to agree to perform this Agreement in the same manner and to 
the same extent that the Company would be required to perform.  As used in
this Agreement, "Company" shall mean the company as hereinbefore defined and
any successor to its business and/or assets as aforesaid which assumes and 
agrees to perform this Agreement by operation of law, or otherwise.

6.	Confidential Information.  The Executive agrees to keep secret and retain 
in the strictest confidence all confidential matters which relate to the 
Company, its subsidiaries and affiliates, including, without limitation, 
customer lists, client lists, trade secrets, pricing policies and other 
business affairs of the Company, its subsidiaries and affiliates learned by
him from the Company or any such subsidiary or affiliate or otherwise
before or after the date of this Agreement, and not to disclose any 
such confidential matter to anyone outside the Company or any of its 
subsidiaries or affiliates, whether during or after his period of service 
with the Company, except (i) as such disclosure may be required or appropriate
in connection with his work as an employee of the Company or (ii) when 
required to do so by a court of law, by any governmental agency having 
supervisory authority over the business of the Company or by any 
administrative or legislative body (including a committee thereof) with
apparent jurisdiction to order him to divulge, disclose or make accessible such
information.  The Executive agrees to give the Company advance written notice of
any disclosure pursuant to clause (ii) of the preceding sentence and to 
cooperate with any efforts by the Company to limit the extent of such 
disclosure.  Upon request by the Company, the Executive agrees to deliver
promptly to the Company upon termination of his services for the Company, or at 
any time thereafter as the Company may request, all Company subsidiary or
affiliate memoranda, notes, records, reports, manuals, drawings, designs, 
computer file in any media and other documents (and all copies thereof) 
relating to the Company's or any subsidiary's or affiliate's business and 
all property of the Company or any subsidiary or affiliate associated
therewith, which he may then possess or have under his direct control, other 
than personal notes, diaries, Rolodexes and correspondence.

7.	Non-Compete and Non-Solicitation.  During the Executive's employment by the 
Company and for a period of one year following the termination thereof for any
reason (other than following a Change in Control), the Executive covenants and
agrees that he will not for himself or on behalf of any other person, 
partnership, company or corporation, directly or indirectly, acquire any 
financial or beneficial interest in (except as provided in the next 
sentence), provide consulting services to, be employed by, or own, manage,
operate or control any business which is in competition with a business 
engaged in by the Company or any of its subsidiaries or affiliates in any state
of the United States in which any of them are engaged in business at the time of
such termination of employment for as long as they carry on a business therein.
Notwithstanding the preceding sentence, the Executive shall not be prohibited
from owning less than five (5%) percent of any publicly traded corporation, 
whether or not such corporation is in competition with the Company.
     The Executive hereby covenants and agrees that, at all times during the
period of his employment and for a period of one year immediately following the
termination thereof for any reason (other than following a Change in 
Control), the Executive shall not employ or seek to employ any person 
employed at that time by the Company or any of its subsidiaries, or
otherwise encourage or entice such person or entity to leave such employment.
     It is the intention of the parties hereto that the restrictions contained
in this Section be enforceable to the fullest extent permitted by applicable
law.  Therefore, to the extent any court of competent jurisdiction shall 
determine that any portion of the foregoing restrictions is excessive, such
provision shall not be entirely void, but rather shall be limited or revised
only to the extent necessary to make it enforceable.  Specifically, if any
court of competent jurisdiction should hold that any portion of the 
foregoing description is overly broad as to one or more states of the United
States, then that state or states shall be eliminated from the territory to
which the restrictions of paragraph (a) of this Section applies and the 
restrictions shall remain applicable in all other states of the United States.

8.	No Mitigation.  The Executive shall not be required to mitigate the amount 
of any payments or benefits provided for in paragraph 4f or 4g hereof by seeking
other employment or otherwise and no amounts earned by the Executive shall be 
used to reduce or offset the amounts payable hereunder, except as otherwise 
provided in paragraph 4f or 4g.

9.	Ownership of Work Product.  Any and all improvements, inventions, 
discoveries, formulae, processes, methods, know-how, confidential data, trade
secrets and other proprietary information (collectively, "Work Products") 
within the scope of any business of the Company or any Affiliate which the 
Executive may conceive or make or have conceived or made during the 
Executive's employment with the Company shall be and are the sole and 
exclusive property of the Company, and that the Executive, whenever requested 
to do so by the Company, at its expense, shall execute and sign any and all 
applications, assignments or other instruments and do all other things which
the Company may deem necessary or appropriate (i) to apply for, obtain, 
maintain, enforce, or defend letters patent of the United States or any 
foreign country for any Work Product, or (ii) to assign, transfer, convey or
otherwise make available to the Company the sole and exclusive right, title
and interest in and to any Work Product.

10.	 Arbitration.  Any dispute or controversy between the parties relating to 
this Agreement (except any dispute relating to Sections 6 or 7 hereof) or
relating to or arising out of the Executive's employment with the Company, 
shall be settled by binding arbitration in the City of Syracuse, State of New 
York, pursuant to the Employment Dispute Resolution Rules of the American
Arbitration Association and shall be subject to the provisions of Article 75
of the New York Civil Practice Law and Rules.  Judgment upon the award may 
be entered in any court of competent jurisdiction.  Notwithstanding anything 
herein to the contrary, if any dispute arises between the parties under 
Sections 6 or 7 hereof, or if the Company makes any claim under Sections 6 or 7,
the Company shall not be required to arbitrate such dispute or claim but shall
have the right to institute judicial proceedings in any court of competent 
jurisdiction with respect to such dispute or claim.  If such judicial 
proceedings are instituted, the parties agree that such proceedings shall
not be stayed or delayed pending the outcome of any arbitration proceedings
hereunder.


11.	Notices.  Any notice or other communication required or permitted under 
this Agreement shall be effective only if it is in writing and delivered 
personally or sent by certified mail, postage prepaid, or overnight delivery
addressed as follows:





If to the Company:

Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse, New York  13202

ATTN: Corporate Secretary



If to the Executive:

1053 The Lane
Skaneateles, NY   13152



or to such other address as either party may designate by notice to the other, 
and shall be deemed to have been given upon receipt.

12.	 Entire Agreement.  This Agreement constitutes the entire agreement between
the parties hereto, and supersedes, and is in full substitution for any and all
prior understandings or agreements, oral or written, with respect to the 
Executive's employment.

13.	 Amendment.  This Agreement may be amended only by an instrument in writing 
signed by the parties hereto, and any provision hereof may be waived only by an
instrument in writing signed by the party or parties against whom or which 
enforcement of such waiver is sought.  The failure of either party hereto at any
time to require the performance by the other party hereto of any provision 
hereof shall in no way affect the full right to require such performance at 
any time thereafter, nor shall the waiver by either party hereto of a breach
of any provision hereof be taken or held to be a waiver of any succeeding
breach of such provision or a waiver of the provision itself or a waiver of any 
other provision of this Agreement.


14.	 Obligation to Provide Benefits.  The company may utilize certain financing 
vehicles, including a trust, to provide a source of funding for the 
Company's obligations under this Agreement.  Any such financing vehicles will be
subject to the claims of the general creditors of the Company.  No such 
financing vehicles shall relieve the Company, or its successors, of its 
obligation to provide benefits under this Agreement, except to the extent
the Executive receives payments directly from such financing vehicle.

15.	 Miscellaneous.  This Agreement is binding on and is for the benefit of the 
parties hereto and their respective successors, heirs, executors, administrators
and other legal representatives.  Neither this Agreement nor any right or 
obligation hereunder may be assigned by the Company (except to an Affiliate)
or by the Executive without the prior written consent of the other party.  
This Agreement shall be binding upon any successor to the Company, whether 
by merger, consolidation, reorganization, purchase of all or 
substantially all of the stock or assets of the Company, or by operation of
law.

16.	 Severability.  If any provision of this Agreement, or portion thereof, is 
so broad, in scope or duration, so as to be unenforceable, such provision or 
portion thereof shall be interpreted to be only so broad as is enforceable.

17.	 Governing Law.  This Agreement shall be governed by and construed in 
accordance with the laws of the State of New York without reference to 
principles of conflicts of law.

18.	 Counterparts.  This Agreement may be executed in several counterparts, 
each of which shall be deemed an original, but all of which shall constitute 
one and the same instrument.

19.	 Performance Covenant.  The Executive represents and warrants to the 
Company that the Executive is not party to any agreement which would prohibit 
the Executive from entering into this Agreement or performing fully the 
Executive's obligations hereunder.

20.	 Survival of Covenants.  The obligations of the Executive set forth in 
Sections 6, 7, 9 and 10 represent independent covenants by which the Executive
is and will remain bound notwithstanding any breach by the Company, and shall 
survive the termination of this Agreement.







IN WITNESS WHEREOF, the Company and the Executive have executed this Agreement 
as of the date first written above.


_____________________________	           NIAGARA MOHAWK POWER CORPORATION
      Edward J. Dienst


                                        	By:______________________________
                                               DAVID J. ARRINGTON
                                               Senior Vice President -
                                               Human Resources

	SCHEDULE A

	Modifications in Respect of Edward J. Dienst ("Executive")
	to the
	Supplemental Executive Retirement Plan ("SERP")
 of the
 Niagara Mohawk Power Corporation ("Company")        
                                                    

I.	Subsection 1.8 of Section I of the SERP is hereby modified to provide that 
the term "Earnings" shall mean the sum of the (i) Executive's base annual
salary, whether or not deferred and including any elective before-tax 
contributions made by the Executive to a plan qualified under Section 401(k) of
the Internal Revenue Code, averaged over the final 36 months of the Executive's
employment with the Company and (ii) the average of the annual bonus earned 
by the Executive under the Corporation's Annual Officers Incentive 
Compensation Plan ("OICP"), whether or not deferred, in respect of the final
36 months of the Executive's employment with the Company.  If the Executive 
is an employee of the Company on December 31, 1997 there shall be taken 
into account for purposes of the preceding sentence as an annual bonus under 
the OICP, the sum of (x) cash payments made with respect to Stock Units (and 
related Dividend Equivalents) granted to the Executive under the SIP and (y)
the result of multiplying the number of Stock Appreciation Rights granted to the
Executive under the SIP, prorated if applicable to Article 9 of the SIP, by 
the difference between (1) the value of one share of the Corporation's common
stock on December 31, 1997 and (2) the Base Value ($10.75). 


II.	Subsection 2.1 of Section II of the SERP is hereby modified to provide that
full SERP benefits are vested following ten (10) years of continuous service
with the Company (i.e., 60% of Earnings (as modified above) without reduction 
for an Early Commencement Factor) regardless of the Executive's years of 
continuous service with the Company.  If the Executive is less than age 55 at 
the date of such termination of employment, the Executive shall be entitled to
receive benefits commencing no earlier than age 55, calculated pursuant to 
Section III of the SERP without reduction for an Early Commencement Factor.

III.	Subsection 4.3 of Section IV of the SERP is hereby modified to provide that
in the event of (x) the Executive's involuntary termination of employment by the
Company, at any time, other than for Cause, (y) the termination of this 
Agreement on account of the Executive's Disability or (z) the Executive's 
termination of employment for Good Reason within the 36 full calendar month
period following a Change in Control (as defined in Schedule B of this 
Agreement), the Executive shall be 100% vested in his full SERP benefit
(i.e., 60% of Earnings (as modified above) without reduction for an Early
Commencement Factor) regardless of the Executive's years of continuous service 
with the Company.  If the Executive is less than age 55 at the date of such 
termination of employment, the Executive shall be entitled to receive benefits 
commencing no earlier than age 55, calculated pursuant to Section III of the 
SERP without reduction for an Early Commencement Factor.

IV.	Except as provided above, the provisions of the SERP shall apply and 
control participation therein and the payment of benefits thereunder.





SCHEDULE B


For purposes of this Agreement, the term "Change in Control" shall mean:

(1)	The acquisition by any individual, entity or 	group (within the 
meaning of Sections 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 
1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership 
(within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or
more of either (i) the then outstanding shares of common stock of the Company 
(the "Outstanding Company Common Stock") or (ii) the combined voting power of 
the then outstanding voting securities of the Company entitled to vote generally
in the election of directors (the "Outstanding Company Voting Securities"); 
provided, however, that the following acquisitions shall not constitute a
Change of Control:  (i) any acquisition directly from the Company (excluding an 
acquisition by virtue of the exercise of a conversion privilege), (ii) any 
acquisition by the Company, (iii) any acquisition by any employee benefit plan 
(or related trust) sponsored or maintained by the Company or any corporation 
controlled by the Company or (iv) any acquisition by any corporation pursuant 
to a reorganization, merger or consolidation, if, following such 
reorganization, merger or consolidation, the conditions described in clauses 
(i), (ii) and (iii) of subparagraph (3) of this Schedule B are satisfied; or

(2)	Individuals who, as of the date hereof, constitute the Company's Board 
of Directors (the "Incumbent Board") cease for any reason to constitute at
least a majority of the Board; provided, however, that any individual 
becoming a director subsequent to the date hereof whose election, or nomination
for election by the Company's shareholders, was approved by a vote of at least 
a majority of the directors then comprising the Incumbent Board shall be 
considered as though such individual were a member of the Incumbent Board, but 
excluding, for this purpose, any such individual whose initial assumption of 
office occurs as a result of either an actual or threatened election contest
(as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the 
Exchange Act) or other actual or threatened solicitation of proxies or consents 
by or on behalf of a Person other than the Board; or


(3)	Approval by the shareholders of the Company of a reorganization, merger or 
consolidation, in each case, unless, following such reorganization, merger or 
consolidation, (i) more than 75% of, respectively, the then outstanding shares 
of common stock of the corporation resulting from such reorganization, merger or
consolidation and the combined voting power of the then outstanding voting 
securities of such corporation entitled to vote generally in the election of 
directors is then beneficially owned, directly or indirectly, by all or 
substantially all of the individuals and entities who were the beneficial 
owners, respectively, of the Outstanding Company Common Stock and 
Outstanding Company Voting Securities immediately prior to such 
reorganization, merger or consolidation in substantially the same proportions as
their ownership, immediately prior to such reorganization, merger or 
consolidation, of the Outstanding Company Common Stock and Outstanding 
Company Voting Securities, as the case may be, (ii) no Person (excluding 
the Company, any employee benefit plan (or related trust) of the Company or
such corporation resulting from such reorganization, merger or consolidation and
any Person beneficially owning, immediately prior to such reorganization, merger
or consolidation, directly or indirectly, 20% or more of the Outstanding Company
Common stock or Outstanding Voting Securities, as the case may be) beneficially
owns, directly or indirectly, 20% or more of, respectively, the then outstanding
shares of common stock of the corporation resulting from such reorganization, 
merger or consolidation or the combined voting power of the then outstanding
voting securities of such corporation entitled to vote generally in the election
of directors and (iii) at least a majority of the members of the board of 
directors of the corporation resulting from such reorganization, merger or 
consolidation were members of the Incumbent Board at the time of the 
execution of the initial agreement providing for such reorganization, merger or
consolidation; or


(4)	Approval by the shareholders of the Company of (i) a complete liquidation 
or dissolution of the Company or (ii) the sale or other disposition of all or 
substantially all of the assets of the Company, other than to a corporation, 
with respect to which following such sale or other disposition, (A) more than 
75% of, respectively, the then outstanding shares of common stock of such 
corporation and the combined voting power of the then outstanding voting 
securities of such corporation entitled to vote generally in the election of
directors is then beneficially owned, directly or indirectly, by all or 
substantially all of the individuals and entities who were the beneficial 
owners, respectively, of the Outstanding Company Common Stock and Outstanding 
Company Voting Securities immediately prior to such sale or other disposition in
substantially the same proportion as their ownership, immediately prior to such
sale or other disposition, of the Outstanding Company Common Stock and 
Outstanding Company Voting Securities, as the case may be, (B) no Person 
(excluding the Company and any employee benefit plan (or related 
trust) of the Company or such corporation and any Person beneficially owning,
immediately prior to such sale or other disposition, directly or indirectly, 
20% or more of the Outstanding Company Common Stock or Outstanding Company
Voting Securities, as the case may be) beneficially owns, directly or 
indirectly, 20% or more of, respectively, the then outstanding shares of 
common stock of such corporation and the combined voting power of 
the then outstanding voting securities of such corporation entitled to vote 
generally in the election of directors and (C) at least a majority of the 
members of the board of directors of such corporation were members of the 
Incumbent Board at the time of the execution of the initial agreement or 
action of the Board providing for such sale or other disposition of assets
of the Company.


















<PAGE>


NIAGARA MOHAWK                                            EXHIBIT 10-41

OFFICERS ANNUAL INCENTIVE COMPENSATION PLAN



Article 1.	Establishment, Purpose and Duration

1.1	Establishment of the Plan.  Niagara Mohawk Power Corporation, a New York 
corporation  hereinafter referred to as the  "Company"), hereby amends and 
restates the Niagara Mohawk Officers Annual Incentive Compensation Plan 
(hereinafter referred to as the "Plan"), as set forth in this document.  The
Plan permits the grant of cash awards, Contingent Stock Units and Dividend 
Equivalents, as defined herein.

The Plan became effective as of December 31, 1990 (the "Effective Date").  This
amendment and reinstatement of the Plan is effective as of December 10,
1998 and shall remain in effect as provided in Section 1.3 herein.

	1.2	Purpose of the Plan.  The purpose of the Plan is to encourage the 
achievement of the Company's financial and operating objectives; to assist
the Company in attracting and retaining highly qualified executives; and to 
enhance the mutual interest of customers, shareholders and employees.



Article 2.	Definitions

Whenever used in the Plan, the following terms shall have the meanings set forth
below and, when such meaning is intended, the initial letter of the
word is capitalized:

2.1	"Award" means, individually or collectively, a grant under the Plan of 
Contingent Stock Units.

2.2	"Award Agreement" means an agreement entered into by each Participant and
the Company, setting forth the terms and provisions applicable to an
Award granted to a Participant under the Plan.

2.3	"Board" or "Board of Directors" means the Board of Directors of the Company.

2.4	"Cause" means: (i) a material default or other material breach by a 
Participant of his obligations under any Employment Agreement he may have
with the Company, (ii) failure by a Participant diligently and competently to 
perform his duties under any Employment Agreement he may have with the
Company, or otherwise, or (iii) misconduct, dishonesty, insubordination or other
act by a Participant detrimental to the good will of the Company or damaging the
Company's relationships with its customers, suppliers or employees.  "Cause"
shall be determined in good faith by the Committee.

2.5	"Change in Control" of the Company shall be deemed to have occurred as of 
the first day that any one or more of the following conditions shall have been
satisfied:

(1)	The acquisition by any Person of beneficial ownership  (within the meaning 
of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) 
the then outstanding Shares of the Company or (ii) the combined voting power of
the then outstanding voting securities of the Company entitled to vote generally
in the election of directors (the "Outstanding Company Voting Securities"); 
provided, however, that the following acquisitions shall not constitute a 
Change of Control: (i) any acquisition directly from the Company (excluding
an acquisition by virtue of the exercise of a conversion privilege), (ii) any 
acquisition by the Company, (iii) any acquisition by any employee benefit plan
(or related trust) sponsored or maintained by the Company or any corporation 
controlled by the Company or (iv) any  acquisition by any corporation pursuant 
to a reorganization, merger or consolidation, if, following such 
reorganization, merger or consolidation, the conditions described in clauses
(i), (ii) and (iii) of subparagraph (3) below are satisfied; or

(2)	Individuals who, as of the date hereof, constitute the Board of Directors 
(the "Incumbent Board") cease for any reason to constitute at least a majority
of the Board; provided, however, that any individual becoming a director 
subsequent to the date hereof whose election, or nomination for election by the
Company's shareholders, was approved by a vote of at least a majority of the 
directors then comprising the Incumbent Board shall be considered as though such
individual were a member of the Incumbent Board, but excluding, for this
purpose, any such individual whose initial assumption of office occurs as a
result of either an actual or threatened election contest (as such terms are 
used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act) or
other actual or threatened solicitation of proxies or consents by or on 
behalf of a Person other than the Board; or
		
(3)	Approval by the shareholders of the Company of a reorganization, merger
or consolidation, in each case, unless, following such reorganization, merger 
or consolidation, (i) more than 75 % of, respectively, the then outstanding 
shares of common stock of the corporation resulting from such reorganization,
merger or consolidation and the combined voting power of the then outstanding 
voting securities of such corporation entitled to vote generally in the 
election of directors are then beneficially owned, directly or indirectly, by 
all or substantially all of the individuals and entities who were the 
beneficial owners, respectively, of the Outstanding Shares and Outstanding 
Company Voting Securities immediately prior to such reorganization, merger or
consolidation, in substantially the same proportions as their ownership 
immediately prior to such reorganization, merger or consolidation, of the 
Outstanding Shares and Outstanding Company Voting Securities, as the case may 
be,  (ii) no Person (excluding the Company, any employee benefit plan (or 
related trust) of the Company or such corporation resulting from such 
reorganization, merger or consolidation  and any  Person beneficially owning,
immediately prior to  such  reorganization,  merger or consolidation, directly 
or indirectly, 20% or more of the Outstanding Shares or Outstanding Voting 
Securities, as the case may be) beneficially owns, directly or indirectly, 
20% or more of, respectively, the then outstanding shares of common stock of 
the corporation resulting from such reorganization, merger or consolidation 
or the combined voting power of the then outstanding voting securities of such 
corporation entitled to vote generally in the election of directors and (iii) at
least a majority of the members of the board of directors of the corporation
resulting from such reorganization, merger or consolidation were members of 
the Incumbent Board at the time of the execution of the initial agreement 
providing for such reorganization, merger or consolidation; or  

(4)	Approval by the shareholders of the Company of (i) a complete liquidation or
dissolution of the Company or (ii) the sale or other disposition of all or 
substantially all of the assets of the Company, other than to a corporation, 
with respect to which following such sale or other disposition, (A) more than 
75% of, respectively, the then outstanding shares of common stock of such 
corporation and the combined voting power of the then outstanding voting 
securities of such corporation entitled to vote generally in the 
election of directors is then beneficially owned, directly or indirectly, by all
or substantially all of the individuals and entities who were the beneficial 
owners, respectively, of the Outstanding Shares and Outstanding Company Voting 
Securities immediately prior to such sale or other disposition in substantially
the same proportion as their ownership immediately prior to such sale or other
disposition of the Outstanding Shares and Outstanding Company Voting Securities,
as the case may be, (B) no Person (excluding the Company and any employee 
benefit plan (or related trust) of the  Company or such corporation and any 
Person beneficially owning, immediately prior to such sale or other disposition,
directly or indirectly, 20% or more of the Outstanding Shares or Outstanding 
Company Voting Securities, as the case may be) beneficially owns, directly or 
indirectly, 20% or more of, respectively, the then outstanding shares of 
common stock of such corporation and the combined voting power of the then 
outstanding voting securities of such corporation entitled to vote generally 
in the election of directors and (C) at least a majority of the members of
the board of directors of such corporation were members of the Incumbent Board 
at the time of the execution of the initial agreement or action of the Board 
providing for such sale or other disposition of assets of the Company;

provided, however, that the implementation of the corporate restructuring 
contemplated by the Company's PowerChoice proposal filed with the New 
York Public Service Commission on October 6, 1995, or any substantially 
similar corporate restructuring (as determined by the Committee) shall 
not be deemed to be a "Change in Control".


2.6	"Code" means the Internal Revenue Code of 1986, as amended from time to 
time.

2.7	"Committee" means the committee, as specified in Article 3, appointed by 
theBoard to administer the Plan with respect to grants of Awards.

2.8	"Company" means Niagara Mohawk Power Corporation, a New York corporation, 
or any successor thereto as provided in Article 17 herein.

2.9 "Compensation" means the base salary earned by a Participant during any 
Performance Period, excluding overtime, premium, bonus or other special 
payments.

2.10 "Contingent Stock Unit" means a right, designated as a Contingent Stock 
Unit, to receive a payment as soon as practicable following the last day of 
a Vesting Period, pursuant to the terms of Articles 7 and 8 herein.  Each 
Contingent Stock Unit shall be denominated in terms of one Share.

2.11 "Director" means any individual who is a member of the Board of 
Directors of the Company.

2.12 "Disability" shall have the meaning ascribed to such term under Section
22(e)(3) of the Code.

2.13 "Dividend Equivalent" means, with respect to Shares underlying a Contingent
Stock Unit, an amount equal to all cash and stock dividends declared on an 
equal number of outstanding Shares on all common stock dividend payment dates
occurring during the Vesting Period.

2.14 "Exchange Act" means the Securities Exchange Act of 1934, as amended from
time to time, or any successor act thereto.

2.15 "Fair Market Value" means the average of the daily opening and closing 
sale prices as reported in the consolidated transaction reporting system.

2.16 "Incentive Award" means a Participant's award for a Performance Period 
under this Plan, expressed as a percentage of the Participant's Compensation.

2.17 "Participant" means an officer of the Company whose salary is fixed by
the Board of Directors of the Company.

2.18 "Performance Period" means a period of a calendar year during which 
Incentive Awards may be earned by Participants in the Plan.

2.19 "Person" shall have the meaning ascribed to such term in Section 3(a)
(9) of the Exchange Act, as used in Sections 13(d) and 14(d) thereof, 
including usage in the definition of a "group" in Section 13(d) thereof.

2.20 "Plan" means this Officers Annual Incentive Compensation Plan.

2.21 "Program" means the identified performance criteria goals and 
associated incentive award opportunities, together with the other 
terms and conditions, approved for a particular Performance Period.

2.22 "Retirement" means (i) ascribed to such term in the tax-qualified 
defined benefit pension plan maintained by the Company for the 
benefit of some or all of its non-represented employees and (ii) retirement 
from the Company or its subsidiaries with the approval of the 
Committee.

2.23 "Shares" means the shares of common stock of the Company, par value $1.

2.24 "Subsidiary" means any corporation that is a "subsidiary corporation" 
of the Company as that term is defined in Section 424(f) of the Code.

2.25 "Valuation Period" means the 12 trading day period ending on and 
including the relevant date.

2.26 "Vesting Period" means the period during which Stock Units are not yet
payable, as set forth in the related Award Agreement.

Article 3.	Administration

3.1	The Committee.  The Plan shall be administered by the Compensation and 
Succession Committee of the Board, or by any other Committee appointed by the
Board consisting of not less than two (2) non-employee Directors.  The 
members of the Committee shall be appointed from time to time by, and shall 
serve at the discretion of, the Board of Directors.  

3.2	Authority of the Committee.  The Committee shall have full power except 
as limited by law, the Articles of Incorporation and the Bylaws of the 
Company, subject to such other restricting limitations or directions as may 
be imposed by the Board and subject to the provisions herein, to determine 
the size and types of Awards; to determine the terms and conditions of such 
Awards in a manner consistent with the Plan; to construe and interpret the 
Plan and any agreement or instrument entered into under the Plan; to 
establish, amend or waive rules and regulations for the Plan's 
administration; and (subject to the provisions of Article 14 herein) to amend
the terms and conditions of any outstanding Award.  Further, the Committee 
shall make all other determinations that may be necessary or advisable for 
the administration of the Plan.  As permitted by law, the Committee may 
delegate its authorities as identified hereunder.

3.3	Decisions Binding.  All determinations and decisions made by the Committee
pursuant to the provisions of the Plan and all related orders or resolutions of
the Board shall be final, conclusive and binding on all persons, including 
the Company, its shareholders, Employees, Participants and their estates and 
beneficiaries .

3.4	Costs.  The Company shall pay all costs of administration of the Plan.


Article 4.	Adjustments in Authorized Shares

 In the event of any merger, reorganization consolidation, recapitalization, 
separation, liquidation, stock dividend, split-up, share combination or other 
change in the corporate structure of the Company affecting the Shares, such 
adjustment shall be made in the number of Contingent Stock Units that may be 
granted under the Plan, and in the number and/or price of outstanding Awards 
granted under the Plan, as may be determined to be appropriate and equitable
by the Committee, in its sole discretion, to prevent dilution or enlargement of
rights; provided, however, that the number of Contingent Stock Units subject
to an Award shall always be a whole number.


Article 5.   Eligibility and Participation

5.1	Eligibility.  Any person who is a Participant for the entire length of a 
Performance Period shall be eligible for consideration for an Incentive Award
with respect to that Performance Period.  The Committee may provide a 
prorated Incentive Award for a person who becomes a Participant during the 
Performance Period and meets such other requirements as the Committee deems 
appropriate.  However, any Participant whose performance is evaluated as 
unacceptable during a Performance Period shall be ineligible for any Incentive 
Award with respect to that Performance Period.

5.2	Termination.  Any Participant who resigns or is terminated for any reason 
during a Performance Period will not be eligible for any Incentive Award with 
respect to that Performance Period.

5.3	Retirement or Death of a Participant.  In the event of the death or 
retirement of a Participant during a Performance Period such Participant may, 
in the discretion of the Committee, be considered for a prorated Incentive 
Award with respect to that Performance Period to the extent the Committee 
deems appropriate.


Article 6.   Performance Criteria and Award Opportunities

6.1	Before the beginning of a Performance Period, the Committee shall approve 
the terms of the Program for that particular Performance Period.  The Program
shall include identified performance criteria and related award opportunities.

6.2	The Program may include designations of contingent events whose 
occurrence during the Performance Period is a required prerequisite to or 
would preclude the approval and payment of any Incentive Award.

6.3	The Program may define maximum award opportunities for identified groups of
Participants by officer levels or other appropriate groupings.

6.4	The Program may include various combinations of goals applicable to all 
Participants, goals applicable to Participants in separate business units, 
and goals applicable to Participants in specific departments, as may be 
appropriate.  Each goal shall be matched with a corresponding award 
opportunity for successful accomplishment.



Article 7.	Determination of Participant Incentive Awards

7.1 Following the completion of a Performance Period, the Committee shall 
undertake or direct an evaluation of performance as compared to the 
appropriate performance criteria established for the Performance Period, and 
compute Participants tentative Incentive Awards.

7.2	The Committee may adjust or prorate the Incentive Award of any Participant 
to the extent it deems appropriate to reflect changes in responsibilities 
during a Performance Period.

7.3	The Committee shall review all tentative Incentive Awards and may, in its 
discretion, reduce or eliminate any Participant's tentative Incentive Award 
as it deems warranted by extraordinary circumstance.

7.4 The Committee may, for reasons it deems appropriate, in its discretion, 
determine to delay, disapprove, or eliminate all tentative Incentive Awards 
for any Performance Period.

7.5 No Incentive Award may be paid without the prior approval of the Committee.

7.6 Incentive Awards will be paid by check as soon as practicable following 
the end of the Performance Period to which they relate.  The Company shall 
deduct from any payment any sums required to be withheld by applicable 
federal, state, or local tax laws.  Incentive Award payments will not be 
considered as earnings for purposes of the Niagara Mohawk Pension Plan, the 
Employee Savings Fund Plan, or any other employee benefit or insurance programs.


Article 8.	Contingent Stock Units

8.1	Subject to the terms and conditions of the Plan, the Committee may, in its 
discretion, convert Incentive Award opportunities into Contingent Stock 
Units, which may be granted to Participants at the beginning of a Period.

8.2	The number of Contingent Stock Units to be granted will be determined by
multiplying Compensation or Projected Compensation (as determined by the 
Committee) as of the end of the Performance Period by the Incentive Award 
opportunity, and dividing that amount by the Fair Market Value of a Share 
determined for the 12 trading day period immediately preceding the date of 
the grant, or for such other period as the Committee, in its sole discretion, 
shall determine at the time of the grant.

8.3	The vesting of Contingent Stock Units granted under the Plan shall be 
determined by the Committee, in its sole discretion, as set forth in the 
related Award Agreement.

8.4	After the conclusion of the applicable Performance Period, the number of 
Contingent Stock Units which vest will be determined by multiplying the 
number of Contingent Stock Units granted by a percentage representing the degree
to which goals in the Plan (the Program) were accomplished during the 
Performance Period.  The number of Contingent Stock Units which vest may also be
adjusted at the conclusion of the Performance Period to reflect actual 
earnings during the Performance Period.

8.5	After determining the number of Contingent Stock Units which vest and become
payable, the payment value will be determined by multiplying the number of 
vested Contingent Stock Units by the Fair Market Value of a share.

8.6	Payment of Contingent Stock Units.  After the applicable Vesting Period has
ended, the holder of Contingent Stock Units shall be entitled to receive, for 
each vested Contingent Stock Unit held,  payment in cash from the Company in an
amount equal to the Fair Market Value of one Share determined as of the 
Valuation Period ending on the last day of the Vesting Period.  Payment shall be
made as soon as practicable following the last day of the Vesting Period.

8.7	Contingent Stock Unit Award Agreement.  Each Contingent Stock Unit grant 
shall be evidenced by an Award Agreement that shall specify the number of 
Contingent Stock Units granted, the Vesting Period and such other provisions as
the Committee shall determine.


Article 9.	Dividend Equivalents

Simultaneously with the grant of Contingent Stock Units, the Participant may be
granted Dividend Equivalents, to be credited to a bookkeeping entry account, 
on each common stock dividend payment date with respect to the Shares subject to
such Award.  In the case of cash dividends, the number of Dividend 
Equivalents credited on each common stock dividend payment date shall equal the
number of Shares (including fractional Shares) that could be purchased on the 
dividend payment date, based on the average of the opening and closing sale 
price, as reported in the consolidated transaction reporting system on that 
date, with cash dividends that would have been paid on Awards of Contingent 
Stock Units and on Dividend Equivalents previously credited to such 
bookkeeping entry account, if such Contingent Stock Units or Dividend 
Equivalents were Shares.  In the case of stock dividends, the number of 
Dividend Equivalents credited on each stock dividend payment date shall be equal
to the number of Shares (including fractional Shares) that would have been 
issued as a stock dividend in respect of the Participant's Contingent Stock 
Units and on Dividend Equivalents previously credited to such bookkeeping 
entry account, if such Contingent Stock Units or Dividend Equivalents 
were Shares.

Participants shall receive cash payment from the Company of the Fair Market 
Value of the Dividend Equivalents, if and when they receive payment of the 
related Contingent Stock Units, the Fair Market Value of such Dividend 
Equivalents to be determined in the same manner as for the 
related Contingent Stock Units.

The Committee may, in its discretion, establish such rules and procedures 
governing the  crediting of Dividend Equivalents, including timing and 
payment contingencies that apply to the Dividend Equivalents, as the 
Committee deems necessary or appropriate in order to comply with 
applicable law.


Article 10.	Termination of Employment

10.1 Disability; Involuntary Termination.   In the event the employment of a
Participant is terminated by reason of Disability or involuntarily by the 
Company (other than for Cause) during a Vesting Period for Contingent Stock 
Units, the Participant shall receive a full payout of the Contingent Stock 
Units and related Dividend Equivalents, as and when provided in Section 8 
herein.

10.2 Death.  In the event the employment of a Participant is terminated by 
reason of death during the Vesting Period for Contingent Stock Units, the 
Participant's beneficiary or estate shall receive a full payout of the  
Contingent Stock Units and related Dividend Equivalents. The payout shall be 
made promptly based on the Fair Market Value of a Share on the date 
of death.

10.3 Retirement.  In the event the employment of a Participant is terminated by
reason of Retirement during a Vesting Period for Contingent Stock Units, the 
Participant shall receive a prorated payout of the Contingent Stock Units 
and related Dividend Equivalents.  The prorated payout shall be determined by
the Committee, shall be based upon the length of time that the Participant
held the Contingent Stock Units during the Vesting Period and shall be made as 
and when provided in Section 8.

10.4	Other than as set forth in Article 13, in the event that a Participant's
employment terminates for any reason other than as set forth in Sections 
10.1, 10.2 and 10.3, above,  all Contingent Stock Units and Dividend  
Equivalents shall be forfeited by the Participant to the Company .

10.5 Right of Committee.  Subject to the provisions of Section 14.2 herein, all
provisions in this Article 10 are subject to the Committee's right, at any 
time, to make such other determinations as it may choose, in its sole 
discretion.  Furthermore, should more than one section of Article 10 and/or 
Article 14 apply to a situation, the Committee shall have the right, in its sole
discretion, to determine which section and/or article to apply.


Article 11.	Beneficiary Designation

Each Participant under the Plan may, from time to time, name any beneficiary or
beneficiaries (who may be named contingently or successively) to whom any 
benefit under the Plan is to be paid in case of his death before he receives any
or all of such benefit.  Each such designation shall revoke all prior 
designations by the same Participant, shall be in a form prescribed by the
Committee, and will be effective only when filed by the Participant in 
writing with the Committee during the Participant's lifetime. In the absence of
any such designation, benefits remaining unpaid at the Participant's death 
shall be paid to the Participant's estate.

The spouse of a married Participant domiciled in a community property 
jurisdiction shall join in any designation of beneficiary or beneficiaries 
other than the spouse.


Article 12.	Rights of Participants

12.1 Employment.  Nothing in the Plan shall interfere with or limit in any way
the right of the Company to terminate any Participant's employment at any 
time, for any reason or no reason, in the  Company's sole discretion, nor confer
upon any Participant any  right to continue in the employ of the Company.

12.2 Participation.  No Participant shall have the right to be selected to 
receive an Award or Incentive Award under the Plan, or, having been so 
selected, to be selected to receive a future Award or Incentive Award.


Article 13.	Change in Control

Any Vesting Period with respect to Contingent Stock Units shall be deemed to 
have expired, and there shall be paid out in cash to Participants within 
thirty (30) days following the effective date of the Change in Control the cash
payment due with respect to such Contingent Stock Units and related Dividend
Equivalents, with a Valuation Period ending on the effective date of the Change
in Control.


Article 14.   Amendment, Modification and Termination

14.1	 Amendment. Modification and Termination.  The Board may, at any time and 
from time to time, alter, amend, suspend or terminate the Plan in whole or in
part.

14.2 Awards Previously Granted.  No termination, amendment or modification of 
the Plan shall adversely affect in any material way any Award or Incentive 
Award previously granted under the Plan, without the written consent of the 
Participant holding such Award, unless such termination, modification or 
amendment is required by applicable law.


Article 15.	Tax Withholding

The Company shall have the power and the right to deduct or withhold, or require
a Participant to remit to the Company, an amount sufficient to satisfy 
Federal, state and local taxes (including the Participant's FICA obligation) 
required by law to be withheld with respect to any taxable event arising out
of or as a result of an Award or Incentive Award made under the Plan.

Article 16.	Successors

All obligations of the Company under the Plan, with respect to Awards or 
Incentive Awards granted hereunder shall be binding on any successor to the 
Company, whether the existence of such successor is the result of a direct or
indirect purchase, merger, consolidation or otherwise, of all or 
substantially all of the business and/or assets of the Company.



Article 17.	Legal Construction

17.1	 Gender and Number.  Except where otherwise indicated by the context, any
masculine term used herein also shall include the feminine, the plural shall 
include the singular and the singular shall include the plural.

17.2	 Severability.  In the event any provision of the Plan shall be held 
illegal or invalid for any reason, the illegality or invalidity 
shall not affect the remaining parts of the Plan, and the Plan shall be 
construed and enforced as if the  illegal or invalid provision had not 
been included.

17.3 Requirements of Law.  The granting of Awards or Incentive Awards under the
Plan shall be subject to all applicable laws, rules and regulations, and to 
such approvals by any governmental agencies or national securities exchanges 
as may be required.

17.4 Governing Law.  To the extent not preempted by Federal law, the Plan, 
and all agreements hereunder, shall be construed in accordance with, and 
governed by, the laws of the State of New York, without regard to conflicts 
of law provisions.

17.5 Notices.  Any notice to a Participant may be given either by personal 
delivery or by depositing it in the United States mail, postage prepaid, 
addressed to his last-known address.  Any notice to the Company or the 
Committee shall be given either by delivering it or depositing it in the 
United States mail, postage prepaid, to the Secretary, Niagara Mohawk, 300 Erie
Boulevard West, Syracuse, New York 13202.

17.6 No Waiver.  Failure by the Company or the Committee to insist upon strict
compliance with any of the terms or conditions of this Plan shall not be 
deemed a waiver of any such term or condition, nor shall any waiver or 
relinquishment of any right or power at any one or more times be deemed a 
waiver or relinquishment of any such right or power at any other time or times.

17.7 Partial Invalidity.  The invalidity or unenforceability of any provision of
this Plan shall not affect the validity or enforceability of any other 
provision.

17.8 Venue of any suit involving the Plan or Plan benefits shall lie in Onondaga
County, New York, if a state court action, and in the United States District 
Court, Northern District of New York, if a federal court action.







<PAGE>


                                                                      EXHIBIT 11

            NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

       COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING

<TABLE>
<CAPTION>

                                                                                        Average Number
                                                                                        of Shares Out-
                                                                                      standing as shown
                                                                                       on Consolidated
                                      (1)             (2)                            Statements of Income
                                   Shares of        Number            (3)                 (3 divided
                                    Common          of Days        Share Days          by number of days
Year Ended December 31,              Stock        Outstanding        (2 x 1)                in year)
-----------------------------   ----------------- ------------  ------------------   --------------------
<S>                             <C>               <C>             <C>                    <C>
       1998
       ----
JANUARY 1 - DECEMBER 31         144,419,351       365             52,713,063,115 

SHARES ISSUED IN ACCORDANCE
   WITH THE MRA AGREEMENT
   JUNE 30                       42,945,512       185              7,944,919,720
                                -----------                        -------------
                                187,364,863                       60,657,982,835         166,186,254
                                ===========                       ==============         ===========

       1997
       ----
January 1 - December 31         144,365,214       365             52,693,303,110 

Shares issued at various
   times during the period -
   Acquisition - Syracuse
   Suburban Gas Company, Inc.        54,137         *                 14,260,096
                                -----------                       --------------
                                144,419,351                       52,707,563,206         144,404,283
                                ===========                       ==============         ===========

       1996
       ----
January 1 - December 31         144,332,123       366             52,825,557,018

Shares issued at various
   times during the period -
   Acquisition - Syracuse
   Suburban Gas Company, Inc.        33,091         *                  6,397,653
                                -----------                       --------------
                                144,365,214                       52,831,954,671         144,349,603
                                ===========                       ==============         ===========

</TABLE>

*  Number of days outstanding not shown as shares represent an accumulation
   of weekly, monthly and quarterly issues throughout the year.  Share days
   for shares issued are based on the total number of days each share was
   outstanding during the year.

Note:  Earnings per share calculated on both a basic and diluted basis are
       the same due to the effects of rounding.

<PAGE>

                                                                      EXHIBIT 12

            NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

  STATEMENT SHOWING COMPUTATIONS OF RATIO OF EARNINGS TO FIXED CHARGES, RATIO OF
EARNINGS TO FIXED CHARGES WITHOUT AFC AND RATIO OF EARNINGS TO FIXED CHARGES AND
                            PREFERRED STOCK DIVIDENDS
<TABLE>
<CAPTION>

                                                   Year Ended December 31,
                                       ----------------------------------------------
                                       1998       1997      1996     1995      1994
                                   --------------------------------------------------
<S>                                <C>         <C>       <C>       <C>       <C>
A..Net Income (Loss) per
   Statements of Income . .        $(120,825)  $183,335  $110,390  $248,036  $176,984
B. Taxes Based on Income or
   Profits. . . . . . . . .          (66,728)   126,595    66,221   159,393   111,469
                                   ----------  --------  --------  --------  --------
C. Earnings, Before Income
   Taxes. . . . . . . . . .         (187,553)   309,930   176,611   407,429   288,453
D. Fixed Charges (a)                 433,313    304,451   308,323   314,973   315,274
                                   ----------  --------  --------  --------  --------
E. Earnings Before Income
   Taxes and Fixed Charges.          245,760    614,381   484,934   722,402   603,727
F. Allowance for Funds Used
   During Construction. . .           18,854      9,706     7,355     9,050     9,079
                                   ----------  --------  --------  --------  --------
G. Earnings Before Income
   Taxes and Fixed Charges
   without AFC. . . . . . .        $ 226,906   $604,675  $477,579  $713,352  $594,648
                                   ==========  ========  ========  ========  ========

  PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend
   Requirements . . . . . .        $  36,555   $ 37,397  $ 38,281  $ 39,596  $ 33,673
                                   ==========  ========  ========  ========  ========
I. Ratio of Pre-Tax Income
   to Net Income (C/A). . .              N/A       1.69      1.60      1.64      1.63
J. Preferred Dividend Factor
   (H x I). . . . . . . . .        $  36,555   $ 63,201  $ 61,250  $ 64,937  $ 54,887
K. Fixed Charges as above (D)        433,313    304,451   308,323   314,973   315,274
                                   ----------  --------  --------  --------  --------
L. Fixed Charges and Preferred
   Dividends Combined . . .        $ 469,868   $367,652  $369,573  $379,910  $370,161
                                   =========   ========  ========  ========  ========
M. Ratio of Earnings to
   Fixed Charges (E/D). . .             0.57       2.02      1.57      2.29      1.91
                                   =========   ========  ========  ========  ========
N. Ratio of Earnings to Fixed
   Charges and Preferred
   Dividends Combined (E/L)             0.52       1.67      1.31      1.90      1.63
                                 ===========   ========  ========  ========  ========
</TABLE>
(a)  Includes a portion of rentals deemed representative of the interest
     factor:  $25,907 for 1998, $26,149 for 1997, $26,600 for 1996, $27,312
     for 1995 and $29,396 for 1994.

N/A - Not applicable due to net loss displayed in line A.

<PAGE>

                                                                      EXHIBIT 21

            NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

                         SUBSIDIARIES OF THE REGISTRANT

Name of Company                                State of Organization
---------------                                ---------------------

Opinac North America, Inc.                     Delaware
  (Note 1)

NM Uranium, Inc.                               Texas

EMCO-TECH, Inc. (Note 2)                       New York

NM Properties, Inc. (Note 3)                   New York

Moreau Manufacturing Corporation (Note 4)      New York

Beebee Island Corporation (Note 4)             New York

NM Receivables Corp. II                        New York

NM Receivables. LLC                            New York

Note 1:  At December 31, 1998, Opinac North America, Inc. owns Opinac Energy
Corporation and Niagara Mohawk Energy, Inc. (formerly Plum Street Enterprises,
Inc.).  Opinac Energy Corporation has portfolio investments and has a 50 percent
interest in CNP, which is incorporated in the Province of Ontario, Canada.  CNP
owns, through subsidiary companies, a wind power facility in Alberta, Canada.
Niagara Mohawk Energy, Inc., an unregulated company, is incorporated in the
State of Delaware.  Niagara Mohawk Energy, Inc., among other investments, owns
Niagara Mohawk Energy Marketing, Inc. (incorporated in the State of Delaware),
Global Energy Enterprises India Private Limited, 90% of Dolphin Investments
International, Inc. (a corporation organized and existing under the laws of
Nevis, West Indies).

Note 2:  EMCO-TECH, Inc. is inactive at December 31, 1998 and was dissolved on
January 15, 1999.

Note 3:  At December 31, 1998, NM Properties, Inc. (formerly NM Holdings, Inc.)
owns Salmon Shores, Inc., Moreau Park, Inc., Riverview, Inc., Hudson Pointe,
Inc., Upper Hudson Development, Inc., Land Management & Development, Inc.,
OPropco, Inc. and LandWest, Inc.

Note 4:  The Company has included its interest in the subsidiary in its sale of
its hydroelectric generating plants.

<PAGE>

                                                                      EXHIBIT 23

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration
Statement on Form S-8 (Nos. 33-36189, 33-42771 and 333-13781) and to the
incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-3 (Nos. 33-50703, 33-51073, 33-54827 and
33-55546) and in the Prospectus/Proxy Statement constituting part of the
Registration Statement on Form S-4 (No. 333-49769) of Niagara Mohawk Power
Corporation of our report dated January 28, 1999 appearing in the Company's Form
10-K dated March 9, 1999.  We also consent to the incorporation by reference
of our report on the Financial Statement Schedule, which appears in this Form
10-K.





/s/PricewaterhouseCoopers LLP
-----------------------------
PricewaterhouseCoopers LLP
Syracuse, New York

January 28, 1999



                                   SIGNATURES

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

                        NIAGARA MOHAWK POWER CORPORATION
                                  (REGISTRANT)



Date:  March 9,1999                                 /s/Steven W. Tasker
                                                    -------------------
                                                    Steven W. Tasker
                                                    Vice President-Controller
                                                    and Principal Accounting
                                                    Officer


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

Signature                      Title                        Date
---------                      -----                        ----


/s/Salvatore H. Alfiero       Director                 February 25, 1999
-----------------------
Salvatore H. Alfiero



/s/William F. Allyn           Director                 February 25, 1999
-------------------
William F. Allyn



                              Director,
/s/Albert J. Budney Jr.       President                February 25, 1999
-----------------------
Albert J. Budney Jr.



/s/Lawrence Burkhardt III     Director                 February 25, 1999
-------------------------
Lawrence Burkhardt III


                              Chairman of the
                              Board of Directors
                              and Chief Executive
/s/William E. Davis           Officer                  February 25, 1999
-------------------
William E. Davis



/s/William J. Donlon          Director                 February 25, 1999
--------------------
William J. Donlon



/s/Anthony H. Gioia           Director                 February 25, 1999
------------------- 
Anthony H. Gioia



/s/Bonnie G. Hill             Director                 February 25, 1999
-----------------
Bonnie G. Hill



/s/Clark A. Johnson           Director                 February 25, 1999
-------------------
Clark A. Johnson



/s/Henry A. Panasci Jr.       Director                 February 25, 1999
-----------------------
Henry A. Panasci Jr.



/s/Patti McGill Peterson      Director                 February 25, 1999
------------------------
Patti McGill Peterson



/s/Donald B. Riefler          Director                 February 25, 1999
--------------------
Donald B. Riefler



/s/Stephen B. Schwartz        Director                 February 25, 1999
----------------------
Stephen B. Schwartz



                              Executive Vice President
/s/Darlene D. Kerr            Energy Delivery          February 25, 1999
------------------
Darlene D. Kerr



                              Senior Vice President
                              and Chief Financial
/s/William F. Edwards         Officer                  February 25, 1999
---------------------
William F. Edwards



                              Vice President-Controller
                              and Principal Accounting
/s/Steven W. Tasker           Officer                  February 25, 1999
-------------------
Steven W. Tasker