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

             ___  Transition Report Pursuant to Section 13 or 15(d)
                     of the Securities Exchange Act of 1934

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                         COMMISSION FILE NUMBER  1-8291

                        GREEN MOUNTAIN POWER CORPORATION
                        --------------------------------
             (Exact name of registrant as specified in its charter)

         Vermont                                  03-0127430
         -------                                  ----------
(State  or  other jurisdiction of           (I.R.S. Employer Identification No.)
 incorporation  or  organization)

    163  Acorn  Lane
    Colchester,  VT                                           05446
-------------------------------------------------------------------
(Address  of  principal  executive  offices)                      (Zip  Code)

Registrant's  telephone  number,  including  area  code         (802)  864-5731
                                                                ---------------

           Securities registered pursuant to Section 12(b) of the Act:
     Title  of Each Class              Name of each exchange on which registered

COMMON  STOCK,  PAR  VALUE                  NEW  YORK  STOCK  EXCHANGE
  $3.33-1/3  PER  SHARE
________________________________________________________________________
       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_
              -
Indicate  by  check  mark  whether  the  registrant  is an accelerated filer (as
defined  in  Exchange  Act  Rule  12b-2).  Yes  _X_   No
                                                ---
     THE  AGGREGATE  MARKET  VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF
THE REGISTRANT AS OF MARCH 12, 2003, WAS APPROXIMATELY $100,939,195 BASED ON THE
CLOSING  PRICE  OF $20.35 FOR THE COMMON STOCK ON THE NEW YORK STOCK EXCHANGE AS
REPORTED  BY  THE  WALL  STREET  JOURNAL.
     THE  NUMBER  OF  SHARES  OF COMMON STOCK OUTSTANDING ON MARCH 12, 2003, WAS
4,960,157
                       DOCUMENTS INCORPORATED BY REFERENCE
     The  Company's Definitive Proxy Statement relating to its Annual Meeting of
Stockholders  to  be  held  on  May  15,  2003,  to be filed with the Commission
pursuant  to  Regulation  14A  under  the  Securities  Exchange  Act of 1934, is
incorporated  by  reference  in Items 10, 11, 12 and 13 of Part III of this Form
10-K.

2

Green  Mountain  Power  Corporation
Form  10-K  for  the  fiscal  year  ended  December  31,  2002
Table  of  contents                              Page

Part  I
Item  1,  Business                                      3

Item  2,  Properties                              17

Item  3,  Legal  Proceedings                         18

Item  4,  Submission  of  Matters  To  a  Vote  of          18
     Security  Holders

Part  II
Item  5,  Market  for  Registrant's  Common
     Equity  and  Related  Shareholder  Matters          19

Item  6,  Selected  Financial  Data                    20

Item  7,  Management's  Discussion  and  Analysis          21
     Of  Financial  Condition  and  Results
     Of  Operations

Item  8,  Index  to  Consolidated  Financial  Statements
     and  Notes          42

Item  9,  Changes  In  and  Disagreements  with  Accountants     79
     On  Accounting  and  Financial  Disclosure

Items  10  through  13,  Certain  Officer  information     79

Item  14,  Controls  and  Procedures                    79

Item  15,  Exhibits,  Financial  Statement  Schedules,     79
     And  Reports  on  Form  8-K




PART  I
     There  are statements in this section that contain projections or estimates
and that are considered to be "forward-looking" as defined by the Securities and
Exchange  Commission  (the "SEC").  In these statements, you may find words such
as  believes,  expects,  plans,  or  similar  words.  These  statements  are not
guarantees  of our future performance.  There are risks, uncertainties and other
factors  that  could  cause actual results to be different from those projected.
Some  of  the  reasons  the results may be different are discussed under Item 7,
Management's  Discussion  and  Analysis  of  Financial  Condition and Results of
Operations  ("MD  and  A"),  in  the 2002 Annual Report to Shareholders ("Annual
Report"),  and  in  the  accompanying Notes to Consolidated Financial Statements
("Notes"),  all  included  herein.

ITEM  1.  BUSINESS
THE  COMPANY
     Green  Mountain  Power  Corporation  (the  "Company"  or "GMP") is a public
utility operating company engaged in supplying electrical energy in the State of
Vermont  ("State" or "Vermont") in a territory with approximately one quarter of
the  State's  population.  We serve approximately 88,000 customers.  The Company
was  incorporated  under  the  laws  of  the  State  on  April  7,  1893.

     Our  sources  of  revenue  for  the  year  ended  December 31, 2002 were as
follows:
*     26.8  percent  from  residential  customers;
*     28.4  percent  from  small  commercial  and  industrial  customers;
*     17.7  percent  from  large  commercial  and  industrial  customers;
*     25.8  percent  from  sales  to  other  utilities;  and
*     1.3  percent  from  other  sources.
     See  the Annual Report and MD and A for further information about revenues.

     During  2002,  our  energy  resources  for  retail  and  wholesale sales of
electricity,  excluding  sales made pursuant to the contract with Morgan Stanley
Capital  Group, Inc. ("MS") discussed under MD and A-Power Contract Commitments,
were  obtained  as  follows:
*     40.8  percent  from  hydroelectric sources (32.8 percent Hydro Quebec, 5.0
percent  Company-owned,  2.9  percent small power producers, and 0.1 percent New
York  Power  Authority  ("NYPA"));
*     34.9  percent  from a nuclear generating source (the Entergy nuclear plant
described  below);
*     3.6  percent  from  wood;
*     2.5  percent  from  natural  gas;
*     1.5  percent  from  oil;  and
*     0.5  percent  from  wind.
     The  remaining  16.2 percent was purchased on a short-term basis from other
utilities  through the Independent System Operator of New England ("ISO" or "ISO
New  England"),  formerly  the  New  England  Power  Pool  ("NEPOOL").
     In  2002,  we purchased 90.7 percent of our energy resources to satisfy our
retail  and  wholesale  sales  of  electricity,  including energy purchased from
Vermont  Yankee  Nuclear  Power Corporation ("Vermont Yankee" or "VY") and under
other  long-term purchase arrangements, but excluding purchases for resale under
the  MS  contract.  See  Note  K  of  Notes.
     A  major source of the Company's power supply is our entitlement to a share
of  the  power generated by the 531 megawatt (MW) nuclear generating plant owned
and operated by Entergy Vermont Yankee Nuclear Corporation ("Entergy").  We have
an  18.99 percent equity interest in Vermont Yankee, which has a long-term power
supply  contract  with  Entergy,  that entitles us to 20 percent of plant output
through  2012  For  further  information  concerning  Vermont  Yankee, see Power
Resources  -  Vermont  Yankee.
     The  Company  participates  in  NEPOOL,  a regional bulk power transmission
organization  established  to assure reliable and economical power supply in the
Northeast.  The ISO was created to manage the operations of NEPOOL in 1999.  The
ISO  works  as  a clearinghouse for purchasers and sellers of electricity in the
deregulated  wholesale energy markets.  Sellers place bids for the sale of their
generation  or purchased power resources and if demand is high enough the output
from  those  resources is sold.  We must purchase additional electricity to meet
customer  demand  during periods of high usage and to replace energy repurchased
by  Hydro  Quebec  under  an arrangement negotiated in 1997.  Our costs to serve
demand during such high usage periods such as warmer than normal temperatures in
summer  months  and  to  replace  such  energy  repurchases by Hydro Quebec rose
substantially  after  the  market  opened to competitive bidding on May 1, 1999.
     Our  principal  service  territory  is  an  area  roughly 25 miles in width
extending  90  miles  across north central Vermont between Lake Champlain on the
west  and the Connecticut River on the east.  Included in this territory are the
cities  and  towns of Montpelier, Barre, South Burlington, Vergennes, Williston,
Shelburne,  and  Winooski, as well as the Village of Essex Junction and a number
of  smaller  communities.  We also distribute electricity in four separate areas
located  in  southern  and southeastern Vermont that are interconnected with our
principal  service area through the transmission lines of Vermont Electric Power
Company, Inc. ("VELCO") and others.  Included in these areas are the communities
of  Vernon  (where  the  Entergy nuclear plant is located), Bellows Falls, White
River Junction, Wilder, Wilmington and Dover.  The Company's right to distribute
electrical  service  in  its  service  territory is the utility's most important
asset.  We  supply  at  wholesale a portion of the power requirements of several
municipalities  and  cooperatives  in  Vermont.  We  are  obligated  to meet the
changing  electrical  requirements  of these wholesale customers, in contrast to
our  obligation  to  other  wholesale  customers,  which is limited to specified
amounts  of  capacity  and  energy  established  by  contract.
     Major  business  activities  in our service areas include computer assembly
and  components  manufacturing  (and  other electronics manufacturing), software
development,  granite  fabrication,  service  enterprises  such  as  government,
insurance,  regional  retail  shopping,  tourism  (particularly  fall and winter
recreation),  and  dairy  and  general  farming.

Operating  statistics  for  the  past  five years are presented in the following
table.

<TABLE>
<CAPTION>

GREEN  MOUNTAIN  POWER  CORPORATION
                        Operating Statistics               For the years ended December 31,

                                                      2,002        2001         2000         1999         1998
                                                   -----------  -----------  -----------  -----------  -----------
<S>                                                <C>          <C>          <C>          <C>          <C>
Total capability (MW) . . . . . . . . . . . . . .       406.9        408.0        411.1        393.2        396.9
Net system peak . . . . . . . . . . . . . . . . .       342.0        341.2        323.5        317.9        312.5
                                                   -----------  -----------  -----------  -----------  -----------
Reserve (MW). . . . . . . . . . . . . . . . . . .        64.9         66.8         87.6         75.3         84.4
                                                   ===========  ===========  ===========  ===========  ===========
Reserve % of peak . . . . . . . . . . . . . . . .        19.0%        19.6%        27.1%        23.7%        27.0%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . .     901,998      951,146    1,053,223    1,095,738      972,723
Wind. . . . . . . . . . . . . . . . . . . . . . .      11,458       12,135       12,246        7,956            -
Nuclear . . . . . . . . . . . . . . . . . . . . .     771,781      736,420      803,303      731,431      607,708
Conventional steam. . . . . . . . . . . . . . . .   2,431,115    2,670,249    2,704,427    2,328,267      750,602
Internal combustion . . . . . . . . . . . . . . .       4,090       18,291       35,699       12,312       40,148
Combined cycle. . . . . . . . . . . . . . . . . .      81,362       72,653       73,433       99,962      118,322
                                                   -----------  -----------  -----------  -----------  -----------
                    Total production. . . . . . .   4,201,804    4,460,894    4,682,331    4,275,666    2,489,503
Less non-firm sales to other utilities. . . . . .   2,104,172    2,365,809    2,573,576    2,152,781      499,409
                                                   -----------  -----------  -----------  -----------  -----------
Production for firm sales . . . . . . . . . . . .   2,097,632    2,095,085    2,108,755    2,122,885    1,990,094
Less firm sales and  lease transmissions. . . . .   1,951,959    1,956,232    1,954,898    1,920,257    1,883,959
                                                   -----------  -----------  -----------  -----------  -----------
Losses and company use (MWH). . . . . . . . . . .     145,673      138,853      153,857      202,628      106,134
                                                   ===========  ===========  ===========  ===========  ===========
Losses as a % of total production . . . . . . . .        3.47%        3.11%        3.29%        4.74%        4.26%
System load factor (***). . . . . . . . . . . . .        70.0%        70.1%        74.2%        76.2%        72.7%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . .        21.5%        21.3%        22.5%        25.6%        39.1%
Wind. . . . . . . . . . . . . . . . . . . . . . .         0.3%         0.3%         0.3%         0.2%         0.0%
Nuclear . . . . . . . . . . . . . . . . . . . . .        18.3%        16.5%        17.1%        17.1%        24.4%
Conventional steam. . . . . . . . . . . . . . . .        57.9%        59.9%        57.8%        54.5%        30.2%
Internal combustion . . . . . . . . . . . . . . .         0.1%         0.4%         0.8%         0.3%         1.6%
Combined cycle. . . . . . . . . . . . . . . . . .         1.9%         1.6%         1.6%         2.3%         4.8%
                                                   -----------  -----------  -----------  -----------  -----------
                  Total . . . . . . . . . . . . .       100.0%       100.0%       100.0%       100.0%       100.0%
                                                   ===========  ===========  ===========  ===========  ===========

Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . .     553,294      549,151      558,682      544,447      533,904
Commercial & industrial - small . . . . . . . . .     723,642      718,969      704,126      688,493      665,707
Commercial & industrial - large . . . . . . . . .     661,480      683,004      683,296      664,110      636,436
Other . . . . . . . . . . . . . . . . . . . . . .       9,773        2,030        6,713        3,138        3,476
                                                   -----------  -----------  -----------  -----------  -----------
Total retail sales and lease transmissions. . . .   1,948,189    1,953,154    1,952,817    1,900,188    1,839,522
Sales to Municipals & Cooperatives (Rate W) . . .       3,770        3,078        2,081       20,069       44,437
                                                   -----------  -----------  -----------  -----------  -----------
Total Requirements Sales. . . . . . . . . . . . .   1,951,959    1,956,232    1,954,898    1,920,257    1,883,959
Other Sales for Resale. . . . . . . . . . . . . .   2,104,172    2,365,809    2,573,576    2,152,781      499,409
                                                   -----------  -----------  -----------  -----------  -----------
Total sales and  lease transmissions(MWH) . . . .   4,056,131    4,322,041    4,528,474    4,073,038    2,383,368
                                                   ===========  ===========  ===========  ===========  ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . .      73,861       73,249       72,424       71,515       71,301
Commercial and industrial small . . . . . . . . .      13,173       12,984       12,746       12,438       12,170
Commercial and industrial large . . . . . . . . .          21           22           23           23           23
Other . . . . . . . . . . . . . . . . . . . . . .          65           65           65           66           70
                                                   -----------  -----------  -----------  -----------  -----------
             Total. . . . . . . . . . . . . . . .      87,120       86,320       85,258       84,042       83,564
                                                   ===========  ===========  ===========  ===========  ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . .       12.96        13.33        12.50        12.32        11.56
Commercial & industrial - small . . . . . . . . .       10.35        10.83        10.00         9.88         9.29
Commercial & industrial - large . . . . . . . . .        7.28         7.69         6.51         6.55         6.32
Total retail including lease. . . . . . . . . . .       10.09        10.44         9.52         9.47         8.96
                                                   ===========  ===========  ===========  ===========  ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . .       7,491        7,497        7,717        7,617        7,488
Revenues including lease revenues . . . . . . . .  $      971   $      999   $      965   $      938   $      865
</TABLE>


 (*)  MW  -  Megawatt  is  one  thousand  kilowatts.
(**)  MWH  -  Megawatt  hour  is  one  thousand  kilowatt  hours.
(***)  Load  factor  is  based  on  net system peak and firm MWH production less
off-system  losses.

STATE  AND  FEDERAL  REGULATION
     General.  The Company is subject to the regulatory authority of the Vermont
Public  Service  Board  ("VPSB"),  which  extends  to retail rates, services and
facilities,  securities  issues and various other matters.  The separate Vermont
Department  of Public Service (the "Department"), created by statute in 1981, is
responsible  for  development  of  energy supply plans for the State of Vermont,
purchases  of  power  as  an  agent  for  the State and other general regulatory
matters.  The VPSB principally conducts quasi-judicial proceedings, such as rate
setting.  The Department, through a Director for Public Advocacy, is entitled to
participate  as a litigant in such proceedings and regularly does so.  Political
or  social  organizations that represent certain classes of customers, neighbors
of  our  properties,  or  other  persons or entities may petition the VPSB to be
granted  intervener  status  in  such  proceedings.
     Our  rate tariffs are uniform throughout our service area.  We have entered
into  a  number  of  jobs  incentive  agreements, providing for reduced capacity
charges  to  large  customers  applicable only to new load.  We have an economic
development  agreement  with International Business Machines Corporation ("IBM")
that  provides  for contractually established charges, rather than tariff rates,
for incremental loads.  See Item 7. MD and A - Results of Operations - Operating
Revenues  and  MWh  Sales.
     Our  wholesale rate on sales to two wholesale customers is regulated by the
Federal  Energy  Regulatory  Commission  ("FERC").  Revenues from sales to these
customers  were  less  than  1.0  percent  of  our  operating revenues for 2002.
     We  provide transmission service to twelve customers within the State under
rates  regulated  by  the FERC; revenues for such services amounted to less than
1.0  percent  of  our  operating  revenues  for  2002.

     On  July  17,  1997, the FERC approved our Open Access Transmission Tariff,
and  on  August  30,  1997 we filed our compliance refund report.  In accordance
with  FERC Order 889, we have functionally separated our transmission operations
and  filed  with the FERC a code of conduct for our transmission operations.  We
do  not  anticipate  any material adverse effects or loss of wholesale customers
due  to  FERC  Order  889.  Our  Open  Access  tariff could reduce the amount of
capacity  available to the Company from such facilities in the future.  See Item
7.  MD  and  A  -  Transmission  Expenses.
     The  Company  has  equity  interests  in  Vermont Yankee, VELCO and Vermont
Electric  Transmission  Company,  Inc.  ("VETCO"),  a wholly owned subsidiary of
VELCO.  We have filed an exemption statement under Section 3(a)(2) of the Public
Utility  Holding  Company  Act  of  1935,  thereby  securing  exemption from the
provisions  of  such  Act,  except  for  Section  9(a)(2),  which  prohibits the
acquisition of securities of certain other utility companies without approval of
the  SEC.  The  SEC  has  the  power  to institute proceedings to terminate such
exemption  for  cause.

     Licensing.  Pursuant  to  the  Federal  Power  Act,  the  FERC  has granted
licenses  for  the  following  hydroelectric  projects  we  own:
<TABLE>
<CAPTION>


  Issue Date   Licensed Period
-------------  ---------------
<S>            <C>              <C>
Project Site:
Bolton. . . .  February 5,1982  February 5,1982 - February 4, 2022
Essex . . . .  March 30, 1995   March 1, 1995 - March 1, 2025
Vergennes . .  June 29, 1999    June 1, 1999 - May 31, 2029
Waterbury . .  July 20, 1954    expired August 31, 2001, renewal pending
</TABLE>



Major  project  licenses  provide  that  after  an initial twenty-year period, a
portion  of the earnings of such project in excess of a specified rate of return
is  to  be  set  aside in appropriated retained earnings in compliance with FERC
Order 5, issued in 1978.  Although the twenty-year periods expired in 1985, 1969
and  1971  in  the  cases  of  the  Essex,  Vergennes  and  Waterbury  projects,
respectively,  the  amounts  appropriated  are  not  material.
     The  relicensing  application  for Waterbury was filed in August 1999.  The
Waterbury reservoir was drained in 2001 to prepare for repairs to the dam by the
State,  presently  estimated for completion in 2004.  Once repairs are complete,
we expect the project to be relicensed for a 30 year term and we do not have any
competition  for  the  Waterbury  license.
     Department  of Public Service Twenty-Year Electric Plan.  In December 1994,
the Department adopted an update of its twenty-year electrical power-supply plan
(the  "Plan")  for the State.  The Plan includes an overview of statewide growth
and  development as they relate to future requirements for electrical energy; an
assessment  of  available  energy  resources; and estimates of future electrical
energy  demand.
     In  June  1996,  we  filed  with  the VPSB and the Department an integrated
resource  plan  pursuant  to  Vermont  Statute 30 V.S.A.   218c.  That filing is
still  pending  before  the  VPSB.
RECENT  RATE  DEVELOPMENTS
     RETAIL  RATE  CASES-  The Company reached a final settlement agreement with
the Department in its 1998 rate case during November 2000.  The final settlement
agreement  contained  the  following  provisions:

*     The Company received a rate increase of 3.42 percent above existing rates,
beginning  with  bills  rendered  January  23,  2001,  and  prior temporary rate
increases  became  permanent;
*     Rates  were  set  at  levels  that  recover the Company's Hydro Quebec VJO
contract  costs,  effectively ending the regulatory disallowances experienced by
the  Company  from  1998  through  2000;
*     The  Company  agreed  not  to  seek any further increase in electric rates
prior  to  April  2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a request
for  additional  rate  relief  if power supply costs increase in excess of $3.75
million  over  forecasted  levels;
*     The  Company  agreed  to  write  off in 2000 approximately $3.2 million in
unrecovered rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
*     Seasonal  rates  were  eliminated  in  April  2001,  which  generated
approximately  $8.5 million in additional cash flow in 2001 that can be utilized
to  offset  increased  costs  during  2002  and  2003;
*     The  Company  agreed  to consult extensively with the Department regarding
capital  spending commitments for upgrading our electric distribution system and
to  adopt  customer  care and reliability performance standards, in a first step
toward  possible  development  of  performance-based  rate-making;
*     The  Company  agreed  to  withdraw its Vermont Supreme Court appeal of the
VPSB's  Order  in  our  1997  rate  case;  and
*     The  Company  agreed to an earnings limitation for its electric operations
in  an amount equal to its allowed rate of return of 11.25 percent, with amounts
earned  over  the  limit  being  used  to  write  off  regulatory  assets.

     On  January 23, 2001, the VPSB approved our settlement with the Department,
with  two  additional  conditions:
*     The Company and customers shall share equally any premium above book value
realized by the Company in any future merger, acquisition or asset sale, subject
to  an  $8.0  million limit on the customers' share, adjusted for inflation; and
*     The  Company's further investment in non-utility operations is restricted.

     The Company earned approximately $4.4 million less than its allowed rate of
return  during  2002  before including in earnings deferred revenues in the same
amount.  The  Company earned approximately $30,000 in excess of its allowed rate
of  return  during 2001 before writing off regulatory assets in the same amount.
     For  further information regarding recent rate developments, see Item 7. MD
and  A  -  Rates,  and  Liquidity  and  Capital  Resources, and Note I of Notes.

SINGLE  CUSTOMER  DEPENDENCE
     The  Company  had  one major retail customer, IBM, metered at two locations
that  accounted  for  12.8  percent,  13.5  percent,  and  12.4 percent of total
operating  revenues,  and  17.3  percent,  19.2  percent and 16.5 percent of the
Company's retail operating revenues in 2002, 2001 and 2000, respectively.  IBM's
percent of total revenues and MWh sales in 2001 increased due to a rate increase
and  a  decrease  in total operating revenues as a result of decreased sales for
resale pursuant to the MS contract, which is discussed in greater detail in Item
7  of  MD  and A-Power Contract Commitments.  No other retail customer accounted
for  more  than  1.0  percent  of  our  revenue  during  the  past  three years.
     IBM  reduced  its  Vermont  workforce  by  1,500 during 2002, to a level of
approximately  7,000  employees.  If  future  significant  losses in electricity
sales  to IBM were to occur, the Company's earnings could be impacted adversely.
If  earnings were materially reduced as a result of lower retail sales, we would
seek  a  retail  rate  increase  from the VPSB.  The Company is not aware of any
plans by IBM to further reduce production at its Vermont facility.  We currently
estimate,  based  on  a  number of projected variables, the retail rate increase
required  from  all  retail  customers  by  a  hypothetical  shutdown of the IBM
facility  to  be  in  the  range  of five to ten percent, inclusive of projected
declines  in  sales to residential and commercial customers.  See Item 7. MD and
A-Results  of  Operations,  Operating  Revenues  and  MWh,  and Note A of Notes.

COMPETITION  AND  RESTRUCTURING
     Electric  utilities  historically  have  had  exclusive  franchises for the
retail  sale  of  electricity  in  specified  service  territories.  Legislative
authority  has  existed  since  1941 that would permit Vermont cities, towns and
villages  to own and operate public utilities.  Since that time, no municipality
served  by  the  Company  has  established  a  municipal  public  utility.
     During  2001,  the  Town  of  Rockingham  ("Rockingham"), Vermont initiated
inquiries and legal procedures to establish its own electric utility, seeking to
purchase  the  Bellows  Falls hydroelectric facility from a third party, and the
associated  distribution  plant  owned by the Company within the town.  In March
2002,  voters in Rockingham approved an article authorizing Rockingham to create
a  municipal utility by acting to acquire a municipal plant, which would include
the  electric  distribution systems of the Company and/or Central Vermont Public
Service Corporation.  The Company receives annual revenues of approximately $4.0
million  from its customers in Rockingham.  Should Rockingham create a municipal
system,  the  Company  would  vigorously  pursue  its  right  to  receive  just
compensation  from  Rockingham.  Such  compensation  would  include  full
reimbursement  for  Company  assets,  if acquired, and full reimbursement of any
other  costs associated with the loss of customers in Rockingham, to assure that
neither  our  remaining  customers  nor our shareholders effectively subsidize a
Rockingham  municipal  utility.
     In  1987,  the Vermont General Assembly enacted legislation that authorized
the  Department  to  sell electricity on a significantly expanded basis.  Before
the new law was passed, the Department's authority to make retail sales had been
limited  to  residential  and  farm customers and the Department could sell only
power  that it had purchased from the Niagara and St. Lawrence projects operated
by  the  New  York  Power  Authority.
     Under  the 1987 law, the Department can sell electricity purchased from any
source  at  retail  to all customer classes throughout the State, but only if it
convinces the VPSB and other State officials that the public good will be served
by  such  sales.  Since  1987, the Department has made limited additional retail
sales  of  electricity.  The Department retains its traditional responsibilities
of  public  advocacy  before  the  VPSB  and electricity planning on a statewide
basis.
     In  certain  states  across  the country, including the New England states,
legislation  has  been  enacted  to  allow  retail  customers  to  choose  their
electricity  suppliers,  with  incumbent  utilities  required  to  deliver  that
electricity  over  their  transmission  and  distribution  systems.  Increased
competitive pressure in the electric utility industry may restrict the Company's
ability  to  charge  energy prices sufficient to recover embedded costs, such as
the cost of purchased power obligations or of generation facilities owned by the
Company.  The  amount by which such costs might exceed market prices is commonly
referred  to  as  stranded  costs.
     Regulatory  and  legislative  authorities  at the federal level and in some
states,  including  Vermont  where  legislation  has  not  been  enacted,  are
considering  how  to  facilitate  competition  for electricity sales.  Alternate
forms  of performance-based regulation currently appear as possible intermediate
steps  towards  deregulation.  For further information regarding Competition and
Restructuring,  See  Item  7.  MD  and  A  -  Future  Outlook.



CONSTRUCTION  AND  CAPITAL  REQUIREMENTS
     Our  capital  expenditures for 2000 through 2002 and projected for 2003 are
set  forth  in  Item 7. MD and A - Liquidity and Capital Resources-Construction.
Construction  projections  are  subject  to continuing review and may be revised
from  time-to-time  in  accordance  with  changes  in  the  Company's  financial
condition,  load  forecasts,  the  availability and cost of labor and materials,
licensing  and  other  regulatory requirements, changing environmental standards
and  other  relevant  factors.
     For  the  period  2000-2002,  internally  generated funds, after payment of
dividends,  provided  approximately 68 percent of our total capital requirements
for  construction,  sinking fund obligations and other requirements.  Internally
generated  funds  provided  49  percent  of  such  requirements  for  2002.  We
anticipate  that for 2003, internally generated funds will provide approximately
71  percent  of  our  total  capital  requirements for regulated operations, the
remainder  to  be  derived  from  bank  loans.
     In  connection  with  the  foregoing,  see Item 7. MD and A - Liquidity and
Capital  Resources.

POWER  RESOURCES
     On  February  11,  1999,  the  Company  entered into a contract with Morgan
Stanley  Capital  Group,  Inc.  ("MS").  In  August  2002,  the  MS contract was
modified and extended to December 31, 2006.  The contract provides us a means of
managing  price  risks  associated  with  changing  fossil  fuel  prices.  For
additional  information  on  the  MS  contract,  see  Note  K  of  Notes.

     We  generated,  purchased or transmitted 2,210,721 MWh of energy for retail
and  requirements  wholesale  customers for the twelve months ended December 31,
2002.  The  corresponding  maximum one-hour integrated demand during that period
was 342.0 MW on August 15, 2002.  This compares to the previous all-time peak of
341.2  MW  on  August  9, 2001.  The following table shows the net generated and
purchased  energy, the source of such energy for the twelve-month period and the
capacity  in  the  month  of  the  period  system  peak.  See  Note  K of Notes.


<TABLE>
<CAPTION>

Net  Electricity  Generated  and  Purchased  and  Capacity  at  Peak
                             Generated and Purchased       Capacity
                                     During year          At time of
                                  Ended 12/31/2002      of annual peak
                                    MWH     percent     KW     percent
                                 ---------  --------  -------  --------
<S>                              <C>        <C>       <C>      <C>

Wholly-owned plants:
Hydro . . . . . . . . . . . . .    110,797      5.0%   32,870      8.9%
Diesel and Gas Turbine. . . . .      4,090      0.2%   50,623     13.6%
Wind. . . . . . . . . . . . . .     11,458      0.5%      480      0.1%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . .      3,687      0.2%    6,968      1.9%
Stony Brook I . . . . . . . . .     55,595      2.5%   27,113      7.3%
McNeil. . . . . . . . . . . . .     19,832      0.9%    6,443      1.7%
Long Term Purchases:
Vermont Yankee Nuclear/Entergy.    771,781     34.9%  100,554     27.1%

Hydro-Quebec. . . . . . . . . .    724,708     32.8%  114,174     30.8%
Stony Brook I . . . . . . . . .     25,767      1.2%   12,382      3.3%
Other:
Small Power Producers . . . . .    123,996      5.6%   19,286      5.2%
NEPOOL and Short-term purchases    359,009     16.2%      400      0.1%
                                 ---------  --------  -------  --------
Net Own Load. . . . . . . . . .  2,210,720    100.0%  371,293    100.0%
                                 =========  ========  =======  ========
</TABLE>


Vermont  Yankee.
     On  July  31,  2002, Vermont Yankee completed the sale of its nuclear power
plant to Entergy Nuclear Vermont Yankee ("Entergy").  In addition to the sale of
the  generating  plant,  the  transaction  calls  for Entergy, through its power
contract  with  VY,  to  provide  20  percent of the plant output to the Company
through  2012, which represents approximately 35 percent of our projected energy
requirements.  The  Company  continues  to  own  approximately 19 percent of the
common  stock  of  VY.  Our benefits of the plant sale and the VY power contract
with  Entergy  include:
     VY receives cash approximately equal to the book value of the plant assets,
removing  the  potential  for  stranded  costs  associated  with  the  plant.
     VY  and  its  owners  will  no  longer bear operating risks associated with
running  the  plant.
     VY  and  its  owners  will  no  longer  bear  the risks associated with the
eventual  decommissioning  of  the  plant.
     Prices  under  the  Power  Purchase  Agreement  between VY and Entergy (the
"PPA")  range from $39 to $45 per megawatt-hour for the period beginning January
2003,  substantially  lower  than the forecasted cost of continued ownership and
operation  by  VY.  Contract prices ranged from $49 to $55 for 2002, higher than
the  forecasted  cost  of  continued  ownership  for  2002.
     The  PPA  calls for a downward adjustment in the price if market prices for
electricity  fall  by defined amounts beginning no later than November 2005.  If
market  prices  rise,  however,  contract  prices  are  not  adjusted  upward.
The  Company  remains  responsible  for  procuring  replacement energy at market
prices  during periods of scheduled or unscheduled outages at the Entergy plant.
The  VY  plant had fuel rods that required repair during May 2002, a maintenance
requirement  that  is  not  unique  to VY.  VY closed the plant for a twelve-day
period, beginning on May 11, 2002, to repair the rods.  Our cost for the repair,
including  incremental replacement energy costs, was approximately $2.0 million.
The  Company  received  an  accounting  order  from  the VPSB on August 2, 2002,
allowing  it  to  defer the additional costs related to the outage, and believes
that  such  amounts  are  probable  of  future  recovery.
Our  ownership  share  of  VY has increased from approximately 17.9 percent last
year  to  approximately  19.0 percent currently, due to VY's purchase of certain
minority  shareholders'  interests.  VY's primary role consists of administering
its  power  supply  contract  with  Entergy  and its contracts with VY's present
sponsors.  Our  entitlement  to energy produced by the Entergy nuclear plant has
increased  from  approximately  18  percent  to  20  percent of plant production
through  a  series  of  transactions in connection with the sale of the plant to
Entergy.

     The  Company  and  Central Vermont Public Service Corporation acted as lead
sponsors  in  the  construction  of  the  Vermont  Yankee  Nuclear  Plant,  a
boiling-water  reactor  designed  by General Electric Company.  The plant, which
became  operational  in  1972,  has a generating capacity of 531 MW.     Vermont
Yankee has also entered into capital funds agreements with its sponsor utilities
that  expired  on December 31, 2002.  Under our Capital Funds Agreement, we were
required, subject to obtaining necessary regulatory approvals, to provide 20% of
the  capital  requirements  of Vermont Yankee not obtained from outside sources.

     During  periods  when  Vermont Yankee power is unavailable, we occasionally
incur  replacement  power  costs  in  excess  of  those costs that we would have
incurred  for  power  purchased  from  Vermont  Yankee.  Replacement  power  is
available  to  us  from  the ISO and through contractual arrangements with other
utilities.  Replacement  power  costs  adversely  affect  cash  flow and, absent
deferral,  amortization  and  recovery  through  rates,  would  adversely affect
reported  earnings.  In  the case of unscheduled outages of significant duration
resulting  in  substantial  unanticipated  costs for replacement power, the VPSB
generally  has  authorized  deferral,  amortization  and recovery of such costs.
     The  Entergy  nuclear plant's current operating license expires March 2012.
     During  the  year  ended  December 31, 2002, we used 771,781 MWh of Vermont
Yankee  energy  representing  34.9  percent of the net electricity generated and
purchased  ("net  power  supply")  by  the Company.  The average cost of Vermont
Yankee electricity in 2002 was $0.045 per kWh.  Vermont Yankee's annual capacity
factor  for  2002  was  88.7  percent  compared with 91.2 percent for 2001, 99.2
percent  in  2000,  and  90.9  percent  in  1999.
     See  Note  B  and  Note  K  of  Notes  for  additional  information.

Hydro  Quebec
     Highgate Interconnection.  On September 23, 1985, the Highgate transmission
facilities, which were constructed to import energy from Hydro Quebec in Canada,
began  commercial  operation.  The transmission facilities at Highgate include a
225-MW  AC-to-DC-to-AC converter terminal and seven miles of 345-kV transmission
line.  VELCO  built  and operates the converter facilities, which we own jointly
with  a  number  of  other  Vermont  utilities.

     NEPOOL/Hydro  Quebec  Interconnection.  VELCO  and  certain  other  NEPOOL
members  have  entered into agreements with Hydro Quebec, which provided for the
construction  in  two  phases  of  a direct interconnection between the electric
systems  in  New England and the electric system of Hydro Quebec in Canada.  The
Vermont  participants  in  this  project, which has a capacity of 2,000 MW, will
derive  about 9.0 percent of the total power-supply benefits associated with the
NEPOOL/Hydro  Quebec  interconnection.  The  Company,  in  turn,  receives
approximately one-third of the Vermont share of those benefits.  The benefits of
the  interconnection  include:
*     access  to  surplus  hydroelectric energy from Hydro Quebec at competitive
prices;
*     energy  banking,  under  which  participating  New  England utilities will
transmit  relatively  inexpensive energy to Hydro Quebec during off-peak periods
and  will  receive  equal  amounts  of energy, after adjustment for transmission
losses, from Hydro Quebec during peak periods when replacement costs are higher;
and
*     a  provision  for  emergency  transfers  and  mutual  backup  to  improve
reliability  for  both  the  Hydro  Quebec  system  and the New England systems.

     Phase  I.  The  first  phase  ("Phase  I")  of  the  NEPOOL/Hydro  Quebec
Interconnection  consists of transmission facilities having a capacity of 690 MW
that  traverse  a  portion of eastern Vermont and extend to a converter terminal
located  in  Comerford,  New  Hampshire.  These  facilities  entered  commercial
operation on October 1, 1986.  VETCO was organized to construct, own and operate
those  portions  of  the  transmission  facilities  located  in  Vermont.  Total
construction  costs  incurred  by  VETCO  for Phase I were $47,850,000.  Of that
amount,  VELCO  provided $10,000,000 of equity capital to VETCO through sales of
VELCO  preferred  stock to the Vermont participants in the project.  The Company
purchased  $3,100,000  of VELCO preferred stock to finance the equity portion of
Phase I.  The remaining $37,850,000 of construction cost was financed by VETCO's
issuance  of $37,000,000 of long-term debt in the fourth quarter of 1986 and the
balance  of  $850,000  was  financed  by  short-term  debt.
     Under  the  Phase  I contracts, each New England participant, including the
Company,  is  required  to  pay monthly its proportionate share of VETCO's total
cost  of  service,  including  its  capital costs.  Each participant also pays a
proportionate share of the total costs of service associated with those portions
of  the  transmission facilities constructed in New Hampshire by a subsidiary of
New  England  Electric  System.

     Phase  II.  Agreements  executed  in  1985  among the Company, VELCO, other
NEPOOL  members  and  Hydro  Quebec  provided for the construction of the second
phase  ("Phase  II")  of the interconnection between New England Electric System
and Hydro Quebec.  Phase II expanded the Phase I facilities from 690 MW to 2,000
MW,  and  provides  for  transmission  of  Hydro  Quebec  power from the Phase I
terminal  in  northern New Hampshire to Sandy Pond, Massachusetts.  Construction
of  Phase  II  commenced  in  1988 and was completed in late 1990.  The Phase II
facilities  commenced  commercial  operation  November  1,  1990, initially at a
rating  of  1,200 MW, and increased to a transfer capability of 2,000 MW in July
1991.  The  Hydro  Quebec-NEPOOL Firm Energy Contract provides for the import of
economical Hydro Quebec energy into New England.  The Company is entitled to 3.2
percent  of  the  Phase  II power-supply benefits.  Total construction costs for
Phase  II  were  approximately  $487,000,000.  The  New  England  participants,
including  the Company, have contracted to pay monthly their proportionate share
of the total cost of constructing, owning and operating the Phase II facilities,
including  capital  costs.  As  a  supporting participant, the Company must make
support  payments  under  30-year agreements.  These support agreements meet the
capital  lease accounting requirements under SFAS 13.  At December 31, 2002, the
present  value  of  the  Company's obligation was approximately $5,287,000.  The
Company's  projected  future  minimum  payments  under  the  Phase  II  support
agreements  are  approximately  $407,000  for each of the years 2003-2007 and an
aggregate  of  $3,253,000  for  the  years  2008-2015.
     The  Phase  II  portion  of  the  project  is  owned  by  New  England
Hydro-Transmission  Electric  Company,  Inc.  and New England Hydro-Transmission
Corporation,  subsidiaries  of  New England Electric System, in which certain of
the  Phase  II  participating  utilities,  including  the  Company,  own  equity
interests.  The  Company  owns  approximately  3.2  percent of the equity of the
corporations  owning  the Phase II facilities.  During construction of the Phase
II  project,  the  Company, as an equity sponsor, was required to provide equity
capital.  At  December  31, 2002, the capital structure of such corporations was
approximately  43 percent common equity and 57 percent long-term debt.  See Note
B  and  Note  J  of  Notes.
     At  times,  we  request  that  portions  of our power deliveries from Hydro
Quebec and other sources be routed through New York.  Our ability to do so could
be  adversely  affected  by  the  proposed tariff that NEPOOL has filed with the
FERC,  which  would reduce our allocation of capacity on transmission interfaces
with New York.  As a result, our ability to import power to Vermont from outside
New  England  could  be adversely affected, thereby impacting our power costs in
the  future.  See  Item  7.  MD  and  A  -  Transmission  Expenses.

     Hydro  Quebec  Power  Supply  Contracts.  We  have  several  power purchase
contracts  with  Hydro  Quebec.  The  bulk of our purchases are comprised of two
schedules,  B  and  C3,  pursuant to a Firm Contract dated December 1987.  Under
these two schedules, we purchase 114.2 MW. from Hydro Quebec.  In November 1996,
we  entered  into  a  Memorandum  of Understanding with Hydro Quebec under which
Hydro  Quebec  paid  $8,000,000  to  the  Company  in exchange for certain power
purchase options.  The exercise of these options in 2001 resulted in an increase
of  approximately  $7.6  million  of  power  supply expenses to meet contractual
obligations  under  the  Company's  December  1997  arrangement  (the  "9701
arrangement", or "9701") with Hydro Quebec.  See Item 7. MD and A - Power Supply
Expenses,  and  Note  K  of  Notes.
     During  2002,  we  used 432,171 MWh under Schedule B, and 292,537 MWh under
Schedule  C3  of  the Hydro Quebec arrangements representing 32.8 percent of our
net  power  supply.  The  average  cost  of Hydro Quebec electricity in 2002 was
approximately  $0.066  per  kWh.
     NEPOOL  and  Short-term  Opportunity  Purchases  and  Sales.  We  have
arrangements  with numerous utilities and power marketers actively trading power
in  New  England  and New York under which we purchase or sell of power on short
notice  and  generally  for brief periods of time when it appears economic to do
so.  Opportunity  purchases  are  arranged when it is possible to purchase power
for  less  than  it  would  cost  us to generate the power with our own sources.
Purchases  also  help us save on replacement power costs during an outage of one
of  our  base load sources.  Opportunity sales are arranged when we have surplus
energy  available at a price that is economic to other regional utilities at any
given  time.  The  sales are arranged based on forecasted costs of supplying the
incremental  power necessary to serve the sale.  Prices are set so as to recover
all  of the forecasted fuel or production costs and to recover some, if not all,
associated  capacity  costs.
     NEPOOL  is  the New England Power Pool whereby participants are able to buy
and  sell  wholesale  power,  through  the regional independent system operator,
known  as  ISO  New  England  for the New England region, to meet current demand
conditions  within  New  England's  transmission  system,  and  within  each
participant's  own  distribution  system.  The Company uses power purchased from
NEPOOL  and  other short-term opportunity market purchases to fulfill occasional
changes  in  the  demand  and supply matrix.  During 2002, the Company purchased
359,009  MWh  representing  16.2 percent of the Company's net power supply at an
average  cost  of  $0.05  per  kWh.

     Stony  Brook  I.  The  Massachusetts  Municipal  Wholesale Electric Company
("MMWEC")  is  principal  owner  and  operator  of  Stony  Brook,  a  352.0-MW
combined-cycle intermediate generating station located in Ludlow, Massachusetts,
which  commenced  commercial  operation  in  November 1981.  In October 1997, we
entered  into a Joint Ownership Agreement with MMWEC, whereby we acquired an 8.8
percent  ownership  share of the plant, entitling us to 31.0 MW of capacity.  In
addition to this entitlement, we have contracted for 14.2 MW of capacity for the
life  of the Stony Brook I plant, for which we will pay a proportionate share of
MMWEC's  share  of the plant's fixed costs and variable operating expenses.  The
three  units that comprise Stony Brook I are all capable of burning oil.  Two of
the  units  are  also capable of burning natural gas.  The natural gas system at
the  plant  was modified in 1985 to allow two units to operate simultaneously on
natural  gas.
     During 2002, we used 81,362 MWh from this plant representing 3.7 percent of
our  net power supply at an average cost of $0.06 per kWh.  See Note I of Notes.

     Wyman  Unit  #4.  The  W.  F.  Wyman Unit #4, which is located in Yarmouth,
Maine,  is  an  oil-fired  steam plant with a capacity of 620 MW.  Central Maine
Power  Company  sponsored  the  construction  of  this  plant.  We  have  a
joint-ownership  share of 1.1 percent (7.1 MW) in the Wyman #4 unit, which began
commercial  operation  in  December  1978.
     During  2002,  we used 3,687 MWh from this unit representing 0.2 percent of
our  net  power  supply  at  an  average  cost  of $0.091 per kWh, based only on
operation,  maintenance,  and  fuel  costs  incurred during 2002.  See Note I of
Notes.

     McNeil  Station.  The  J.C. McNeil station, which is located in Burlington,
Vermont,  is  a  wood chip and gas-fired steam plant with a capacity of 53.0 MW.
We  have  an  11.0  percent  or 5.8 MW interest in the J. C. McNeil plant, which
began  operation  in June 1984.  In 1989, the plant added the capability to burn
natural  gas  on  an  as-available/interruptible  service  basis.
     During  2002, we used 19,832 MWh from this unit representing 0.9 percent of
our  net  power  supply  at  an  average  cost  of $0.049 per kWh, based only on
operation,  maintenance,  and  fuel  costs  incurred during 2002.  See Note I of
Notes.

     Independent Power Producers.  The VPSB has adopted rules that implement for
Vermont  the  purchase  requirements  established  by  federal law in the Public
Utility  Regulatory Policies Act of 1978 ("PURPA").  Under the rules, qualifying
facilities  have  the  option to sell their output to a central state-purchasing
agent  under  a  variety  of  long-  and  short-term,  firm and non-firm pricing
schedules.  Each  of  these  schedules  is  based  upon  the  projected  Vermont
composite system's power costs that would be required but for the purchases from
independent  producers.  The  State  purchasing  agent  assigns  the  energy  so
purchased,  and  the  costs of purchase, to each Vermont retail electric utility
based  upon  its pro rata share of total Vermont retail energy sales.  Utilities
may  also  contract  directly  with  producers.  The  rules  provide  that  all
reasonable  costs  incurred by a utility under the rules will be included in the
utilities'  revenue  requirements  for  ratemaking  purposes.
     Currently,  the  State  purchasing agent, Vermont Electric Power Producers,
Inc. ("VEPPI"), is authorized to seek 150 MW of power from qualifying facilities
under  PURPA, of which our average pro rata share in 2002 was approximately 33.5
percent  or  50.2  MW.
     The  rated capacity of the qualifying facilities currently selling power to
VEPPI  is approximately 74.5 MW.  These facilities were all online by the spring
of  1993, and no other projects are under development.  We do not expect any new
projects to come online in the foreseeable future because excess capacity in the
region  has  eliminated  the  need  for  and  value  of  additional  qualifying
facilities.
     In  2002,  through our direct contracts and VEPPI, we purchased 123,996 MWh
of  qualifying  facilities  production representing 5.6 percent of our net power
supply  at  an  average  cost  of  $0.116  per  kWh.

     Company Hydroelectric Power.  We wholly own and operate eight hydroelectric
generating  facilities  located  on  river  systems within our service area, the
largest  of  which  has  a  generating  output  of  7.8  MW.
     In  2002,  Company  owned  hydroelectric  plants  provided  110,797  MWh of
pollution  free  energy,  representing 5.0 percent of our net power supply at an
average  cost  of  $0.043 per kWh based on total embedded costs and maintenance.
See  State  and  Federal  Regulation  -  Licensing.

     VELCO.  The  Company  and six other Vermont electric distribution utilities
own  VELCO.  Since commencing operation in 1958, VELCO has transmitted power for
its  owners in Vermont, including power from NYPA and other power contracted for
by Vermont utilities.  VELCO also purchases bulk power for resale at cost to its
owners,  and as a member of NEPOOL, represents all Vermont electric utilities in
pool  arrangements  and  transactions.  See  Note  B  of  Notes.

     Fuel.  During  2002,  our  retail  and  requirements  wholesale  sales were
provided  by  the  following  fuel  sources:
*     40.8  percent  from  hydroelectric sources (32.8 percent Hydro Quebec, 5.0
percent Company-owned, 2.9 percent small power producers, and 0.1 percent NYPA);
*     34.9 percent from a nuclear generating source (the Entergy nuclear plant);
*     3.6  percent  from  wood;
*     2.5  percent  from  natural  gas;
*     1.5  percent  from  oil;
*     0.5  percent  from  wind;  and
*     16.2  percent purchased on a short-term basis from other utilities through
the  ISO.

     We do not maintain long-term contracts for the supply of oil for our wholly
owned  oil-fired  peak  generating  stations  (80  MW).  We  did  not experience
difficulty  in  obtaining  oil  for  our  own units during 2002, however, we are
experiencing  some  difficulty  during 2003 as a result of extended cold weather
that  has affected fuel deliveriesNone of the utilities from which we expect to
purchase  oil- or gas-fired capacity in 2003 has advised us of grounds for doubt
about  maintenance  of  secure  sources  of  oil  and  gas  during  the  year.
     Wood  for  the  McNeil  plant  is  furnished  to  the  Burlington  Electric
Department  from  a  variety  of sources under short-term contracts ranging from
several  weeks'  to six months' duration.  The McNeil plant used 257,268 tons of
wood  chips  and  mill  residue,  54,827 gallons of fuel oil, and 37,869 million
cubic  feet  of  natural  gas  in  2002.  The  McNeil plant, assuming any needed
regulatory approvals are obtained, is forecasting 2003 consumption of wood chips
to  be  300,000  tons, fuel oil of 70,000 gallons and natural gas consumption of
36,000  million  cubic  feet.
     The  Stony  Brook  combined-cycle  generating station is capable of burning
either  natural  gas  or oil in two of its turbines.  Natural gas is supplied to
the  plant  subject  to  its  availability.  During  periods  of  extremely cold
weather,  the supplier reserves the right to discontinue deliveries to the plant
in  order  to  satisfy  the demand of its residential customers.  We assume, for
planning and budgeting purposes, that the plant will be supplied with gas during
the  months of April through November, and that it will run solely on oil during
the  months  of  December  through  March.  The  plant  maintains  an oil supply
sufficient  to  meet  approximately  one-half  of  its  annual  needs.
     Wind  Project. The Company was selected by the Department of Energy ("DOE")
and  the  Electric Power Research Institute ("EPRI") to build a commercial scale
wind-powered  facility.  The  DOE and EPRI provided partial funding for the wind
project  of  approximately  $3.9  million.  The  net  cost to the Company of the
project,  located  in  the southern Vermont town of Searsburg, was $7.8 million.
The  eleven  wind  turbines  have a rating of 6 MW and were commissioned July 1,
1997.
     In  2002,  the project provided pollution free 11,458 MWh, representing 0.5
percent  of  the  Company's  net  power supply at an approximate average cost of
$0.04  per  kWh,  based  only  on  maintenance  costs.


SEGMENT  INFORMATION
     Financial  information  about  the  Company's primary industry segment, the
electric  utility,  is  presented in Item 6, Selected Financial Data, and in the
Annual  Report  and  Notes  included  herein.
     The Company has sold or disposed of substantially all of the operations and
assets  of  Northern  Water  Resources, Inc. ("NWR"), formerly known as Mountain
Energy,  Inc.,  classified as discontinued operations in 1999.  Industry segment
information  relating  to  the Company's discontinued operations is presented in
Note  L  of  Notes.

SEASONAL  NATURE  OF  BUSINESS
      Winter recreational activities, longer hours of darkness and heating loads
from  cold  weather historically caused our average peak electric sales to occur
in  December, January or February.  Summer air conditioning loads have increased
in  recent years as a result of steady economic growth in our service territory.
As  a  result, our heaviest load in 2002, 342.0 MW, occurred on August 15, 2002.
     Under  NEPOOL market rules implemented in May 1999, the cost basis that had
supported  the  Company's  previous  seasonally  differentiated  rate design was
eliminated,  making  a  seasonal  rate  structure  no  longer  appropriate.  The
elimination  of  the seasonal rate structure in all classes of service effective
April  2001  was  approved  by  the  VPSB  in  January  2001.

EMPLOYEES
     As  of  December  31,  2002,  the  Company  had 194 employees, exclusive of
temporary  employees.  The  Company considers its relations with employees to be
excellent.

ENERGY  EFFICIENCY
     In  2002,  GMP  did  not  offer its own energy efficiency programs.  Energy
efficiency  services  were  provided  to  GMP's  customers by a statewide Energy
Efficiency Utility ("EEU") known as "Efficiency Vermont", created by the VPSB in
1999.  The  EEU is funded by a separate energy efficiency charge that appears as
a  line  item  on each customer bill.  In 2002, the charge was 2.0777 percent of
each  customer's  total  electric  bill.  Some  charges,  such  as late fees and
outdoor  lighting,  are  excluded. The funds we collect are remitted to a fiscal
agent  representing the State of Vermont.  From 1992 through 1999, the Company's
efficiency programs achieved a cumulative annual saving of 89,000 megawatthours,
saving  approximately  $7.9  million  per  year  for  our  customers.

RATE  DESIGN
     The  Company  seeks to design rates to encourage the shifting of electrical
use  from  peak  hours  to off-peak hours.  Since 1976, we have offered optional
time-of-use  rates  for  residential  and  commercial  customers.  Currently,
approximately 1,904 of the Company's residential customers continue to be billed
on  the  original  1976  time-of-use  rate basis.  In 1987, the Company received
regulatory  approval  for  a  rate design that permitted it to charge prices for
electric  service  that  reflected  as  accurately  as  possible the cost burden
imposed  by  each  customer  class.  The Company's rate design objectives are to
provide  a  stable  pricing  structure  and  to  accurately  reflect the cost of
providing  electric services.  This rate structure helps to achieve these goals.
Since  inefficient  use  of  electricity  increases  its cost, customers who are
charged  prices  that reflect the cost of providing electrical service have real
incentives  to follow the most efficient usage patterns.  Included in the VPSB's
order  approving  this  rate design was a requirement that the Company's largest
customers  be  charged  time-of-use  rates  on  a  phased-in  basis by 1994.  At
December  31,  2002,  approximately  1,657  of  the Company's largest customers,
comprising  52  percent  of  retail  revenues,  received  service  on  mandatory
time-of-use  rates.
     In  May 1994, the Company filed its current rate design with the VPSB.  The
parties,  including the Department, IBM and a low-income advocacy group, entered
into  a settlement that was approved by the VPSB on December 2, 1994.  Under the
settlement,  the  revenue  allocation to each rate class was adjusted to reflect
class-by-class  cost changes since 1987, the differential between the winter and
summer  rates  was  reduced, the customer charge was increased for most classes,
and  usage  charges were adjusted to be closer to the associated marginal costs.
     No  modifications  to  base  rate  redesign have taken place since the VPSB
Order  issued  on  December  2,  1994,  however,  as  previously noted, the VPSB
Settlement  Order  of  January  2001  eliminated  seasonal  rate  differentials
effective  April  2001.

DISPATCHABLE  AND  INTERRUPTIBLE  SERVICE  CONTRACTS
     In  2002,  we  had  27  dispatchable  power  contracts:  20  contracts were
year-round,  while  the  5 seasonal contracts included two major ski areas.  The
dispatchable  portion  of the contracts allows customers to purchase electricity
during  times  designated  by the Company when low cost power is available.  The
customer's  demand  during  these  periods  is not considered in calculating the
monthly  billing.  This program enables the Company and the customers to benefit
from  load  control.  We  shift  load  from  our  high cost peak periods and the
customer  uses  inexpensive power at a time when its use provides maximum value.
These  programs  are  available  by  tariff  for  qualifying  customers.

ENVIRONMENTAL  MATTERS
     We had been notified by the Environmental Protection Agency ("EPA") that we
were  one  of  several  potentially responsible parties for clean up at the Pine
Street  Barge  Canal  site  in  Burlington,  Vermont.  In  September  1999,  we
negotiated  a final settlement with the United States, the State of Vermont, and
other  parties  over  terms  of a Consent Decree that covers claims addressed in
earlier  negotiations  and  implementation  of  the selected remedy.  In October
1999,  the  federal  district  court  approved the Consent Decree that addresses
claims  by the EPA for past Pine Street Barge Canal site costs, natural resource
damage  claims  and  claims  for  past  and future oversight costs.  The Consent
Decree  also  provides  for the design and implementation of response actions at
the  site.  For information regarding the Pine Street Barge Canal site and other
environmental  matters,  see Item 7. MD and A- Environmental Matters, and Note I
of  Notes.

UNREGULATED  BUSINESSES
       In  1999,  Green  Mountain Resources, Inc. sold its remaining interest in
Green  Mountain  Energy  Resources.  During  1999,  the  Company  discontinued
operations of Northern Water Resources, Inc.("NWR"), a subsidiary of the Company
that invested in wastewater, energy efficiency and generation businesses.  NWR's
remaining  assets  include  an  interest  in  a  wind  generation  facility  in
California,  a  note  from  a  hydroelectric  facility  in  New Hampshire, and a
wastewater  businessin  the  process of completing dissolution.  For information
regarding  our  remaining  unregulated  businesses,  see  Item  7a.  MD  and A -
Unregulated  Businesses.

EXECUTIVE  OFFICERS

The names, ages, and positions of our Executive Officers, in alphabetical order,
as  of  March  15,  2003  are:

Christopher  L.  Dutton    54
     President  and  Chief  Executive Officer of the Company and Chairman of the
Executive  Committee  of the Company since August 1997.  Vice President, Finance
and  Administration,  Chief  Financial Officer and Treasurer from 1995 to August
1997.  Vice  President  and  General  Counsel  from  1993 to January 1995.  Vice
President,  General  Counsel  and  Corporate  Secretary  from  1989  to  1993.

Robert  J.  Griffin,  CPA       46
     Treasurer  since February 2002.  Controller since October 1996.  Manager of
General  Accounting  from  1990  to  1996.

Walter  S.  Oakes         56
     Vice  President-Field  Operations  since  August  1999.  Assistant  Vice
President-Customer  Operations  from  June  1994 to August 1999.  Assistant Vice
President,  Human  Resources  from  August  1993  to  June 1994.  Assistant Vice
President-Corporate  Services  from  1988  to  1993.

Mary  G.  Powell          42
     Senior  Vice  President-Chief  Operating  Officer since April 2001.  Senior
Vice  President-Customer  and  Organizational  Development  since December 1999.
Vice  President-Administration  from  February 1999 through December 1999.  Vice
President,  Human  Resources  and  Organizational Development from March 1998 to
February  1999.  Prior  to  joining  the  Company, she was President of HRworks,
Inc.,  a  human  resources  management  firm,  from  January 1997 to March 1998.

Donald  J.  Rendall,     47
     Vice  President,  General  Counsel and Corporate Secretary since July 2002,
March  2002,  and December 2002, respectively.  Prior to joining the Company, he
was a principal in the Burlington, Vermont law firm of Sheehey, Furlong, Rendall
&  Behm,  P.C.  from  1988  to  February  2002.

Stephen  C.  Terry       60
     Senior  Vice  President-Corporate  and  Legal  Relations since August 1999.
Senior  Vice  President,  Corporate Development from August 1997 to August 1999.
Vice  President  and General Manager, Retail Energy Services from 1995 to August
1997.  Vice  President-External  Affairs  from  1991  to  January  1995.

     Officers  are  elected  by  the  Board  of Directors of the Company and its
wholly  owned  subsidiaries, as appropriate, for one-year terms and serve at the
pleasure  of  such  boards  of  directors.
     Additional  information regarding compensation, beneficial ownership of the
Company's  stock,  members  of  the board of directors, and other information is
presented in the Company's Proxy Statement to Shareholders dated March 28, 2003,
and  is  hereby  incorporated  by  reference.

AVAILABLE  INFORMATION
     Our  Internet  website  address  is:  www.Greenmountainpower.biz.  We  make
available  free  of  charge  through the website our annual report on Form 10-K,
quarterly  reports  on  Form 10-Q, current reports on Form 8-K and amendments to
those  reports  filed  or  furnished  pursuant  to Section 13(a) or 15(d) of the
Securities  Exchange  Act of 1934, as amended, as soon as reasonably practicable
after  such  documents  are electronically filed with, or furnished to, the SEC.
The  information on our website is not, and shall not be deemed to be, a part of
this  report  or  incorporated  into  any  other  filings  we make with the SEC.

ITEM  2.  PROPERTY
GENERATING  FACILITIES
     Our  Vermont properties are located in five areas and are interconnected by
transmission  lines  of  VELCO and New England Power Company.  We wholly own and
operate eight hydroelectric generating stations with a total nameplate rating of
36.1  MW  and  an  estimated  claimed  capability  of  35.7 MW.  We also own two
gas-turbine  generating  stations  with an aggregate nameplate rating of 59.9 MW
and  an  estimated  aggregate claimed capability of 73.2 MW.  We have two diesel
generating  stations  with  an  aggregate  nameplate  rating  of  8.0  MW and an
estimated  aggregate  claimed  capability  of  8.6  MW.  We  also  have  a  wind
generating  facility  with  a  nameplate  rating  of  6.1  MW.
     We  also  own:
*     18.99  percent  of  the  outstanding  common  stock of Vermont Yankee and,
through  its contract with Entergy, we are entitled to 20.0 percent (106.2 MW of
a  total  531  MW)  of the capacity of the Entergy Nuclear Vermont Yankee plant,
*     1.1  percent (7.1 MW of a total 620 MW) joint-ownership share of the Wyman
#4  plant  located  in  Maine,
*     8.8 percent (31.0 MW of a total 352 MW) joint-ownership share of the Stony
Brook  I  intermediate  units  located  in  Massachusetts,  and
*     11.0  percent  (5.8 MW of a total 53 MW) joint-ownership share of the J.C.
McNeil  wood-fired  steam  plant  located  in  Burlington,  Vermont.
See  Item  1.  Business  -  Power  Resources  for  plant  details  and the table
hereinafter  set  forth  for  generating  facilities  presently  available.

TRANSMISSION  AND  DISTRIBUTION
      The  Company  had,  at  December 31, 2002, approximately 2 miles of 115 kV
transmission  lines,  10  miles  of  69  kV transmission lines, 5 miles of 44 kV
transmission lines, 187 miles of 34.5 kV transmission lines, and 2 miles of 13.8
kV  transmission  lines.  Our  distribution  system included approximately 2,340
miles  of overhead lines of 2.4 to 34.5 kV and 455 miles of underground cable of
2.4  to  34.5 kV.  At such date, we owned approximately 115,000 kV of substation
transformer  capacity  in  transmission substations and 590,000 kV of substation
transformer capacity in distribution substations and approximately 872,000 kV of
transformers  for  step-down  from  distribution  to  customer  use.
     The  Company  owns  34.8  percent of the Highgate transmission inter-tie, a
225-MW converter and transmission line used to transmit power from Hydro Quebec.
     We  also  own  28.4  percent  of  the  common  stock  and 30 percent of the
preferred  stock  of  VELCO,  which  operates a high-voltage transmission system
interconnecting  electric  utilities  in  the  State  of  Vermont.

PROPERTY  OWNERSHIP
     Our  wholly  owned  plants  are located on lands that we own in fee.  Water
power and floodage rights are controlled through ownership of the necessary land
in  fee  or  under  easements.
     Transmission  and  distribution  facilities that are not located in or over
public  highways are, with minor exceptions, located either on land owned in fee
or  pursuant  to  easements  which,  in  nearly  all  cases,  are  perpetual.
Transmission  and  distribution  lines located in or over public highways are so
located  pursuant to authority conferred on public utilities by statute, subject
to  regulation  by  state  or  municipal  authorities.

INDENTURE  OF  FIRST  MORTGAGE
     The  Company's  interests  in  substantially  all  of  its  properties  and
franchises  are  subject to the lien of the mortgage securing its First Mortgage
Bonds.  See  Note  F,  Long-Term Debt, for more information concerning our First
Mortgage  Bonds.

GENERATING  FACILITIES  OWNED
      The  following  table  gives  information  with  respect  to  generating
facilities  presently  available in which the Company has an ownership interest.
See  also  Item  1.  Business  -  Power  Resources.
<TABLE>
<CAPTION>

                                                                     Winter
                                                                   Capability
                            Location           Name          Fuel     MW
                         ---------------  ---------------  --------  -----
<S>                      <C>              <C>              <C>       <C>    <C>
Wholly Owned
Hydro . . . . . . . . .  Middlesex, VT    Middlesex #2     Hydro      3.3
Hydro . . . . . . . . .  Marshfield, VT   Marshfield #6    Hydro      4.9
Hydro . . . . . . . . .  Vergennes, VT    Vergennes #9     Hydro      2.1
Hydro . . . . . . . . .  W. Danville, VT  W. Danville #15  Hydro      1.1
Hydro . . . . . . . . .  Colchester, VT   Gorge #18        Hydro      3.3
Hydro . . . . . . . . .  Essex Jct., VT   Essex #19        Hydro      7.8
Hydro . . . . . . . . .  Waterbury, VT    Waterbury #22    Hydro      5.0   (1)
Hydro . . . . . . . . .  Bolton, VT       DeForge #1       Hydro      7.8
Diesel. . . . . . . . .  Vergennes, VT    Vergennes #9     Oil        4.2
Diesel. . . . . . . . .  Essex Jct., VT   Essex #19        Oil        4.4
Gas . . . . . . . . . .  Berlin, VT       Berlin #5        Oil       56.6
Turbine . . . . . . . .  Colchester, VT   Gorge #16        Oil       16.1
Wind. . . . . . . . . .  Searsburg, VT    Searsburg        Wind       1.2
Jointly Owned
Steam . . . . . . . . .  Yarmouth, ME     Wyman #4         Oil        7.1
Steam . . . . . . . . .  Burlington, VT   McNeil           Wood/Gas   6.6   (3)
Combined. . . . . . . .  Ludlow, MA       Stony Brook #1   Oil/Gas   31.0   (2)
Total Winter Capability                                              162.5
                                                                   ========
</TABLE>

(1)   Reservoir  has been drained, dam awaiting repairs by the State of Vermont.
(2)  For  a  discussion  of  the  impact  of  various  power supply sales on the
availability  of  generating facilities, see Item 1. Business - Power Resources.
(3)   The  Company's entitlement in McNeil is 5.8 MW.  However, we receive up to
6.6  MW  as  a  result  of  other  owners'  losses  on  this  system.

CORPORATE  HEADQUARTERS
     Our headquarters and main service center are located in Colchester Vermont,
one  of  the  most  rapidly growing areas of our service territory.  The Company
terminated an operating lease for its former corporate headquarters building and
two  of its service center buildings in the first quarter of 1999.  During 1998,
the  Company  recorded  a  loss  of approximately $1.9 million before applicable
income  taxes to reflect the probable loss resulting from this transaction.  The
Company sold its corporate headquarters building in 1999, but retained ownership
of  its  two  service  centers.

ITEM  3.  LEGAL  PROCEEDINGS
     The Company is not involved in any material litigation at the present time.
See  the  discussion  under Item 7. MD and A - Environmental Matters, Rates, and
Note  I  of  Notes.

ITEM  4.  SUBMISSION  OF  MATTERS  TO  A  VOTE  OF  SECURITY  HOLDERS.
     None.





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

     Outstanding  shares  of  our  Common Stock are listed and traded on the New
York  Stock  Exchange  under the symbol GMP.  The following tabulation shows the
high  and  low  sales prices for the Common Stock on the New York Stock Exchange
during  2001  and  2002:
<TABLE>
<CAPTION>
                 HIGH    LOW
                ------  ------
<S>             <C>     <C>
                  2001
First Quarter.  $19.50  $11.06
Second Quarter   16.65   14.88
Third Quarter.   17.74   15.56
Fourth Quarter   18.85   15.90
                  2002
First Quarter.  $19.00  $17.00
Second Quarter   19.50   17.54
Third Quarter.   18.25   15.75
Fourth Quarter   21.08   15.89
</TABLE>

The  number  of  common  stockholders  of  record  as  of  March  12,  2003  was
approximately  5,190.
     Quarterly  cash  dividends  were paid as follows during the past two years:
<TABLE>
<CAPTION>


       First     Second    Third     Fourth
      Quarter   Quarter   Quarter   Quarter
      --------  --------  --------  --------
<S>   <C>       <C>       <C>       <C>
2001  $ 0.1375  $ 0.1375  $ 0.1375  $ 0.1375
2002  $ 0.1375  $ 0.1375  $ 0.1375  $ 0.1900
</TABLE>
     Dividend  Policy.  The  annual  dividend  rate was increased from $0.55 per
share to $0.76 per share beginning with the $0.19 quarterly dividend declared in
December  2002.  The  Company  intends  to  increase  the dividend in a measured
consistent manner until the payout ratio falls between 50 percent and 60 percent
of  anticipated  earnings.  We  believe  this payout ratio to be consistent with
that  of  other  utilities  having  similar  risk  profiles.
     Our current dividend policy reflects changes affecting the electric utility
industry,  which,  in  other  jurisdictions, is moving away from the traditional
cost-of-service regulatory model to a competition based market for power supply.

     Historically,  we  based  our  dividend policy on the continued validity of
three  assumptions:  the  ability  to achieve earnings growth; the receipt of an
allowed  rate  of  return  that accurately reflects our cost of capital; and the
retention  of  our exclusive franchise.  Our Board of Directors will continue to
assess  and  adjust  the  dividend,  when  appropriate,  as the Vermont electric
industry  evolves  towards competition.  In addition, if other events beyond our
control  cause  the  Company's  financial situation to deteriorate, the Board of
Directors would consider whether the current dividend level is appropriate.  See
Item  7.  MD  and  A  -  Liquidity and Capital Resources-Dividend Policy, Future
Outlook,  Competition and Restructuring, and Note C of Notes for a discussion of
dividend  restrictions.
42
<TABLE>
<CAPTION>

     ITEM  6.   SELECTED  FINANCIAL  DATA

     RESULTS  OF  OPERATIONS  FOR  THE  YEARS  ENDED  DECEMBER  31,
     --------------------------------------------------------------


                                                                          2002       2001       2000       1999       1998
                                                                        ---------  ---------  ---------  ---------  ---------
In thousands, except per share data
<S>                                                                     <C>        <C>        <C>        <C>        <C>
  Operating Revenues . . . . . . . . . . . . . . . . . . . . . . . . .  $274,608   $283,464   $277,326   $251,048   $184,304
  Operating Expenses . . . . . . . . . . . . . . . . . . . . . . . . .   259,528    267,005    272,066    243,102    178,832
                                                                                   ---------  ---------  ---------  ---------
        Operating Income . . . . . . . . . . . . . . . . . . . . . . .    15,080     16,459      5,260      7,946      5,472
                                                                        ---------  ---------  ---------  ---------  ---------
  Other Income
        AFUDC - equity . . . . . . . . . . . . . . . . . . . . . . . .       233        210        284        134        104
        Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . .     2,252      2,163      2,422      3,319      1,509
        Total other income . . . . . . . . . . . . . . . . . . . . . .     2,485      2,373      2,706      3,453      1,613
                                                                        ---------  ---------  ---------  ---------  ---------
  Interest Charges
        AFUDC - borrowed . . . . . . . . . . . . . . . . . . . . . . .      (103)      (188)      (228)       (91)      (131)
        Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . .     6,273      7,227      7,485      7,274      8,007
            Total interest charges . . . . . . . . . . . . . . . . . .     6,170      7,039      7,257      7,183      7,876
                                                                        ---------  ---------  ---------  ---------  ---------
  Net Income (Loss) from continuing operations before. . . . . . . . .    11,395     11,793        709      4,216       (791)
     preferred dividends
  Net Income (Loss) from discontinued operations, including
     provisions for loss on disposal . . . . . . . . . . . . . . . . .        99       (182)    (6,549)    (7,279)    (2,086)
  Dividends on Preferred Stock . . . . . . . . . . . . . . . . . . . .        96        933      1,014      1,155      1,296
                                                                        ---------  ---------  ---------  ---------  ---------
  Net Income (Loss)Applicable
        to Common Stock. . . . . . . . . . . . . . . . . . . . . . . .  $ 11,398   $ 10,678   $ (6,854)  $ (4,218)  $ (4,173)
                                                                        =========  =========  =========  =========  =========
  Common Stock Data
        Basic earnings per share-continuing operations . . . . . . . .  $   2.02   $   1.93   $  (0.06)  $   0.57   $  (0.40)
        Basic earnings per share-discontinued operations . . . . . . .      0.02      (0.03)     (1.19)     (1.36)     (0.40)
                                                                                   ---------  ---------  ---------  ---------
        Basic earnings per share . . . . . . . . . . . . . . . . . . .  $   2.04   $   1.90   $  (1.25)  $  (0.79)  $  (0.80)
                                                                        =========  =========  =========  =========  =========
        Diluted earnings (loss) per share from discontinued operations  $   1.96   $   1.88   $  (0.06)  $   0.57   $  (0.40)
        Diluted earnings (loss) per share from continuing operations .      0.02      (0.03)     (1.19)     (1.36)     (0.40)
        Diluted earnings (loss) per share. . . . . . . . . . . . . . .  $   1.98   $   1.85   $  (1.25)  $   0.79   $  (0.80)
                                                                        =========  =========  =========  =========  =========
  Cash dividends declared per share. . . . . . . . . . . . . . . . . .  $   0.60   $   0.55   $   0.55   $   0.55   $   0.96
        Weighted average shares outstanding-basic. . . . . . . . . . .     5,592      5,592      5,630      5,491      5,243
        Weighted average share equivalents outstanding-diluted . . . .     5,756      5,756      5,789      5,491      5,243
</TABLE>


<TABLE>
<CAPTION>

     FINANCIAL  CONDITION  AS  OF  DECEMBER  31
     ------------------------------------------

                                             2002      2001      2000      1999      1998
                                           --------  --------  --------  --------  --------
In thousands
<S>                                        <C>       <C>       <C>       <C>       <C>
  ASSETS
  Utility Plant, Net. . . . . . . . . . .  $203,529  $196,858  $194,672  $192,896  $195,556
  Other Investments . . . . . . . . . . .    21,552    20,945    20,730    20,665    20,678
  Current Assets. . . . . . . . . . . . .    31,432    36,183    53,652    33,238    35,700
  Deferred Charges. . . . . . . . . . . .    51,594    72,468    46,036    41,853    35,576
  Non-Utility Assets. . . . . . . . . . .       995     1,075     1,518    11,099    27,314
  Total Assets. . . . . . . . . . . . . .  $309,102  $327,529  $316,608  $299,751  $314,824
                                           ========  ========  ========  ========  ========

  CAPITALIZATION AND LIABILITIES
  Common Stock Equity . . . . . . . . . .  $ 91,722  $101,277  $ 92,044  $100,645  $106,755
  Redeemable Cumulative Preferred Stock .        55    12,560    12,795    14,435    16,085
  Long-Term Debt, Less Current Maturities    93,000    74,400    72,100    81,800    88,500
  Capital Lease Obligation. . . . . . . .     5,287     5,959     6,449     7,038     7,696
  Current Liabilities . . . . . . . . . .    38,491    38,841    68,109    36,708    28,825
  Deferred Credits and Other. . . . . . .    78,606    92,791    61,794    59,125    59,889
  Non-Utility Liabilities . . . . . . . .     1,941     1,701     3,317         -     7,074
  Total Capitalization and Liabilities. .  $309,102  $327,529  $316,608  $299,751  $314,824
                                           ========  ========  ========  ========  ========
</TABLE>
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF  OPERATIONS.
     In this section, we explain the general financial condition and the results
of  operations  for  Green  Mountain  Power  Corporation (the "Company") and its
subsidiaries.  This  explanation  includes:
*     factors  that  affect  our  business;
*     our  earnings  and  costs  in  the  periods presented and why they changed
between  periods;
*     the  source  of  our  earnings;
*     our  expenditures  for capital projects and what we expect they will be in
the  future;
*     where  we  expect  to  get  cash  for  future  capital  expenditures;  and
*     how  all  of  the  above  affects  our  overall  financial  condition.

     Our  critical  accounting  policies are discussed in Item 7a, "Quantitative
And  Qualitative  Disclosures About Market Risk, And Other Factors", and in Item
8,  Note  1,  "Significant  Accounting  Policies".  Management believes the most
critical  accounting  policies  include  the  timing  of  expense  and  revenue
recognition  under  the  regulatory accounting framework within which we operate
and  the  manner  in which we account for certain power supply arrangements that
qualify  as  derivatives.  These  accounting  policies, among others, affect the
Company's  more  significant  judgments and estimates used in the preparation of
its  consolidated  financial  statements.

     There  are statements in this section that contain projections or estimates
and that are considered to be "forward-looking" as defined by the Securities and
Exchange  Commission  (the "SEC").  In these statements, you may find words such
as  believes,  expects,  plans,  or  similar  words.  These  statements  are not
guarantees  of our future performance.  There are risks, uncertainties and other
factors  that  could  cause actual results to be different from those projected.
Some  of  the  reasons  the  results  may  be  different are discussed under the
captions  "Power  Contract  Commitments",  "Future  Outlook,"  "Transmission
Expenses,"  "Environmental  Matters,"  "Rates,  "and  "Liquidity  and  Capital
Resources,"  in  this  Management  Discussion  and  Analysis  and  include:
*     regulatory  and  judicial  decisions  or  legislation;
*     weather;
*     changes  in  regional  market  and  transmission  rules;
*     energy  supply  and  demand  and  pricing;
*     contractual  commitments;
*     availability,  terms,  and  use  of  capital;
*     general  economic  and  business  environment;
*     changes  in  technology;
*     nuclear  and  environmental  issues;  and
*     industry  restructuring  and  cost  recovery  (including  stranded costs).

     These  forward-looking  statements  represent our estimates and assumptions
only  as  of  the  date  of  this  report.

EARNINGS  SUMMARY
     The  Company  reported  consolidated  earnings of $1.98 per share of common
stock,  diluted,  in 2002, compared to earnings of $1.85 per share in 2001 and a
loss  of  $1.25  per  share in 2000.  The 2002 earnings represent a consolidated
return  on  average  common  equity  of 11.03 percent, and a return on regulated
operations  of  11.25 percent.  The consolidated return on average common equity
was  11.02  percent  in  2001  and  negative  7.1  percent in 2000.  Income from
continuing operations was $1.96 per share, diluted, in 2002, compared with $1.88
per  share,  diluted,  in  2001,  and  a  loss  of $0.06 per share in 2000.  The
Company's  subsidiary  Northern  Water  Resources,  Inc.  ("NWR"), classified as
discontinued  in  1999,  earned  $0.02 per share in 2002 compared with a loss of
$0.03  per  share in 2001, and a loss of $1.19 per share in 2000.  A significant
portion  of  NWR's  assets,  which consisted of energy generation and efficiency
investments  and  wastewater  treatment  projects,  have been sold, or otherwise
disposed.  NWR's  2002  earnings  resulted  primarily  from  an  adjustment to a
reserve  for  warranty  claims.
On  January  23, 2001, the Vermont Public Service Board ("VPSB") issued an order
(the  "Settlement  Order")  approving  a  settlement between the Company and the
Vermont Department of Public Service (the "Department") that granted the Company
an  immediate  3.42  percent  rate  increase, and allowed full recovery of power
supply  costs  under  the Hydro Quebec Vermont Joint Owners ("VJO") contract(the
"VJO  Contract").  The  Settlement  Order  paved  the way for restoration of the
Company's  first  mortgage bond credit rating to investment grade status in 2001
(See  "Rates-Retail  Rate  Cases"  and "Liquidity and Capital Resources" in this
section)  and  enabled  the  Company to earn its allowed rate of return of 11.25
percent  on  regulated  operations  during  2002  and  2001.
 The  improvement  in  earnings from continuing operations in 2002 compared with
2001  resulted  from  reductions  in  the  Company's  cost  of capital and other
operating  expenses,  partially  offset  by  increases  in  maintenance  and
transmission  expenses  and  lower  gross margins on the Company's sales.  Lower
capital  costs  resulted  from  reduced  interest rates and average debt levels,
which  caused 2002 interest expense to decline by $0.9 million compared to 2001,
and  the  redemption  of  preferred  stock  which  reduced  2002 preferred stock
dividends $0.8 million compared with 2001.  Lower gross margins resulted from an
increase  in  power  supply  costs  to  serve  retail  customers,  that was only
partially  offset  by  recognition  of  $4.4 million in revenue deferred in 2001
under  the  Settlement  Order.
     The  improvement  in  earnings from continuing operations in 2001, compared
with  2000,  resulted  primarily  from  several  factors,  including:
*     2001  power  supply  costs  were  $10.5  million  lower  than during 2000,
principally  due  to  decreased  costs  associated  with  the  management of the
Company's  long-term  power  supply  sale  commitments  to  Hydro  Quebec, and a
decrease  in  lower  margin  wholesale  sales  of  electricity;
*     the  3.42 percent retail rate increase under the Settlement Order resulted
in  an  increase  of  $9.1  million  in  2001  retail  operating  revenues;  and
*     the  write-off  in 2000 of $3.2 million, or $0.35 per share, in regulatory
litigation  costs.


ITEM  7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, AND OTHER
RISK  FACTORS.
POWER  SUPPLY  RISK.
     Our  material  power supply contracts and arrangements are principally with
Hydro  Quebec, MS and Vermont Yankee Nuclear Power Corporation.  At December 31,
2002,  more  than 90 percent of our estimated load requirements through 2006 are
expected  to  be  met  by  these  contracts  and  arrangements,  and  by our own
generation  and  other  power  supply  resources,  which  reduces  the Company's
exposure  to  market  prices.
     A  primary  factor  affecting future operating results is the volatility of
the  wholesale  electricity  market.  Restructuring  of the wholesale market for
electricity  has brought increased price volatility to our power supply markets.
Inherent  in  our  market  risk  sensitive  instruments  and  positions  are the
potential  losses  that may result from adverse changes in our commodity prices.

     One objective of the Company's risk management program is to stabilize cash
flow  and  earnings by minimizing power supply risks.  Transactions permitted by
the  risk  management  program  include  futures,  forward  contracts,  option
contracts,  swaps  and  transmission congestion rights with counter-parties that
have  at  least  investment grade ratings.  These transactions are used to hedge
the  risk  of  fossil  fuel  and  spot  market electricity price increases.  The
Company's  risk  management  policy  specifies  risk  measures,  the  amount  of
tolerable  risk  exposure,  and  authorization  limits  for  transactions.
     The  Company has a contract with Morgan Stanley Capital Group, Inc. ("MS"),
which  is  used  to hedge against increases in fossil fuel prices.  MS purchases
the  majority of the Company's power supply resources at index prices for fossil
fuel resources or specified prices for contracted resources and then sells to us
at  a  fixed  rate  to  serve pre-established load requirements.  This contract,
along with other power supply commitments, allows the Company to fix the cost of
much  of  its  power supply requirements, subject to power resource availability
and  other  risks.  The MS contract is a derivative under Statement of Financial
Accounting  Standards No. 133 ("SFAS 133") and is effective through December 31,
2006.  Management's estimate of the fair value of the future net benefit of this
arrangement  at  December  31,  2002 is approximately $8.8 million.  Assumptions
used to calculate the future net benefit using the Blacks option valuation model
include  a  risk-free  interest  rate of 3.4 percent, volatility equivalent to a
weighted  average from NEPOOL, which varies from 32 percent in the first year to
29  percent  in  the  fourth year, locked in forward commitment prices for 2003,
with  an estimated forward market price of approximately $43 per MWh for periods
beyond 2003.  The forward price for electricity is consistent with the Company's
current  long-term  wholesale  energy price forecast.  Actual results may differ
materially  from  the  table  below.
       We  currently  have  an  arrangement  that  grants Hydro Quebec an option
("9701")  to call power at prices that are expected to be below estimated future
market  rates.  This  arrangement is a derivative and is effective through 2015.
Management's  estimate  of  the  fair  value  of  the  future  net cost for this
arrangement  at  December 31, 2002 is approximately $27.2 million.  We sometimes
use  futures  contracts  to hedge forecasted sales of electric power under 9701.
     A sensitivity analysis has been prepared to estimate exposure to the market
price  risk  of  9701,  using  the  Black-Scholes model, over the next 13 years.
Assumptions  used  within  the  model  include a risk-free interest rate of 5.02
percent, volatility equivalent to the weighted average from NEPOOL, which varies
from  48  percent  in the first year to 26 percent in year 13, locked in forward
commitment prices for 2003, and an average of approximately 59,326 MWh per year,
with  an  estimated  forward  market  price of $59.81 per MWh for periods beyond
2003.  The  forward  price  for  electricity  is  consistent  with the Company's
current long-term wholesale energy price forecast.  Quoted forward market prices
for monthly peak power rates are not currently available beyond 2004.  The table
below  presents  market  risk  estimated  as  the  potential  loss in fair value
resulting  from  a  hypothetical ten percent adverse change in prices, which for
the  Company's  derivatives  discussed  above totals approximately $0.9 million.
Actual  results may differ materially from the table below.  Under an accounting
order  issued  by  the  VPSB,  changes  in the fair value of derivatives are not
recognized  in  earnings  until  the  derivative  positions  are  settled.
<TABLE>
<CAPTION>

             Commodity Price Risk               At December 31, 2002

                      Fair Value     Market Risk
                    ---------------  ------------
                    (in thousands)
<S>                 <C>              <C>
Net short position  $        18,405  $        880
</TABLE>
REGULATORY  RISK-     There  are  currently  no  regulatory  proceedings,  court
actions  or  pending  legislative  proposals  to  adopt  electric  industry
restructuring  in  Vermont.  However, if Vermont adopted such restructuring, the
major  risk  factors  for  the  Company  that  may  arise from electric industry
restructuring,  including  risks  pertaining  to the recovery of stranded costs,
are:
*     regulatory  and  legal  decisions;
*     cost  and  amount  of  default  service  responsibility;
*     the  market  price  of  power;  and
*     the  amount  of  market  share  retained  by  the  Company.

     There  can  be  no  assurance  that any potential future restructuring plan
ordered by the VPSB, the courts, or through legislation will include a mechanism
that  would  allow  for  full  recovery of our stranded costs and include a fair
return  on  those  costs  as  they  are being recovered.  If laws are enacted or
regulatory  decisions  are  made  that  do  not offer an adequate opportunity to
recover  stranded  costs,  we  believe  we  have  compelling  legal arguments to
challenge  such  laws  or  decisions.
     The  largest category of our potential stranded costs is future costs under
long-term  power  purchase  contracts,  which,  based  on current forecasts, are
above-market.  The magnitude of our stranded costs is largely dependent upon the
future  market price of power.  We have discussed various market price scenarios
with  interested  parties  for  the  purpose  of  identifying  stranded  costs.
Preliminary  market price assumptions, which are likely to change, have resulted
in  estimates  by  the Company of its stranded costs of between $203 million and
$224  million  over  the  life  of  the  contracts.     If retail competition is
implemented  in  Vermont,  we  cannot  predict  what  the impact would be on the
Company's  revenues  from  electricity  sales.

     Historically,  electric  utility  rates  in  Vermont  have  been based on a
utility's  cost of service.  As a result, Vermont electric utilities are subject
to  certain  accounting  standards  that  apply  only  to  regulated businesses.
Statement  of  Financial Accounting Standards No. 71 ("SFAS 71"), Accounting for
the Effects of Certain Types of Regulation, allows regulated entities, including
the  Company,  in  appropriate circumstances, to establish regulatory assets and
liabilities,  and thereby defer the income statement impact of certain costs and
revenues  that  are  expected  to  be  realized  in  future  rates.
     Regulatory  assets represent incurred costs that have been deferred because
the  Company has concluded that they are probable of future recovery in customer
rates.  Regulatory  liabilities  generally represent obligations to make refunds
to  customers for previous collections of costs.  The Company's last retail rate
case  was  filed during 1998.  Since that time a material amount of expenditures
have  been  deferred as regulatory assets pending consideration by the VPSB in a
future  retail  rate  proceeding.  These  regulatory  assets have been judged as
probable of recovery by management.  The most significant regulatory assets that
are  not  being  currently amortized in rates, or are being amortized at amounts
that  could  materially  differ  from  future  expenditure  levels,  include:
<TABLE>
<CAPTION>

Regulatory  assets
                               At December 31,
                               2002     2001
                              -------  -------
(in thousands)
<S>                           <C>      <C>
Pine Street Barge Canal. . .   13,019   12,425
Unscheduled VY outage costs.    2,002        -
Demand Side Management . . .    6,434    6,961
Storm damages. . . . . . . .    1,905    2,169
Tree Trimming. . . . . . . .      905      905
                              -------  -------
Regulatory assets. . . . . .  $24,265  $22,460
                              =======  =======
</TABLE>
Management's conclusion that these assets are probable of recovery is based on a
variety  of  factors,  including  benefits  to  customers, consistency with past
regulatory  treatment,  materiality  of  costs  relative  to normal cost levels,
similar  rate  case  decisions  in  other jurisdictions applying cost of service
ratemaking  principles,  and  opportunities to recover these costs over extended
periods  of  time.  If  the VPSB were to disallow any of these costs, the result
would  be a pretax charge to current earnings in the amount of the disallowance.

     The  Company  currently  complies  with  the provisions of SFAS 71.  If the
Company had determined that it no longer met the criteria for following SFAS 71,
at  December  31,  2002  the  accounting impact would have been an extraordinary
non-cash charge to operations of $51.6 million.  Factors that could give rise to
the  discontinuance  of  SFAS  71  include:
*     deregulation;
*     a  change  in  the  regulators'  approach to setting rates from cost-based
regulation  to  another  form  of  regulation;
*     increasing competition that limits our ability to sell utility services or
products  at  rates  that  will  recover  costs;  and
*     regulatory  actions  that  limit  rate  relief  to a level insufficient to
recover  costs.
     The  enactment  of  restructuring  legislation  or issuance of a regulatory
order  containing  provisions that do not allow for the recovery of above-market
power costs would require the Company to estimate and record losses immediately,
on  an  undiscounted  basis,  for  any above-market power purchase contracts and
other  costs  which are probable of not being recoverable from customers, to the
extent  that  those  costs  are  estimable.
     We  are  unable  to  predict what form future legislation, if passed, or an
order,  if issued, will take, and we cannot predict if or to what extent SFAS 71
will  continue  to  be  applicable  in the future.  However, we believe that the
continued  application  of  SFAS  71  is  appropriate  at  this  time.
     We  cannot  predict  whether  restructuring  legislation, if enacted by the
Vermont General Assembly, or any subsequent report or actions of, or proceedings
before,  the  VPSB or the Vermont General Assembly would have a material adverse
effect on our operations, financial condition or credit ratings.  The failure to
recover  a  significant  portion  of our purchased power costs, or to retain and
attract  customers  in  a  competitive environment, would likely have a material
adverse  effect on our business, including our operating results, cash flows and
ability  to  pay  dividends  at  current  levels.

PENSION  RISK-Other  critical  accounting  policies involve the non-contributory
defined  benefit  pension  and  postretirement  health care benefit plans of the
Company.  The  reported costs of these plans are dependent upon numerous factors
resulting  from  actual  plan  experience  and assumptions of future experience.
     Pension  and  postretirement  health  care  costs  are  impacted  by actual
employee demographics, the level of Company contributions to the plans, earnings
on  plan  assets,  and  health care cost trends (postretirement health care plan
only).
The Company's pension and postretirement health care benefit plan assets consist
of  equity  and  fixed income investments.  Fluctuations in actual equity market
returns,  as  well as changes in general interest rates, may result in increased
or  decreased costs in future periods.  Changes in assumptions regarding current
discount  rates  and expected rates of return on plan assets could also increase
or  decrease  recorded  defined benefit plan costs.  For example, the Company in
2003 expects to reduce the expected return on its plan assets by 50 basis points
to  8.5  percent,  resulting in a $210,000 increase in plan expense.  See Note H
for  further  information.
As  a result of our plan asset experience, at December 31, 2002, the Company was
required  to  recognize  an additional minimum liability of $2.4 million, net of
applicable  income  taxes, as prescribed by SFAS 87.  The liability was recorded
as  a  reduction to common equity through a charge to Other Comprehensive Income
("OCI"),  and  did  not  affect  net  income for 2002.  The charge to OCI may be
restored  through  common  equity  in future periods to the extent fair value of
trust  assets  exceeded  the accumulated benefit obligation.  Current changes to
plan  assumptions,  along with plan losses experienced during 2002, are expected
to  result  in  increased  pension and postretirement health benefit expenses of
approximately  $0.6  million  and  $0.5 million, respectively, for 2003 compared
with  2002.

UNREGULATED  BUSINESSES
     Most  of  the  assets  of  NWR, which invested in energy generation, energy
efficiency  and  wastewater treatment projects, have been sold.  NWR earned $0.1
million in 2002, compared with a loss of approximately $0.2 million in 2001, and
a  loss  of  $6.5  million  in  2000.  The  2002 earnings and 2001 loss resulted
primarily  from provisions to recognize adjustments to liability estimates under
warranties  for  past  equipment  sales.
     Risk  factors associated with the discontinuation of NWR operations include
the  outcome  of  warranty litigation, and future cash requirements necessary to
minimize  costs  of  winding down wastewater operations.  Several municipalities
using  wastewater treatment equipment provided by Micronair, LLC, a wholly owned
subsidiary  of  NWR,  have commenced or threatened litigation against Micronair.
The ultimate loss remains subject to the disposition of remaining NWR assets and
liabilities,  and  could  exceed  the  amounts  recorded.
          The  Company's  unregulated  rental  water heater business earned $0.3
million  in  2002,  essentially  unchanged  from  the  prior  two  years.

RESULTS  OF  OPERATIONS
OPERATING  REVENUES  AND  MWH  SALES-Operating revenues and megawatthour ("MWh")
sales  for  the  years  ended  2002,  2001  and  2000  consisted  of:
<TABLE>
<CAPTION>


                            Years ended December 31,
                                      2002                2001        2000
                            -------------------------  ----------  ----------
<S>                         <C>                        <C>         <C>
   (dollars in thousands)
 Operating Revenues
     Retail. . . . . . . .  $                 201,052  $  195,093  $  185,944
     Sales for Resale. . .                     70,646      83,804      88,333
     Other . . . . . . . .                      2,910       4,567       3,049
                            -------------------------  ----------  ----------
 Total Operating Revenues.  $                 274,608  $  283,464  $  277,326
                            =========================  ==========  ==========

 MWH Sales-Retail. . . . .                  1,948,190   1,953,154   1,947,857
 MWH Sales for Resale. . .                  2,107,941   2,368,887   2,575,657
                            -------------------------  ----------  ----------
 Total MWH Sales . . . . .                  4,056,131   4,322,041   4,523,514
                            =========================  ==========  ==========
</TABLE>
<TABLE>
<CAPTION>

 Average  Number  of  Customers

                               Years ended December 31,
                                         2002             2001    2000
                               ------------------------  ------  ------
<S>                            <C>                       <C>     <C>
    Residential . . . . . . .                    73,861  73,249  72,424
    Commercial and Industrial                    13,194  13,006  12,769
    Other . . . . . . . . . .                        65      65      65
                               ------------------------  ------  ------
 Total Number of Customers. .                    87,120  86,320  85,258
                               ========================  ======  ======
</TABLE>
Differences in operating revenues were due to changes in the following:
<TABLE>
<CAPTION>

          Change in Operating Revenues      2001 to      2000 to
                                               2002       2001
                                             ---------  --------
 (In thousands)
<S>                                          <C>        <C>
 Retail Rates . . . . . . . . . . . . . . .  $  6,471   $ 8,620
 Retail Sales Volume. . . . . . . . . . . .      (512)      529
 Resales and Other Revenues . . . . . . . .   (14,815)   (3,011)
                                             ---------  --------
 Increase (Decrease) in Operating Revenues.  $ (8,856)  $ 6,138
                                             =========  ========
</TABLE>
In  2002,  total electricity sales decreased 6.2 percent compared with 2001, due
to reduced sales for resale under the 9701 arrangement with Hydro Quebec and our
MS  contract,  described  in  more detail below under the headings "Power Supply
Expenses"  and "Power Contract Commitments".  Total operating revenues decreased
$8.9  million,  or  3.1 percent, in 2002 compared with 2001, due to decreases in
sales  for  resale,  partially  offset  by  increased retail operating revenues.
Retail  operating  revenues  increased  $6.0  million,  or  3.1 percent, in 2002
compared  with  2001  due to the recognition of $4.4 million of revenue deferred
under  the  Settlement  Order.  Increased  sales  to  residential and commercial
customers  also  contributed  to  higher  retail revenues, partially offset by a
decline  in  revenues  from International Business Machines Corporation ("IBM").

     In  2001, total electricity sales decreased 4.5 percent compared with 2000,
due  principally  to  reduced  sales  for  resale  executed  pursuant  to the MS
contract,  described  in  more  detail  below  under  the headings "Power Supply
Expenses"  and "Power Contract Commitments".  Total operating revenues increased
$6.1  million,  or  2.2  percent,  in  2001  compared with 2000 primarily due to
increases in retail and other operating revenues, partially offset by a decrease
in  lower  margin  wholesale  sales.  Retail  operating  revenues increased $9.1
million, or 4.9 percent, in 2001 compared with 2000 due to a 3.42 percent retail
rate  increase that went into effect January 2001, and an additional increase in
revenues  from  an  industrial customer pursuant to revisions in a contract with
that  customer  approved  in  the  Settlement  Order.

     IBM,  the  Company's largest customer, operates a manufacturing facility in
Essex  Junction,  Vermont.  IBM's  electricity  requirements  for  its  facility
accounted for approximately 25.7, 26.6, and 26.6 percent of the Company's retail
MWh  sales  in  2002,  2001,  and  2000,  respectively, and 17.3, 19.2, and 16.5
percent  of  the  Company's  retail  operating revenues in 2002, 2001, and 2000,
respectively.  No  other  retail customer accounted for more than one percent of
the  Company's  revenue  in  any  year.
     Since  1995,  the  Company  has  had  agreements  with  IBM with respect to
electricity  sales above agreed-upon base-load levels.  On December 8, 2000, the
VPSB  approved  a  new  three-year agreement between the Company and IBM, ending
December  31,  2003.  During  2002,  the  VPSB  approved  a modification of this
agreement  for  the  last  year  of  the term, 2003.  The price of power for the
three-year  term  of  the  agreement  is  above  our marginal costs of providing
incremental  service  to  IBM.
     IBM  reduced  its  Vermont  workforce  by  1,500 during 2002, to a level of
approximately  7,000  employees.  If  future  significant  losses in electricity
sales  to IBM were to occur, the Company's earnings could be impacted adversely.
If  earnings  were  materially  reduced  as  a result of lower retail sales, the
Company  would  seek  a  retail rate increase from the VPSB.  The Company is not
aware  of any plans by IBM to further reduce production at its Vermont facility.
The  Company  currently estimates, based on a number of projected variables, the
retail  rate  increase  required  from  all  retail  customers by a hypothetical
shutdown  of  the  IBM  facility  to  be  in  the  range of five to ten percent,
inclusive  of  projected  declines  in  sales  to  residential  and  commercial
customers.

POWER  SUPPLY EXPENSES- Prior to 2001, our inability to recover our power supply
costs had been a primary reason for the poor performance of the Company's common
stock price during 1999 and 2000.  The Settlement Order removed this obstacle by
allowing the Company rate recovery of its estimated power supply costs for 2001.
Furthermore,  the  Settlement  Order  allowed the Company to defer approximately
$8.5  million in rate levelization revenues for recognition in 2002 and 2003, if
necessary,  to  achieve  its  allowed  rate  of  return.  The Company recognized
approximately  $4.4  million  of these revenues in 2002 and expects to recognize
the  remaining balance of $4.1 million during 2003.  The deferred recognition of
rate  levelization  revenues  allowed the Company to achieve our allowed rate of
return  in  2002  without  further  rate  relief  and is expected to provide the
Company  with  the  opportunity  to  achieve  similar  operating results in 2003
without further rate relief (See "Power Contract Commitments", and "Rates-Retail
Rate  Cases"  in  this  section).
      Power  supply  expenses  constituted 74.5, 75.3, and 77.7 percent of total
operating  expenses  for  the  years  2002, 2001, and 2000, respectively.  Power
supply  expenses  decreased by $7.6 million or 3.8 percent in 2002 when compared
with  2001,  and  resulted  from  the  following:
     a $13.2 million decrease in power purchased for resale, primarily under the
9701  arrangement  with  Hydro  Quebec  and  our  MS  contract;
     a  $3.5 million decrease in the net cost of the 9701 arrangement with Hydro
Quebec;  and
     a  $2.1  million  increase  in  the  value  of additional generation at the
Company's  hydroelectric plants, that allowed the Company to purchase less power
during  2002.

These  decreases were partially offset by increased power supply expense in 2002
when  compared  with  2001  for  the  following  reasons:
     a  $6.2  million  increase  in  the  cost  of  power  purchased  from  MS;
     a  $3.7  million  net  increase in the cost of power purchased from Vermont
Yankee,  including  an  offset  of  $1.4  million  for  the increase in value of
additional  generation  purchased  from  the  plant;  and
     a  $2.9  million  increase  in  power  purchased  from  independent  power
producers.



       Power  supply  expenses decreased by $10.5 million or 5.0 percent in 2001
when compared with 2000.  The decrease in power supply expenses in 2001 compared
with  2000  resulted  from  the  following:
*     a  $7.7  million  decrease  in  energy  costs  arising from a power supply
arrangement  with  Hydro  Quebec,  discussed  under  the caption "Power Contract
Commitments",  whereby  Hydro  Quebec has an option to purchase energy at prices
that  are  below  market  replacement  costs;
*     a  $5.9  million  decrease  in  Vermont  Yankee costs due primarily to the
timing  of scheduled outages at the plant, where the outage costs, including the
costs  of  replacement  power,  are  deferred  and amortized over the subsequent
refueling  cycle;
*     a  $4.5  million decrease in power purchased for resale, primarily under a
power  supply  contract discussed under the caption "Power Contract Commitments"
below, pursuant to which the Company purchases  power from MS that is sufficient
to  serve  pre-established  load  requirements  at  a  pre-defined  price;  and
*     a  $3.0  million  decrease in Company-owned generation costs, reflecting a
reduction  in  generation used to maintain system reliability as compared to the
prior  year  when  the unavailability of certain transmission equipment required
these  units  to  run  more  frequently.


     In  2001,  these amounts were partially offset by the disallowance in rates
of  2000  Hydro  Quebec power contract costs that required $7.5 million of those
costs  to  be  charged  in  1999  and  amortized  as a reduction of power supply
expenses  during 2000, $2.1 million in higher energy prices in 2001 under our MS
contract,  and  higher  capacity  costs  in  2001 of approximately $1.0 million.

     The Independent System Operator of New England ("ISO" or "ISO New England")
was  created  to manage the operations of the New England Power Pool ("NEPOOL"),
effective  May  1,  1999.  The  ISO  works as a clearinghouse for purchasers and
sellers  of  electricity  in  the deregulated wholesale energy markets.  Sellers
place  bids for the sale of their generation or purchased power resources and if
demand  is  high  enough  the  output  from  those  resources  is  sold.
     We must purchase electricity to meet customer demand during periods of high
usage  and  to  replace  energy  repurchased  by  Hydro  Quebec  under  the 9701
arrangement  negotiated  in  1997.  Our  costs to serve demand during periods of
warmer  than  normal  temperatures  in  summer months and to replace such energy
repurchases by Hydro Quebec rose substantially after the wholesale power markets
became  deregulated in 1999, which caused much greater volatility in spot prices
for  electricity.  The  cost  of  securing  future power supplies had also risen
substantially  in  tandem  with  higher  summer power supply costs.  The Company
cannot  predict  the  extent  to which future prices will trade above historical
levels  of  cost.  If  the markets continue to experience the volatility evident
since  1999,  or the Company's power resources are unavailable during periods of
high  market prices, our earnings and cash flow could be adversely impacted by a
material  amount.

POWER  CONTRACT  COMMITMENTS-  On  February 11, 1999, we entered into a contract
with  MS  as  a result of our power requirements solicitation in 1998.  A master
power  purchase  and sales agreement ("PPSA") between the Company and MS defines
the  general  contract  terms under which the parties may transact.  Sales under
the PPSA commenced on February 12, 1999 and will terminate after all obligations
under  each  transaction entered into by MS and the Company have been fulfilled.
The  PPSA  was  filed with the Federal Energy Regulatory Commission ("FERC") and
the  VPSB  was  notified  as  well.  In  August  2002, the PPSA was modified and
extended  to  December  31,  2006.
     The  PPSA  provides us with a means of managing price risks associated with
changing  fossil fuel prices.  On a daily basis, and at MS's discretion, we sell
power  to  MS from either (i) all or part of our portfolio of power resources at
predefined  operating  and  pricing  parameters  or  (ii)  any  power  resources
available  to  us,  provided  that  sales  of  power  from  sources  other  than
Company-owned  generation  comply  with  the  predefined  operating  and pricing
parameters.  MS  then  sells  to  us, at a predefined price, power sufficient to
serve  pre-established load requirements.  MS is also responsible for scheduling
supply  resources.  We  remain  responsible  for  resource  performance  and
availability.  MS  provides  no coverage against major unscheduled outages.  The
Company  and  MS  have  agreed  to the protocols that are used to schedule power
sales  and  purchases  and to secure necessary transmission.  We anticipate that
arrangements we make to manage power supply risks will be on average more costly
than  the  expected  cost  of fuel during the periods being hedged because these
arrangements  typically  incorporate  a  risk  premium.
          The  Company's  current  purchases pursuant to the contract with Hydro
Quebec  entered into December 4, 1987 (the "1987 Contract") are as follows:  (1)
Schedule  B  --  68  megawatts  of  firm  capacity  and  associated energy to be
delivered  at  the  Highgate  interconnection  for  twenty  years  beginning  in
September  1995;  and  (2)  Schedule  C3  --  46  megawatts of firm capacity and
associated  energy  to  be delivered at interconnections to be determined at any
time  for  20  years,  which  began  in  November  1995.
     Pursuant  to  the  1987 Contract,  Hydro Quebec has the right to reduce the
load  factor  from 75 percent to 65 percent a total three times over the life of
the  1987  Contract.  The  Company  has  the contractual right to delay any such
reduction  by  one  year  under  the  1987  Contract.  During 2001, Hydro Quebec
exercised  the  first  of  these  options  for  2002 and the Company delayed the
effective  date of this exercise until 2003.  The Company estimates that the net
cost of Hydro Quebec's exercise of its option will increase power supply expense
during  2003  by  approximately  $0.4  million.
     Our contracts with Hydro Quebec contain cross default provisions that allow
Hydro  Quebec  to  invoke  "step-up"  provisions  under  which the other Vermont
utilities  that  are  party  to the contract would be required to purchase their
proportionate  share  of the power supply entitlement of the defaulting utility.
The  Company  is not aware of any instance where this provision has been invoked
by  Hydro  Quebec.
     During  1994,  we  negotiated an arrangement with Hydro Quebec that reduced
the  cost  under  our  1987  Contract  with  Hydro Quebec over the November 1995
through  October  1999  period  (the  "July  1994  Agreement").

     As  part  of  the  July  1994 Agreement, we were obligated to purchase $4.0
million  (in  1994  dollars)  worth  of research and development work from Hydro
Quebec  over  a  four-year  period (which was extended to 2003), and made a $6.5
million (in 1994 dollars) payment to Hydro Quebec in 1995.  Hydro Quebec retains
the  right  to  curtail annual energy deliveries by 10 percent up to five times,
over  the 2001 to 2015 period, if documented drought conditions exist in Qu bec.


     Under  the  9701  arrangement  established in December 1997 `, Hydro Quebec
paid  $8.0  million  to  the  Company  in  1997.  In return for this payment, we
provided  Hydro  Quebec  options for the purchase of power.  Commencing April 1,
1998  and  effective  through the term of the 1987 Contract, which ends in 2015,
Hydro  Quebec  may purchase up to 52,500 MWh ("option A") on an annual basis, at
the  1987  Contract  energy prices, which are substantially below current market
prices.  The  cumulative  amount  of energy that may be purchased under option A
shall  not  exceed  950,000  MWh.
     Over  the  same  period,  Hydro Quebec may exercise an option to purchase a
total  of  600,000  MWh  ("option  B") at the 1987 Contract energy price.  Under
option B, Hydro Quebec may purchase no more than 200,000 MWh in any year.  As of
December  31, 2002, Hydro Quebec had purchased or called to purchase 458,000 MWh
under  option  B.


     In 2002, Hydro Quebec exercised option A and called for deliveries to third
parties  at a net expense to the Company of approximately $3.0 million including
capacity  charges.
     In  2001,  Hydro  Quebec  exercised  option  A and option B, and called for
deliveries  to  third  parties  at a net expense to the Company of approximately
$6.5  million,  including  capacity  charges.
     In  2000,  Hydro  Quebec  exercised  option  A and option B, and called for
deliveries  to  third  parties  at a net expense to the Company of approximately
$14.0  million  (including the cost of January and February, 2001 calls, and the
cost of related financial positions), which was due to higher energy replacement
costs  incurred by the Company.  Approximately $6.6 million of the $14.0 million
net  9701  costs  were  recovered  in  rates  in  2000.
     The  Company  believes  that  it  is  probable  that Hydro Quebec will call
options  A  and B for 2003, and has purchased replacement power at a net cost of
$4.7  million.
     The  VPSB, in the Settlement Order stated, "The record does not demonstrate
that  any  other New England utility foresaw the extent and degree of volatility
that  has  developed  in  the  New England wholesale power markets.  Absent that
volatility,  the  97-01  Agreement  would  not  have  had  adverse effects."  In
conjunction  with the Settlement Order, Hydro Quebec committed to the Department
that  it  would  not  call any energy under option B of 9701 during the contract
year  ending  October  31,  2002.
     On  April  17,  2001,  an  Arbitration  Tribunal issued its decision in the
arbitration  brought  by  a  group  of  Vermont electric companies and municipal
utilities,  known  as the Vermont Joint Owners ("VJO"), against Hydro Quebec for
its  failure to deliver electricity pursuant to the VJO contract during the 1998
ice  storm.  The  Company  is  a  member  of  the  VJO.

          On  July  23,  2001,  the  Company received approximately $3.2 million
representing  its  share of refunded capacity payments from Hydro Quebec.  These
proceeds  reduced  related  deferred  assets  leaving  a  deferred  balance  of
unrecovered  arbitration  costs of approximately $1.4 million.  We believe it is
probable  that  this  balance  will  ultimately  be  recovered  in  rates.

Vermont  Yankee  Nuclear  Power  Corporation  ("VY")
     On  July  31,  2002, Vermont Yankee completed the sale of its nuclear power
plant to Entergy Nuclear Vermont Yankee ("Entergy").  In addition to the sale of
the  generating  plant,  the  transaction  calls  for  Entergy through its power
contract  with  VY,  to  provide  20  percent of the plant output to the Company
through  2012, which represents approximately 35 percent of the Company's energy
requirements.  The  Company  continues  to  own  approximately 19 percent of the
common  stock  of  VY.  Our benefits of the plant sale and the VY power contract
with  Entergy  include:
     VY receives cash approximately equal to the book value of the plant assets,
removing  the  potential  for  stranded  costs  associated  with  the  plant.
     VY  and  its  owners  will  no  longer bear operating risks associated with
running  the  plant.
     VY  and  its  owners  will  no  longer  bear  the risks associated with the
eventual  decommissioning  of  the  plant.
     Prices  under  the  Power  Purchase  Agreement  between VY and Entergy (the
"PPA")  range from $39 to $45 per megawatt-hour for the period beginning January
2003,  substantially  lower  than the forecasted cost of continued ownership and
operation  by  VY.  Contract prices ranged from $49 to $55 for 2002, higher than
the  forecasted  cost  of  continued  ownership  for  2002.
     The  PPA  calls for a downward adjustment in the price if market prices for
electricity  fall  by defined amounts beginning no later than November 2005.  If
market  prices  rise,  however,  the  contract  prices  are not adjusted upward.

     The  Company remains responsible for procuring replacement energy at market
prices  during periods of scheduled or unscheduled outages at the Entergy plant.
Payments  totaling $0.5 million were made to VY's non-Vermont sponsors in return
for  guarantees  those  sponsors  made  to  Entergy  to  finalize  the  VY sale.
Although  the  sale  closed  on July 31, 2002, the Company's distribution of the
sale  proceeds  and final accounting for the sale are pending certain regulatory
approvals  and  the  resolution of certain closing items between VY and Entergy.
The  Company expects its share of the VY power plant sale proceeds, estimated at
between $7 million and $8 million, to be distributed in the latter part of 2003.
The  sale  required  various  regulatory approvals, all of which were granted on
terms  acceptable  to the parties to the transaction. Certain intervener parties
to  the  VPSB  approval  proceeding  appealed  the  VPSB approval to the Vermont
Supreme  Court.  That  appeal  is  pending.  If  the appellants prevail on their
appeal,  the  VPSB  could  be  required  to conduct additional proceedings or to
reconsider  its  order  approving  the  sale.



OTHER  OPERATING  EXPENSES-  Other operating expenses decreased $1.7 million, or
10.9  percent  in  2002  compared  with 2001.  The decrease was primarily due to
reduced  consulting costs of approximately $1.0 million and reduced distribution
expenses of $0.6 million.  Other operating expenses are not expected to increase
significantly  during  2003.
     Other  operating  expenses  decreased  $1.7 million, or 9.7 percent in 2001
compared  with  2000.  The  decrease  was primarily due to a $3.2 million charge
during  2000  for disallowed regulatory litigation costs, ordered by the VPSB as
part  of  the  Settlement  Order,  offset  in  part by increased outside service
expense  during  2001.


TRANSMISSION  EXPENSES-Transmission  expenses  increased  $1.1  million,  or 7.7
percent,  in  2002  compared  with  2001.  The  Company's  relative  share  of
transmission  costs  varies  with  the  peak  demand  recorded  on  Vermont's
transmission  system.  The  Company's  share of those costs increased due to its
increased  load growth, relative to other Vermont utilities, and also because of
increased  transmission  investment  by  VELCO.
     Transmission  expenses  decreased  $0.1  million  or  0.8  percent  in 2001
compared  with  2000.
     During 2002, the Federal Energy Regulatory Commission ("FERC") accepted ISO
New  England's  request  to implement a standard market design ("SMD") governing
wholesale  energy  sales  in  New  England.  The ISO implemented its SMD plan on
March  1, 2003.  SMD includes a system of locational marginal pricing of energy,
under  which  prices  are  determined by zone, and based in part on transmission
congestion  experienced  in  each  zone.  Currently,  the  State  of  Vermont
constitutes  a  single  zone  under the plan, although pricing may eventually be
determined on a more localized ("nodal") basis.  The Company does not expect the
implementation  of  this SMD in its current form, which denominates Vermont as a
single  pricing zone, to have a material impact on the Company's power supply or
transmission  costs.  The  FERC has suggested that change to nodal pricing might
be  appropriate  as  early  as  18  months after the implementation of SMD.  The
Company  believes  that  this  could  result in a material adverse impact on its
power  supply  or  transmission  costs.
     On  July 31, 2002, FERC issued a Notice of Proposed Rulemaking to amend its
regulations and modify its existing pro forma open access transmission tariff to
require  that  all public utilities with open access transmission tariffs modify
their  tariffs  to reflect non-discriminatory, standardized transmission service
and  standard  wholesale  electric market design.  This rulemaking, known as the
"SMD NOPR," proposes to implement standard market design and locational marginal
pricing  in  all  regions  of the United States, including New England.  The SMD
NOPR  is currently in the rulemaking comment period.  It is uncertain whether or
how implementation of FERC's SMD NOPR, if and when approved, may differ from the
ISO New England SMD plan, or how implementation of the SMD NOPR could impact the
Company's  power  supply  or  transmission  costs, although the impacts could be
material.

     During  2002,  ISO New England and the New York Independent System Operator
filed  and  then  withdrew their petition with the FERC proposing to establish a
single  Northeastern  Regional  Transmission Organization ("NERTO") encompassing
the  six  New  England  states  and  New York.  ISO New England has indicated an
intention  to  file  a  petition  with  FERC  to  create a regional transmission
organization  comprising  six  New  England  states  now  part  of  the  ISO.

     VELCO  has  proposed  a  project  to  substantially  upgrade  Vermont's
transmission  system  (the  "Northwest  Reliability  Project"),  principally  to
support  reliability  and  eliminate  transmission  constraints  in northwestern
Vermont,  including  most  of  the  Company's  service  territory.  The proposed
Northwest  Reliability  Project  must be approved by the VPSB.  If approved, the
project is estimated to cost approximately $150 million over a seven to ten year
period.  Under  current  NEPOOL  and  ISO  New  England  rules,  which  require
qualifying  large  transmission project costs to be shared among all New England
utilities,  the  Company  would expect the costs of this project to be allocated
throughout  the  New  England  region,  with  Vermont  utilities responsible for
approximately  five percent of the total project costs.  However, in response to
FERC's  SMD  NOPR  and as part of ISO New England's SMD plan, ISO New England is
considering changes to the transmission cost allocation rules which could modify
or  eliminate  the  opportunity  to allocate costs associated with the Northwest
Reliability  Project  to  the  New  England  region as a whole.  The Company has
vigorously  advocated for continuation of the current cost allocation rules.  If
these  rules are modified or eliminated, the Company and other Vermont utilities
could be required to bear a greater proportion, and potentially all, of the cost
of  the  Northwest  Reliability  Project.

MAINTENANCE EXPENSES-Maintenance expenses increased $1.7 million or 25.0 percent
in  2002  compared  with  2001,  due  to increased expenditures related to storm
damage  and  increased  right-of-way  maintenance  programs.
     Maintenance expenses increased $0.5 million or 7.2 percent in 2001 compared
with  2000  due  to increased expenditures on right-of-way maintenance programs.

DEPRECIATION  AND  AMORTIZATION-Depreciation  and  amortization  expense
decreased  $0.1  million  or  1.0  percent  in  2002  compared  with 2001 due to
reductions  in  depreciation  of  utility  plant in service, partially offset by
increased  amortization  of  software  costs.
     Depreciation and amortization expense decreased $1.0 million or 6.6 percent
in  2001  compared  with  2000  due to reductions in amortization of demand side
management  costs  that  were only partially offset by increased depreciation of
utility  plant  in  service.

INCOME  TAXES-Income  tax  expense  decreased $0.9 million in 2002 compared with
2001  due  to  a  decrease  in the Company's taxable income.  Income tax expense
increased  $7.6  million  in  2001  when  compared  with  that of 2000 due to an
increase  in  the  Company's  taxable  income.

OTHER  INCOME-Other income increased $0.4 million in 2002 compared with 2001 due
primarily  to  the  VY recognition of deferred tax assets arising in conjunction
with  the sale of the VY plant,, offset in part by payments made to out-of-state
VY  sponsors  necessary  to  close  the  sale  of  the  VY  plant.
     Other  income decreased $0.3 million in 2001 compared with 2000 due in part
to  reduced  interest  income  from  the reduced investment returns available in
2001.

INTEREST EXPENSE-Interest expense decreased $0.9 million or 12.3 percent in 2002
compared with 2001 primarily due to scheduled and early redemptions of long-term
debt  and  reduced  short-term  borrowing rates offset in part by higher average
balances  for  short-term  borrowings.  Interest  expense  on  long-term debt is
expected  to  rise  approximately  $0.9 million in 2003 due to increased average
debt  levels  from  long-term  bonds  issued  in  December  2002.
     Interest  expense  decreased  $0.2  million or 3.0 percent in 2001 compared
with 2000 primarily due to scheduled reductions in long-term debt offset in part
by  a  $12  million  term  loan  made  on  August  24,  2001.

DIVIDENDS  ON  PREFERRED  STOCK-     Dividends on preferred stock decreased $0.8
million,  or  90 percent in 2002 compared with 2001 due to the repurchase of all
outstanding  preferred  stock  other  than  the  4.75  percent  Class  B shares.
Dividends on preferred stock are expected to be negligible during 2003.  See the
discussion  under  the  caption,  "Liquidity and Capital Resources-Financing and
Capitalization".
          Dividends  on preferred stock decreased $81,000 or 8.0 percent in 2001
compared  with  2000  due  to  repurchases  of  preferred  stock.

ENVIRONMENTAL  MATTERS
     The  electric  industry  typically uses or generates a range of potentially
hazardous products in its operations.  We must meet various land, water, air and
aesthetic  requirements  as  administered by local, state and federal regulatory
agencies.  We  believe  that  we  are  in  substantial  compliance  with  these
requirements,  and  that  there are no outstanding material complaints about our
compliance  with  present  environmental  protection  regulations,  except  for
developments  related  to  the  Pine  Street  Barge  Canal  site.

PINE  STREET  BARGE CANAL SITE-The Federal Comprehensive Environmental Response,
Compensation,  and  Liability  Act ("CERCLA"), commonly known as the "Superfund"
law, generally imposes strict, joint and several liability, regardless of fault,
for  remediation  of  property  contaminated with hazardous substances.  We have
previously  been notified by the Environmental Protection Agency ("EPA") that we
are  one  of several potentially responsible parties ("PRPs") for cleanup of the
Pine  Street  Barge  Canal site in Burlington, Vermont, where coal tar and other
industrial  materials  were  deposited.
     In  September 1999, we negotiated a final settlement with the United States
EPA,  the  State of Vermont (the "State"), and other parties to a Consent Decree
that  covers  claims with respect to the site and implementation of the selected
site  cleanup  remedy.  In  November  1999,  the Consent Decree was filed in the
federal district court.  The Consent Decree addresses claims by the EPA for past
Pine  Street  Barge  Canal site costs, natural resource damage claims and claims
for  past  and future oversight costs.  The Consent Decree also provides for the
design  and  implementation  of  response  actions  at  the  site.
     As  of December 31, 2002, our total expenditures related to the Pine Street
Barge  Canal  site  since  1982 were approximately $27.2 million.  This includes
amounts  not  recovered  in  rates,  amounts recovered in rates, and amounts for
which rate recovery has been sought but which are presently waiting further VPSB
action.  The  bulk  of  these  expenditures  consisted  of  transaction  costs.
Transaction  costs  include  legal  and  consulting  costs  associated  with the
Company's  opposition to the EPA's earlier proposals for a more expensive remedy
at  the  site, litigation and related costs necessary to obtain settlements with
insurers  and  other  PRPs  to  provide  amounts  required  to fund the clean up
("remediation  costs"),  and to address liability claims at the site.  A smaller
amount of past expenditures was for site-related response costs, including costs
incurred  pursuant  to  EPA  and  State orders that resulted in funding response
activities at the site, and to reimburse the EPA and the State for oversight and
related  response  costs.  The EPA and the State have asserted and affirmed that
all costs related to these orders are appropriate costs of response under CERCLA
for  which  the  Company  and  other  PRPs  were  legally  responsible.
     We  estimate  that  we  have recovered or secured, or will recover, through
settlements  of  litigation  claims  against insurers and other parties, amounts
that  exceed  estimated  future  remediation  costs,  future  federal  and state
government  oversight  costs and past EPA response costs.  We currently estimate
our  unrecovered  transaction  costs  mentioned  above,  which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $13.0 million over the next 32
years.  The  estimated  liability is not discounted, and it is possible that our
estimate  of  future  costs  could  change  by  a material amount.  We also have
recorded  an offsetting regulatory asset and we believe that it is probable that
we  will  receive  future  revenues  to  recover  these  costs.
     Through  rate  cases  filed  in  1991,  1993, 1994, and 1995, we sought and
received  recovery  for  ongoing  expenses associated with the Pine Street Barge
Canal  site.  While  reserving  the  right  to  argue  in  the  future about the
appropriateness of full rate recovery of the site-related costs, the Company and
the  Department,  and  as applicable, other parties, reached agreements in these
cases  that  the  full  amount of the site-related costs reflected in those rate
cases  should  be  recovered  in  rates.
     We  proposed  in  our  rate  filing  made  on  June 16, 1997 recovery of an
additional $3.0 million in such expenditures.  In an Order in that case released
March  2,  1998,  the VPSB suspended the amortization of expenditures associated
with  the Pine Street Barge Canal site pending further proceedings.  Although it
did  not  eliminate  the  rate  base deferral of these expenditures, or make any
specific  order in this regard, the VPSB indicated that it was inclined to agree
with  other parties in the case that the ultimate costs associated with the Pine
Street  Barge Canal site, taking into account recoveries from insurance carriers
and  other  PRPs,  should  be  shared  between customers and shareholders of the
Company.  In  some  other  jurisdictions,  "sharing"  has  been  accomplished by
allowing  utilities  to  recover  costs  over time without a rate of return.  In
response  to our Motion for Reconsideration, the VPSB on June 8, 1998 stated its
intent  was  "to reserve for a future docket issues pertaining to the sharing of
remediation-related  costs  between  the  Company  and  its  customers".  The
Settlement  Order  released  January  23, 2001 did not change the status of Pine
Street  Barge  Canal  site  cost  recovery.

CLEAN AIR ACT-Because we purchase most of our power supply from other utilities,
we  do not anticipate that we will incur any material direct cost increases as a
result  of  the  Federal  Clean  Air  Act  or  proposals  to make more stringent
regulations  under that Act.  Furthermore, only one of our power supply purchase
contracts,  which  expired in early 1998, related to a generating plant that was
affected  by Phase I of the acid rain provisions of this legislation, which went
into  effect  January  1,  1995.


RATES
RETAIL  RATE  CASES-  The  Company reached a final settlement agreement with the
Department  in  its  1998  rate case during November 2000.  The final settlement
agreement  contained  the  following  provisions:

*     The Company received a rate increase of 3.42 percent above existing rates,
beginning  with  bills  rendered  January  23,  2001,  and  prior temporary rate
increases  became  permanent;
*     Rates  were  set  at  levels  that  recover the Company's Hydro Quebec VJO
contract  costs,  effectively ending the regulatory disallowances experienced by
the  Company  from  1998  through  2000;
*     The  Company  agreed  not  to  seek any further increase in electric rates
prior  to  April  2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a request
for  additional  rate  relief  if power supply costs increase in excess of $3.75
million  over  forecasted  levels;
*     The  Company  agreed  to  write  off in 2000 approximately $3.2 million in
unrecovered rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
*     Seasonal  rates  were  eliminated  in  April  2001,  which  generated
approximately  $8.5 million in additional cash flow in 2001 that can be utilized
to  offset  increased  costs  during  2002  and  2003;
*     The  Company  agreed  to consult extensively with the Department regarding
capital  spending commitments for upgrading our electric distribution system and
to  adopt  customer  care and reliability performance standards, in a first step
toward  possible  development  of  performance-based  rate-making;
*     The  Company  agreed  to  withdraw its Vermont Supreme Court appeal of the
VPSB's  Order  in  a  1997  rate  case;  and
*     The  Company  agreed to an earnings limitation for its electric operations
in  an amount equal to its allowed rate of return of 11.25 percent, with amounts
earned  over  the  limit  being  used  to  write  off  regulatory  assets.

     On  January  23,  2001, the VPSB approved the Company's settlement with the
Department,  with  two  additional  conditions:
*     The Company and customers shall share equally any premium above book value
realized by the Company in any future merger, acquisition or asset sale, subject
to  an  $8.0  million limit on the customers' share, adjusted for inflation; and
*     The  Company's further investment in non-utility operations is restricted.

     The Company earned approximately $4.4 million less than its allowed rate of
return  during  2002  before including in earnings deferred revenues in the same
amount.
     The  Company  earned approximately $30,000 in excess of its allowed rate of
return  during  2001  before  writing  off regulatory assets in the same amount.

     The  VPSB,  in  its order approving VY's sale of its nuclear power plant to
Entergy,  ordered the Company and Central Vermont Public Service each to file on
or  before April 15, 2003, a cost-of-service study based on actual 2002 data, to
enable the VPSB to determine whether an adjustment to rates is justified in 2003
or  2004.  The  Company  believes this filing will support the Company's current
rates  and  does  not  intend  to  request a rate increase or decrease when this
filing is made.  The VPSB could initiate an investigation of the Company's rates
based  on  this  filing,  requiring the Company to complete a rate case, and the
VPSB  could order an adjustment to the Company's rates based on its findings and
conclusions.  If  the  VPSB  ordered  the Company to reduce its rates in 2003 or
2004,  this  could have a material adverse effect on our operating results, cash
flows  and  ability  to  pay  dividends  at  current  levels.

LIQUIDITY  AND  CAPITAL  RESOURCES
CONSTRUCTION-Our  capital  requirements  result  from  the  need  to  construct
facilities  or  to  invest  in  programs to meet anticipated customer demand for
electric  service.  Capital  expenditures,  net  of  customer  advances  for
construction,  over the past three years and forecasted for 2003 are as follows:
<TABLE>
<CAPTION>


                Generation   Transmission   Distribution   Conservation  Other*    Total
                -----------  -------------  -------------  ------------  -------  -------
(In thousands)
Actual:
--------------
<S>             <C>          <C>            <C>            <C>           <C>      <C>
2000 . . . . .  $     1,937  $         348  $       7,316            **  $ 5,876  $15,477
2001 . . . . .        2,323          1,219          8,567            **    3,529   15,638
2002 . . . . .        3,258          1,827          9,173            **    7,267   21,525
Forecast:
------------
2003 . . . . .  $     2,578  $       3,200  $       8,638            **  $ 8,088  $22,504
</TABLE>
*  Other  includes  $1.3  million in 2000, $1.5 million in 2001, $1.8 million in
2002,  and  an  estimated  $2.3  million in 2003 for the Pine Street Barge Canal
site.
**A  statewide  Energy Efficiency Utility set up by the VPSB in 1999 manages all
energy  efficiency  programs, receiving funds the Company bills to its customers
as  a  separate  charge.

DIVIDEND  POLICY-  The  annual  dividend  was $0.60 per share for the year ended
December 31, 2002.  The Settlement Order had limited the annual dividend rate at
its  then  current  level  of $0.55 per share until short-term credit facilities
were  replaced  with  long-term  debt  or  equity  financing.  The  Company used
proceeds  of  a $42 million long-term debt issue in December 2002 to replace all
short-term  borrowings,  satisfying  the  conditions in the Settlement Order and
permitting  the  Company  to  raise  its dividend.  The annual dividend rate was
increased  from  $0.55  per  share  to  $0.76 per share beginning with the $0.19
quarterly  dividend  declared in December 2002.  The Company intends to increase
the  dividend  in  a  measured  consistent  manner  until the payout ratio falls
between 50 percent and 60 percent of anticipated earnings.  The Company believes
this  payout  ratio to be consistent with that of other utilities having similar
risk  profiles.


FINANCING  AND  CAPITALIZATION-Internally-generated funds provided approximately
49  percent,  100  percent,  and  41 percent, of requirements for 2002, 2001 and
2000,  respectively.  The 2002 rate of internally generated funding requirements
was  reduced  because  of  accelerated redemptions of preferred stock and common
stock  repurchases  described in more detail below.  Internally generated funds,
after  payment  of  dividends,  provide  capital  requirements for construction,
sinking  funds  and other requirements.  We anticipate that for 2003, internally
generated  funds  will  provide  approximately  71  percent  of  total  capital
requirements  for  regulated  operations,  the remainder to be derived from bank
loans.
     The  Company  is  not  dependent  on the use of off-balance sheet financing
arrangements,  such  as  securitization  of  receivables  or obtaining access to
assets  through  special  purpose  entities.  We  do  have material power supply
commitments  that  are  discussed  in  detail under the captions "Power Contract
Commitments"  and  "Power  Supply  Expenses".  We also own an equity interest in
VELCO, which requires the Company to contribute capital when required and to pay
a  portion  of  VELCO's  operating  costs.
     At  December  31, 2002, our capitalization consisted of 47.6 percent common
equity  and  52.4  percent  long-term  debt.
     The  Company  has  a  $20.0 million 364-day revolving credit agreement with
Fleet  Financial  Services  ("Fleet")  joined  by  KeyBank  National Association
("KeyBank"),  expiring  June  2003  (the  "Fleet-Key Agreement").  The Fleet-Key
Agreement  is  unsecured  and  allows the Company to choose any blend of a daily
variable  prime  rate and a fixed term LIBOR-based rate.  There was $2.5 million
outstanding  with  a  weighted  average  rate  of  4.25 percent on the Fleet-Key
Agreement  at  December  31,  2002.  There  was  no  non-utility short-term debt
outstanding  at  December  31,  2002  or  2001.
     The  Company negotiated a $12.0 million, two-year, unsecured loan agreement
with  Fleet,  joined by KeyBank, on August 24, 2001.  The $12.0 million loan was
repaid  on  December  16,  2002.
     On  March  15,  2002, the Company redeemed $5.1 million of the 10.0 percent
first  mortgage  bonds  due  June  1,  2004.
     During March and June 2002, the Company repurchased $11.0 and $1.0 million,
respectively,  of  the 7.32 percent Class E preferred stock outstanding.  On May
1,  2002, the Company redeemed $0.3 million of the 7.0 percent Class C preferred
stock  outstanding.  During  November 2002, the Company redeemed $0.2 million of
the  9.375  percent  Class  D  preferred  stock  outstanding.

          On  November  19,  2002,  the  Company  completed  a  "Dutch  Auction"
self-tender  offer  and repurchased 811,783 shares, or approximately 14 percent,
of  its  common  stock  outstanding  for  approximately  $16.3  million.
     See  Note  D,  Preferred  Stock,  and Note F, Long Term Debt for additional
information.
     The Company anticipates that it will secure financing that replaces some or
all  of  its  expiring  facilities  during  2003.
     The  credit  ratings  of the Company's securities at December 31, 2002 are:

                                 Fitch     Moody's  Standard  &  Poor's
          First mortgage bonds     BBB+     Baa1          BBB
          Preferred stock           BBB     Ba1           BB
On August 29, 2002, Moody's upgraded the Company's senior secured debt rating to
Baa1  from  Baa2.  The outlook for the rating is stable.  On September 29, 2002,
Fitch  Ratings upgraded the rating of the Company's first mortgage bonds to BBB+
from  BBB,  with  a  stable outlook.  On September 23, 2002, Standard and Poor's
Ratings  Services  affirmed its BBB rating of the Company's senior secured debt,
with  a  stable  outlook.
          In  the  event of a change in the Company's first mortgage bond credit
rating  to  below investment grade, scheduled payments under the Company's first
mortgage  bonds  would not be affected.  Such a change would require the Company
to post what would currently amount to a $4.3 million bond under our remediation
agreement  with  the  EPA  regarding  the  Pine Street Barge Canal site.  The MS
contract  requires credit assurances if the Company's first mortgage bond credit
ratings  are  lowered  to  below investment grade by any two of the three credit
rating  agencies  listed  above.

     The  following  table  presents  a  summary of certain material contractual
obligations  existing  as  of  December  31,  2002.
<TABLE>
<CAPTION>

                                    Payments Due by Period
                                    ----------------------
                                                           2004 and    2006 and  After
                                       TOTAL       2003       2005      2007      2007
------------------------------------  ----------  --------  --------  --------
(In thousands)
<S>                                   <C>         <C>       <C>       <C>       <C>
Long-term debt . . . . . . . . . . .  $  101,000  $  8,000  $      -  $ 14,000  $ 79,000
Interest on long-term debt . . . . .      72,797     7,047    13,068    12,068    40,614
Preferred stock. . . . . . . . . . .          85        30        55         -         -
Capital lease obligations. . . . . .       5,287       407       814       814     3,252
Hydro-Quebec power supply contracts.     671,268    47,285   101,368   101,872   420,743
MS power supply contract . . . . . .     184,108    55,884    83,941    44,283         -
Vermont Yankee . . . . . . . . . . .     296,909    36,308    64,421    64,130   132,050
                                      ----------  --------  --------  --------  --------
    Total. . . . . . . . . . . . . .  $1,331,454  $154,961  $263,667  $237,167  $675,659
                                      ==========  ========  ========  ========  ========
</TABLE>
PENSION.  Due  to sharp declines in the equity markets during 2001 and 2002, the
value of assets held in trusts to satisfy the Company's pension plan obligations
has  decreased.  The  Company's  pension  plan  assets  are primarily made up of
public  equity  and  fixed  income  investments.  Fluctuations  in actual equity
market  returns  as  well  as  changes  in  general interest rates may result in
increased  or  decreased  pension  costs  in  future  periods.
     The  Company's  funding  policy  is  to make voluntary contributions to its
defined  benefit  plans  before  ERISA  or  Pension Benefit Guaranty Corporation
requirements mandate such contributions under minimum funding rules, and so long
as  the Company's liquidity needs do not preclude such investments.  The Company
made  voluntary  pension  plan  contributions  totaling  $1.0  million  between
September  1,  2002 and December 31, 2002.  The Company plans to make additional
voluntary  contributions  totaling  $1.0  million  before  June  30,  2003.  The
Company's  pension  costs and cash funding requirements could increase in future
years  in  the  absence  of  recovery  in  the  equity  markets.

OTHER  REGULATORY  PROCEEDINGS  AND LITIGATION-In a series of Vermont regulatory
proceedings, the Company has agreed to undertake a process known as "distributed
utility planning" as part of its transmission and distribution planning process.
Distributed  utility  planning  requires  the  Company  to  evaluate
conservation-related  alternatives  and  distributed  generation alternatives to
typical  transmission  and  distribution  capital  investments.  In  certain
circumstances,  the  Company  may  be  required  to  implement  conservation  or
distributed  generation  alternatives in lieu of, or in addition to, traditional
transmission  and  distribution capital investments, where societal cost savings
associated  with  conservation  or  distributed  generation, including the costs
associated  with  avoided  electricity  sales,  justify  the  expenditures.  The
Company  is uncertain of the potential magnitude of future spending requirements
for  this  program,  but  note  they  could  be material.  Costs associated with
conservation  measures  or  distributed  generation  facilities not owned by the
Company  would be deferred as regulatory assets pending future rate proceedings.
     In  2002,  the  owners  of  property  along the shoreline of Joe's Pond, an
impoundment located in Danville, Vermont, created by the Company's West Danville
Dam  hydroelectric  generating  facility, filed an inquiry with the VPSB seeking
review of certain dam improvements made by the Company in 1995, complaining that
the  Company  did  not  obtain  all  necessary regulatory approvals for the 1995
improvements and that the Company's improvements and subsequent operation of the
dam  have caused flooding of the shoreline and property damage.  The Company has
petitioned  the  VPSB  to make additional dam improvements at the facility at an
estimated cost of $350,000.  The VPSB must approve the Company's petition before
the  proposed  improvements  can  be implemented.  This regulatory proceeding is
pending and the Company is unable to predict whether the Company's petition will
be  approved or whether the VPSB will impose regulatory conditions or penalties.

FUTURE  OUTLOOK
COMPETITION  AND  RESTRUCTURING-The  electric  utility business are experiencing
rapid  and  substantial  changes.  These changes are the result of the following
trends:
*     disparity  in  electric rates, transmission, and generating capacity among
and  within  various  regions  of  the  country;
*     improvements  in  generation  efficiency;
*     increasing  demand  for  customer  choice;
*     new regulations and legislation intended to foster competition, also known
as  restructuring;  and
*     increasing  volatility  of  wholesale  market  prices  for  electricity.

     Electric  utilities  historically  have  had  exclusive  franchises for the
retail  sale  of  electricity  in  specified  service territories.  As a result,
competition  for  retail  customers  has  been  limited  to:
*     competition  with  alternative  fuel  suppliers, primarily for heating and
cooling;
*     competition  with  customer-owned  generation;  and
*     direct  competition  among  electric  utilities  to  attract  major  new
facilities  to  their  service  territories.

     These  competitive  pressures  have  led the Company and other utilities to
offer, from time to time, special discounts or service packages to certain large
customers.
     In  certain states across the country, including all the New England states
except Vermont, legislation has been enacted to allow retail customers to choose
their  electricity  suppliers, with incumbent utilities required to deliver that
electricity  over  their  transmission  and  distribution systems (also known as
retail  wheeling).  Increased  pressure  in  the  electric  utility industry may
restrict  the  Company's  ability  to charge energy prices sufficient to recover
costs  of  service,  such  as  the  cost  of  purchased  power obligations or of
generation  facilities  owned  by  the  Company.  The amount by which such costs
might  exceed  market  prices  is  commonly  referred  to  as  stranded  costs.
     Regulatory  and  legislative  authorities  at the federal level and in some
states,  including  Vermont  (where  legislation  has  not  been  enacted),  are
considering  whether,  when  and  how  to facilitate competition for electricity
sales  at  the  retail  level.  Recent  difficulties  in  some  regulatory
jurisdictions,  such  as  California,  have  dampened any immediate push towards
deregulation  in  Vermont.  Alternate  forms  of  performance-based  regulation
currently  appear as possible intermediate steps towards deregulation.  However,
in  the  future,  the  Vermont General Assembly through legislation, or the VPSB
through a subsequent report, action or proceeding, may allow customers to choose
their  electric supplier.  If this happens without providing for recovery of the
costs  associated with our power supply obligations and other costs of providing
vertically  integrated service, the Company's franchise, including our operating
results,  cash flows and ability to pay dividends at the current level, would be
adversely  affected.
     During  2001,  the  Town  of  Rockingham  ("Rockingham"), Vermont initiated
inquiries and legal procedures to establish its own electric utility, seeking to
purchase  the  Bellows  Falls hydroelectric facility from a third party, and the
associated  distribution  plant  owned by the Company within the town.  In March
2002,  voters in Rockingham approved an article authorizing Rockingham to create
a  municipal utility by acting to acquire a municipal plant, which would include
the  electric  distribution systems of the Company and/or Central Vermont Public
Service Corporation.  The Company receives annual revenues of approximately $4.0
million  from its customers in Rockingham.  Should Rockingham create a municipal
system,  the  Company  would  vigorously  pursue  its  right  to  receive  just
compensation  from  Rockingham.  Such  compensation  would  include  full
reimbursement  for  Company  assets,  if acquired, and full reimbursement of any
other  costs associated with the loss of customers in Rockingham, to assure that
neither  our  remaining  customers  nor our shareholders effectively subsidize a
Rockingham  municipal  utility.


NUCLEAR  DECOMMISSIONING-The  staff  of  the  SEC has questioned certain current
accounting practices of the electric utility industry regarding the recognition,
measurement  and  classification of decommissioning costs for nuclear generating
units  in  financial  statements.  In response to these questions, the Financial
Accounting  Standards  Board  ("FASB")  had  agreed to review the accounting for
closure  and  removal  costs,  including decommissioning.  The FASB issued a new
statement  in  August  2001  for  "Accounting for Asset Retirement Obligations",
which  provides  guidance on accounting for nuclear plant decommissioning costs,
as  well  as  other  asset retirement costs.  The Company has not yet determined
what  impact, if any, the new accounting standard will have on its investment in
VY.  We  do not believe that changes in such accounting, if required, would have
an adverse effect on the results of our operations due to our current and future
ability  to  recover  decommissioning  costs  through  rates.

EFFECTS  OF  INFLATION-Financial  statements  are  prepared  in  accordance with
generally  accepted  accounting principles and report operating results in terms
of historic costs.  This accounting provides reasonable financial statements but
does not always take inflation into consideration.  As rate recovery is based on
these  historical costs and known and measurable changes, the Company is able to
receive  some  rate  relief  for  inflation.  It does not receive immediate rate
recovery  relating  to  fixed  costs associated with Company assets.  Such fixed
costs  are  recovered  based  on  historic figures.  Any effects of inflation on
plant  costs  are  generally  offset  by the fact that these assets are financed
through  long-term  debt.

42

ITEM  8.  FINANCIAL  STATEMENTS  AND  SUPPLEMENTARY  DATA

                        GREEN MOUNTAIN POWER CORPORATION
            INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES


Financial  Statements                                                    Page

Consolidated  Statements  of  Income  and Other Comprehensive                 43
    Income  For  the  Years  Ended  December  31,  2002,  2001,  and  2000

Consolidated  Statements  of  Cash  Flows For the                             44
    Years  Ended  December  31,  2002,  2001,  and  2000

Consolidated  Balance  Sheets  as  of                                         45
    December  31,  2002  and  2001
Consolidated  Statement  of  Changes  In Shareholders Equity                  47
     For  the  Years  Ended  December  31,  2002,  2001  and  2000
Consolidated  Capitalization  Data  as  of                                    48
    December  31,  2002  and  2001

Notes  to  Consolidated  Financial  Statements                                49

Quarterly  Financial  Information                                           73

Reports  of  Independent  Public  Accountants                                 74

Schedules

For  the  Years  Ended  December  31,  2002,  2001,  and  2000:

    II  Valuation  and  Qualifying  Accounts  and Reserves                    76

             All  other  schedules  are  omitted  as  they  are  either
             not  required,  not  applicable  or  the  information  is
             otherwise  provided.

Consent  and  Report  of  Independent  Public  Accountants

             Arthur  Andersen  LLP                                          77
          Deloitte  and  Touche  LLP

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

<TABLE>
<CAPTION>

GREEN  MOUNTAIN  POWER  CORPORATION
                CONSOLIDATED STATEMENTS OF INCOME                     For the Years Ended December 31
                                                                            2002       2001       2000
                                                                          ---------  ---------  ---------
(In thousands, except per share data)
<S>                                                                       <C>        <C>        <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . .  $274,608   $283,464   $277,326
OPERATING EXPENSES
Power Supply
  Vermont Yankee Nuclear Power Corporation . . . . . . . . . . . . . . .    35,252     30,114     34,813
  Company-owned generation . . . . . . . . . . . . . . . . . . . . . . .     5,067      4,742      7,777
  Purchases from others. . . . . . . . . . . . . . . . . . . . . . . . .   153,129    166,209    168,947
Other operating. . . . . . . . . . . . . . . . . . . . . . . . . . . . .    14,188     15,924     17,644
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    15,221     14,130     14,237
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     8,854      7,108      6,633
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . .    14,151     14,294     15,304
Taxes other than income. . . . . . . . . . . . . . . . . . . . . . . . .     7,623      7,536      7,402
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     6,043      6,948       (691)
                                                                          ---------  ---------  ---------
    Total operating expenses . . . . . . . . . . . . . . . . . . . . . .   259,528    267,005    272,066
                                                                          ---------  ---------  ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . .    15,080     16,459      5,260
                                                                          ---------  ---------  ---------

OTHER INCOME
Equity in earnings of affiliates and non-utility operations. . . . . . .     2,777      2,253      2,495
Allowance for equity funds used during construction. . . . . . . . . . .       233        210        284
                                                                          ---------
Other (deductions) income, net . . . . . . . . . . . . . . . . . . . . .      (525)       (90)       (73)
                                                                          ---------  ---------  ---------
    Total other income . . . . . . . . . . . . . . . . . . . . . . . . .     2,485      2,373      2,706
                                                                          ---------  ---------  ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . .    17,565     18,832      7,966
                                                                          ---------  ---------  ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     5,214      6,073      6,499
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     1,059      1,154        986
Allowance for borrowed funds used during construction. . . . . . . . . .      (103)      (188)      (228)
                                                                          ---------  ---------  ---------
    Total interest charges . . . . . . . . . . . . . . . . . . . . . . .     6,170      7,039      7,257
                                                                          ---------  ---------  ---------
INCOME BEFORE PREFERRED DIVIDENDS AND
DISCONTINUED OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . .    11,395     11,793        709
Dividends on preferred stock . . . . . . . . . . . . . . . . . . . . . .        96        933      1,014
                                                                          ---------  ---------  ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS . . . . . . . . . . . . . . . .    11,299     10,860       (305)

Income (Loss) on disposal, including provisions for
operating losses during phaseout period, net of applicable income taxes.        99       (182)    (6,549)
                                                                          ---------  ---------  ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . . . . . . .  $ 11,398   $ 10,678   $ (6,854)
                                                                          =========  =========  =========
EARNINGS PER SHARE
Basic earnings (loss) per share from continuing operations . . . . . . .  $   2.02   $   1.93   $  (0.06)
Basic earnings (loss) per share from discontinued operations . . . . . .      0.02      (0.03)     (1.19)
                                                                          ---------  ---------  ---------
Basic earnings (loss) per share. . . . . . . . . . . . . . . . . . . . .  $   2.04   $   1.90   $  (1.25)
                                                                          =========  =========  =========
Diluted earnings (loss) per share from continuing operations . . . . . .  $   1.96   $   1.88   $  (0.06)
Diluted earnings (loss) per share from discontinued operations . . . . .      0.02      (0.03)     (1.19)
                                                                          ---------  ---------  ---------
Diluted earnings (loss) per share. . . . . . . . . . . . . . . . . . . .  $   1.98   $   1.85   $  (1.25)
                                                                          =========  =========  =========
Cash dividends declared per share. . . . . . . . . . . . . . . . . . . .  $   0.60   $   0.55   $   0.55
Weighted average shares outstanding-basic. . . . . . . . . . . . . . . .     5,592      5,630      5,491
Weighted average equivalent shares outstanding-diluted . . . . . . . . .     5,756      5,789      5,491
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME . . . . . . . . . . . . .      2002       2001       2000
                                                                          ---------  ---------  ---------
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $ 11,398   $ 10,678   $ (6,854)
Minimum pension liability adjustment, net of $1,612 related income tax .    (2,374)         -          -
                                                                          ---------  ---------  ---------
  Other comprehensive income, net of tax . . . . . . . . . . . . . . . .  $  9,024   $ 10,678   $ (6,854)
                                                                          =========  =========  =========
</TABLE>
The  accompanying  notes  are  an  integral  part  of the consolidated financial
statements.

<TABLE>
<CAPTION>


 GREEN  MOUNTAIN  POWER  CORPORATION
           CONSOLIDATED STATEMENTS OF CASH FLOWS            FOR THE YEARS ENDED
                                 (in thousands)     DECEMBER 31,
                                                           2002       2001       2000
                                                         ---------  ---------  ---------
OPERATING ACTIVITIES:
<S>                                                      <C>        <C>        <C>
Net income (loss) before preferred dividends. . . . . .  $ 11,494   $ 11,611   $ (5,840)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . .    14,151     14,294     15,304
Dividends from associated companies less equity income.       415        280        (26)
Allowance for funds used during construction. . . . . .      (335)      (398)      (512)
Amortization of deferred purchased power costs. . . . .     3,236      3,767      5,575
Deferred income taxes . . . . . . . . . . . . . . . . .     2,430     (2,167)       161
Provision for chargeoff of deferred regulatory asset. .         -          -      3,229
Deferred purchased power costs. . . . . . . . . . . . .    (2,003)     1,126     (6,692)
Accrued purchase power contract option call . . . . . .         -     (8,276)     8,276
Adjustment to provision for loss on segment disposal. .       (99)       182      6,549
Arbitration costs recovered (deferred). . . . . . . . .         -      3,229     (3,184)
Rate levelization liability . . . . . . . . . . . . . .    (4,483)     8,527          -
Environmental and conservation deferrals, net . . . . .    (2,194)    (3,380)    (2,073)
Changes in:
Accounts receivable and accrued utility revenues. . . .      (896)     6,483     (3,987)
Prepayments, fuel and other current assets. . . . . . .       850        300       (931)
Accounts payable and other current liabilities. . . . .       (55)       128     (4,337)
Accrued income taxes payable and receivable . . . . . .     5,010      1,187       (372)
Other . . . . . . . . . . . . . . . . . . . . . . . . .     1,556     (1,603)      (181)
                                                         ---------  ---------  ---------
Net cash provided by continuing operations. . . . . . .    29,077     35,290     10,959
Net change in discontinued segment. . . . . . . . . . .         -     (1,797)       245
                                                         ---------  ---------  ---------
Net cash provided by operating activities . . . . . . .    29,077     33,493     11,204

INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . .   (19,543)   (12,963)   (13,853)
Investment in associated companies. . . . . . . . . . .      (392)         -          -
Proceeds from subsidiary sales. . . . . . . . . . . . .         -          -      6,000
Investment in nonutility property . . . . . . . . . . .      (206)      (212)      (187)
                                                         ---------  ---------  ---------
Net cash used in investing activities . . . . . . . . .   (20,141)   (13,175)    (8,041)
                                                         ---------  ---------  ---------
FINANCING ACTIVITIES:
Proceeds from issuance of long term debt. . . . . . . .    42,000          -          -
Payments to acquire treasury stock. . . . . . . . . . .   (16,319)         -          -
(Reduction in) Proceeds from term loan. . . . . . . . .   (12,000)    12,000          -
Repurchase of preferred stock . . . . . . . . . . . . .   (12,536)      (235)    (1,640)
Issuance of common stock. . . . . . . . . . . . . . . .     1,037      1,655      1,250
Proceeds (purchases) of certificate of deposit. . . . .         -     16,173    (15,437)
Power supply option obligation. . . . . . . . . . . . .         -    (16,012)    15,419
Reduction in long-term debt . . . . . . . . . . . . . .   (13,322)    (9,700)    (6,700)
Short-term debt, net. . . . . . . . . . . . . . . . . .     2,500    (15,500)     7,600
Cash dividends. . . . . . . . . . . . . . . . . . . . .    (3,393)    (4,034)    (4,011)
                                                         ---------  ---------  ---------

Net cash used in financing activities . . . . . . . . .   (12,033)   (15,653)    (3,520)
                                                         ---------  ---------  ---------
Net increase (decrease) in cash and cash equivalents. .    (3,097)     4,665       (356)

Cash and cash equivalents at beginning of period. . . .     5,006        341        696
                                                         ---------  ---------  ---------

Cash and cash equivalents at end of period. . . . . . .  $  1,909   $  5,006   $    341
                                                         =========  =========  =========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . .  $  6,048   $  6,936   $  7,185
Income taxes. . . . . . . . . . . . . . . . . . . . . .     2,349      9,622      1,191

SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Minimum pension liability adjustment, net . . . . . . .  $  2,374   $      -   $      -
</TABLE>


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

<TABLE>
<CAPTION>



GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                          DECEMBER 31,

                                                    2002      2001
                                                  --------  --------
(in thousands)
<S>                                               <C>       <C>
ASSETS
UTILITY PLANT
  Utility plant, at original cost. . . . . . . .  $311,543  $302,489
  Less accumulated depreciation. . . . . . . . .   122,197   119,054
                                                  --------  --------
  Net utility plant. . . . . . . . . . . . . . .   189,346   183,435
  Property under capital lease . . . . . . . . .     5,287     5,959
  Construction work in progress. . . . . . . . .     8,896     7,464
                                                  --------  --------
  Total utility plant, net . . . . . . . . . . .   203,529   196,858
                                                  --------  --------
OTHER INVESTMENTS
  Associated companies, at equity. . . . . . . .    14,101    14,093
  Other investments. . . . . . . . . . . . . . .     7,451     6,852
                                                  --------  --------
  Total other investments. . . . . . . . . . . .    21,552    20,945
                                                  --------  --------
CURRENT ASSETS
  Cash and cash equivalents. . . . . . . . . . .     1,909     5,006
  Accounts receivable, less allowance for
  doubtful accounts of $547 and $613 . . . . . .    17,253    17,111
  Accrued utility revenues . . . . . . . . . . .     6,618     5,864
  Fuel, materials and supplies, at average cost.     3,349     4,058
  Prepayments. . . . . . . . . . . . . . . . . .     1,901     1,976
  Income tax receivable. . . . . . . . . . . . .         -     1,699
  Other. . . . . . . . . . . . . . . . . . . . .       402       469
                                                  --------  --------
  Total current assets . . . . . . . . . . . . .    31,432    36,183
                                                  --------  --------
DEFERRED CHARGES
  Demand side management programs. . . . . . . .     6,434     6,961
  Purchased power costs. . . . . . . . . . . . .     2,323     3,504
  Pine Street Barge Canal. . . . . . . . . . . .    13,019    12,425
  Power supply derivative deferral . . . . . . .    18,405    37,313
  Other. . . . . . . . . . . . . . . . . . . . .    11,413    12,265
                                                  --------  --------
  Total deferred charges . . . . . . . . . . . .    51,594    72,468
                                                  --------  --------

NON-UTILITY
  Other current assets . . . . . . . . . . . . .         8         8
  Property and equipment . . . . . . . . . . . .       249       250
  Other assets . . . . . . . . . . . . . . . . .       738       817
                                                  --------  --------
  Total non-utility assets . . . . . . . . . . .       995     1,075
                                                  --------  --------

TOTAL ASSETS . . . . . . . . . . . . . . . . . .  $309,102  $327,529
                                                  ========  ========
</TABLE>


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






<TABLE>
<CAPTION>


GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                          DECEMBER 31,

                                                       2002       2001
                                                     ---------  ---------
(in thousands except share data)
<S>                                                  <C>        <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,782,496 and 5,701,010 ) . . . . . . . . . . . . .  $ 19,276   $ 19,004
Additional paid-in capital. . . . . . . . . . . . .    75,347     74,581
Retained earnings . . . . . . . . . . . . . . . . .    16,171      8,070
Accumulated other comprehensive income. . . . . . .    (2,374)         -
Treasury stock, at cost (827,639 and 15,856 shares)   (16,698)      (378)
                                                     ---------  ---------
Total common stock equity . . . . . . . . . . . . .    91,722    101,277
Redeemable cumulative preferred stock . . . . . . .        55     12,325
Long-term debt, less current maturities . . . . . .    93,000     74,400
                                                     ---------  ---------
Total capitalization. . . . . . . . . . . . . . . .   184,777    188,002
                                                     ---------  ---------
CAPITAL LEASE OBLIGATION. . . . . . . . . . . . . .     5,287      5,959
                                                     ---------  ---------
CURRENT LIABILITIES
Current maturities of preferred stock . . . . . . .        30        235
Current maturities of long-term debt. . . . . . . .     8,000      9,700
Short-term debt . . . . . . . . . . . . . . . . . .     2,500          -
Accounts payable, trade and accrued liabilities . .     7,431      7,237
Accounts payable to associated companies. . . . . .     8,940      8,361
Rate levelization liability . . . . . . . . . . . .     4,091      8,527
Customer deposits . . . . . . . . . . . . . . . . .       898        971
Interest accrued. . . . . . . . . . . . . . . . . .     1,081      1,100
Other . . . . . . . . . . . . . . . . . . . . . . .     5,520      2,945
                                                     ---------  ---------
Total current liabilities . . . . . . . . . . . . .    38,491     39,076
                                                     ---------  ---------
DEFERRED CREDITS
Power supply derivative liability . . . . . . . . .    18,405     37,313
Accumulated deferred income taxes . . . . . . . . .    26,471     23,759
Unamortized investment tax credits. . . . . . . . .     3,130      3,413
Pine Street Barge Canal cleanup liability . . . . .     8,833     10,059
Other . . . . . . . . . . . . . . . . . . . . . . .    21,767     18,247
                                                     ---------  ---------
Total deferred credits. . . . . . . . . . . . . . .    78,606     92,791
                                                     ---------  ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Net liabilities of discontinued segment . . . . . .     1,941      1,701
                                                     ---------  ---------
Total non-utility liabilities . . . . . . . . . . .     1,941      1,701
                                                     ---------  ---------

TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . .  $309,102   $327,529
                                                     =========  =========

</TABLE>


The  accompanying  notes  are  an  integral part of these consolidated financial
statements.
<TABLE>
<CAPTION>

CONSOLIDATED  STATEMENT  OF  CHANGES  IN  STOCKHOLDERS'  EQUITY
                                                                                            ACCUMULATED
                                                COMMON STOCK         PAID-IN    RETAINED  COMPREHENSIVE   TREASURY   STOCK
                                         SHARES           AMOUNT    CAPITAL    EARNINGS    OTHER INCOME     STOCK     EQUITY
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
                                  (Dollars in thousands)
<S>                               <C>                     <C>       <C>        <C>         <C>             <C>        <C>
BALANCE, DECEMBER 31, 1999 . . .              5,409,715   $18,085   $ 72,594   $  10,344   $           -   $   (378)  $100,645
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
Common Stock Issuance:
DRIP and ESIP. . . . . . . . . .                157,790       526        764           -               -          -        609
Compensation Program:
   Restricted Shares . . . . . .                   (809)       (3)       (37)          -               -          -        (40)
Net Loss . . . . . . . . . . . .                      -         -          -      (5,840)              -          -     (5,840)
Other Comprehensive Income . . .                      -
Common Stock Dividends . . . . .                      -         -          -      (2,997)              -          -     (2,997)
Preferred Stock Dividends: . . .                      -         -          -      (1,014)              -          -     (1,014)
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
BALANCE, DECEMBER 31, 2000 . . .              5,566,696    18,608     73,321         493               -       (378)    92,044
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
Common Stock Issuance:
DRIP and ESIP. . . . . . . . . .                105,767       352      1,218           -               -          -      1,570
Compensation Programs:
   Restricted Shares and ISOP. .                 12,691        44         42           -               -          -         86
Net Income . . . . . . . . . . .                      -         -          -      11,611               -          -     11,611
Other Comprehensive Income
Common Stock Dividends . . . . .                      -         -          -      (3,101)              -          -     (3,101)
Preferred Stock Dividends: . . .                      -         -          -        (933)              -          -       (933)
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
BALANCE, DECEMBER 31, 2001 . . .              5,685,154    19,004     74,581       8,070               -       (378)   101,277
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
Common Stock Issuance:
DRIP and ESIP. . . . . . . . . .                 28,682        95        424           -               -          -        519
Common stock repurchase. . . . .               (811,783)        -          -           -               -    (16,320)   (16,320)
Compensation Programs:
   Restricted Shares and ISOP. .                 52,804       177        342           -               -          -        519
Net Income . . . . . . . . . . .                      -         -          -      11,494               -          -     11,494
Other Comprehensive Income(Loss)                      -         -          -           -          (2,374)         -     (2,374)
Common Stock Dividends . . . . .                      -         -          -      (3,297)              -          -     (3,297)
Preferred Stock Dividends: . . .                      -         -          -         (96)              -          -        (96)
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
BALANCE, DECEMBER 31, 2002 . . .              4,954,857   $19,276   $ 75,347   $  16,171   $      (2,374)  $(16,698)  $ 91,722
                                  ----------------------  --------  ---------  ----------  --------------  ---------  ---------
</TABLE>


The  accompanying  notes  are  an  integral  part  of the consolidated financial
statements.
<TABLE>
<CAPTION>

CONSOLIDATED  CAPITALIZATION  DATA
GREEN  MOUNTAIN  POWER  CORPORATION  At  December  31,
                                                    SHARES
                                               ISSUED AND OUTSTANDING
                                               ----------------------
                                    AUTHORIZED   2002       2001       2002      2001
----------------------------------  ----------  ---------  ---------  -------
                                                                       (In thousands)
<S>                                 <C>         <C>        <C>        <C>      <C>
COMMON STOCK
Common Stock, $3.33 1/3 par value.  10,000,000  4,954,857  5,685,154  $19,276  $19,004
                                                                      =======  =======
</TABLE>


<TABLE>
<CAPTION>
                                                                   OUTSTANDING
                                                                    -----------

                                             AUTHORIZED   ISSUED   2002    2001   2002    2001
---------------------------------------  ---------------  --------  ----  -------  -----
                                                     Shares                       (In thousands)
                                         ---------------------------------------
<S>                                      <C>              <C>       <C>   <C>      <C>    <C>
REDEEMABLE CUMULATIVE PREFERRED STOCK,
100 PAR VALUE
4.75%, Class B, redeemable at
101 per share. . . . . . . . . . . . .           15,000    15,000   850    1,150  $  85  $   115
7%, Class C . . . . . . . . . . . . . .           15,000    15,000     -    2,850      -      285
9.375%, Class D, Series 1,. . . . . . .           40,000    40,000     -    1,600      -      160
7.32%, Class E, Series 1. . . . . . . .          200,000   120,000     -  120,000      -   12,000
                                                                                   -----  -------
TOTAL PREFERRED STOCK . . . . .                                . . . .  $            85  $ 12,560
                                                                         ===============  ========
</TABLE>


<TABLE>
<CAPTION>


                                                              2002     2001
                                                            --------  -------
(In thousands)
<S>                                                         <C>       <C>
LONG-TERM DEBT
Fleet/Key Term Loan due August 2003. . . . . . . . . . . .  $      -  $12,000
FIRST MORTGAGE BONDS
6.29% Series due 2002. . . . . . . . . . . . . . . . . . .         -    8,000
6.41% Series due 2003. . . . . . . . . . . . . . . . . . .     8,000    8,000
10.0% Series due 2004. . . . . . . . . . . . . . . . . . .         -    5,100
7.05% Series due 2006. . . . . . . . . . . . . . . . . . .     4,000    4,000
7.18% Series due 2006. . . . . . . . . . . . . . . . . . .    10,000   10,000
6.7% Series due 2018 . . . . . . . . . . . . . . . . . . .    15,000   15,000
9.64% Series due 2020. . . . . . . . . . . . . . . . . . .     9,000    9,000
8.65% Series due 2022 - Cash sinking fund, commences 2012.    13,000   13,000
6.04 % Series due 2017-Cash sinking fund commences 2011. .    42,000        -
                                                            --------  -------
Total Long-term Debt Outstanding . . . . . . . . . . . . .   101,000   84,100
Less Current Maturities (due within one year). . . . . . .     8,000    9,700
                                                            --------  -------
TOTAL LONG-TERM DEBT, LESS CURRENT MATURITIES. . . . . . .  $ 93,000  $74,400
                                                            ========  =======
</TABLE>


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

Notes  to  Consolidated  Financial  Statements

A.  SIGNIFICANT  ACCOUNTING  POLICIES

     1.  Organization  and  Basis  of  Presentation.  Green  Mountain  Power
Corporation  (the  "Company")  is  an  investor-owned  electric services company
located  in  Vermont  with  a  principal  service  territory  that  includes
approximately  one-quarter of Vermont's population.  Nearly all of the Company's
net  income  is  generated  from  retail sales in its regulated electric utility
operation,  which  purchases  and generates electric power and distributes it to
approximately  88,000  customers.  At  December  31, 2002, the Company's primary
unregulated  subsidiary  investment  was Northern Water Resources, Inc. ("NWR"),
which  had  invested  in  energy  generation,  energy  efficiency and wastewater
treatment  projects  across the United States.  In 2000, the Company disposed of
most  of  the  assets of NWR.  Green Mountain Power Investment Company ("GMPIC")
was created in December 2002 to hold the Company's investments in Vermont Yankee
Nuclear  Power Corporation ("Vermont Yankee" or "VY") and Vermont Electric Power
Company,  Inc.  ("VELCO").  The  Company's  remaining wholly owned subsidiaries,
which  are  not  regulated  by  the  Vermont Public Service Board ("VPSB" or the
"Board"),  are Green Mountain Resources, Inc. ("GMRI"), which sold its remaining
interest  in  Green Mountain Energy Resources in 1999 and is currently inactive,
Green  Mountain  Propane  Gas  Company ("GMPG") and GMP Real Estate Corporation.
The  results  of  these  subsidiaries and the Company's unregulated rental water
heater  program,  excluding  NWR,  are  included  in  earnings of affiliates and
non-utility  operations  in  the  Other  (Deductions)  Income  section  of  the
Consolidated  Statements  of Income.  Summarized financial information for these
subsidiaries,  and  the Company's unregulated water heater program, which earned
approximately  $0.3  million  in  2002  is  as  follows:
<TABLE>
<CAPTION>


                               Years ended December 31,
              2002    2001    2000
              -----  ------  ------
In thousands
<S>           <C>    <C>     <C>
Revenue. . .  $ 997  $1,012  $1,034
Expense. . .    744     749  $  696
              -----  ------  ------
Net Income .  $ 253  $  263  $  338
              =====  ======  ======
</TABLE>

The  Company  accounts  for  its  investments  in  VY,  VELCO,  New  England
Hydro-Transmission  Corporation,  and  New  England  Hydro-Transmission Electric
Company  using  the equity method of accounting.  The Company's share of the net
earnings  or  losses  of  these  companies  is also included in the Other Income
section  of  the  Consolidated  Statements of Income.  See Note B and Note L for
additional  information.

     2.  Regulatory  Accounting.  The  Company's  utility  operations, including
accounting  records,  rates,  operations  and  certain  other  practices  of its
electric  utility  business,  are  subject  to  the  regulatory authority of the
Federal  Energy  Regulatory  Commission  ("FERC")  and  the  VPSB.
          The  accompanying  consolidated  financial  statements  conform  to
accounting  principles  generally  accepted  in  the United States applicable to
rate-regulated  enterprises in accordance with Statement of Financial Accounting
Standards  No.  ("SFAS")  71  ("SFAS  71"),  "Accounting  for  Certain  Types of
Regulation".  Under  SFAS  71,  the Company accounts for certain transactions in
accordance  with permitted regulatory treatment.  As such, regulators may permit
incurred  costs,  typically  treated  as expenses by unregulated entities, to be
deferred  and  expensed  in  future  periods  when recovered in future revenues.
Conditions  that  could  give  rise  to  the  discontinuance  of SFAS 71 include
increasing  competition that restricts the Company's ability to recover specific
costs,  and  a  change  in  the manner in which rates are set by regulators from
cost-based  regulation  to  another  form  of regulation.  In the event that the
Company  no  longer  meets  the  criteria  under  SFAS  71, the Company would be
required to write off related regulatory assets and liabilities as summarized in
the  following  table:
<TABLE>
<CAPTION>

SFAS  71  Deferred  charges
                                        At December 31,
                               2002     2001
                              -------  -------
(in thousands)
<S>                           <C>      <C>
Power Supply Derivative. . .  $18,405  $37,313
Pine Street Barge Canal. . .   13,019   12,425
Power Supply . . . . . . . .    4,492    6,112
Demand Side Management . . .    6,434    6,961
Preliminary Survey . . . . .    1,202    1,094
Storm Damages. . . . . . . .    1,905    2,169
Regulatory Commission costs.    1,774      873
Tree Trimming. . . . . . . .      905      905
Restructuring Costs. . . . .    2,216    3,502
Other. . . . . . . . . . . .    1,242    1,114
                              -------  -------
Total Deferred Charges . . .  $51,594  $72,468
                              =======  =======
</TABLE>
The  Company  continues  to  believe, based on current regulatory circumstances,
that the use of regulatory accounting under SFAS 71 remains appropriate and that
its  regulatory  assets  are  probable  of  recovery.  Regulatory  entities that
influence the Company include the VPSB, the Vermont Department of Public Service
("DPS"  or  the  "Department"),  and  the  Federal  Energy Regulatory Commission
("FERC"),  among  other  federal,  state  and  local  regulatory  agencies.

      3.  Impairment. The Company is required to evaluate long-lived assets,
including  regulatory  assets,  for  potential  impairment.  Assets  that are no
longer probable of recovery through future revenues would be revalued based upon
future  cash  flows.  Regulatory  assets are charged to expense in the period in
which  they are no longer probable of future recovery.  As of December 31, 2002,
based  upon  the  regulatory  environment  within  which  the  Company currently
operates,  the  Company  does  not  believe  that  an  impairment loss should be
recorded.  Competitive  influences  or  regulatory  developments may impact this
status  in  the  future.

     4.  Utility  Plant.  The  cost  of  plant  additions  includes  all
construction-related  direct  labor  and  materials,  as  well  as  indirect
construction  costs,  including  the  cost  of  money ("Allowance for Funds Used
During Construction" or "AFUDC").  As part of a rate agreement with the DPS, the
Company discontinued recording AFUDC on construction work in progress in January
2001.  The costs of renewals and improvements of property units are capitalized.
The  costs  of maintenance, repairs and replacements of minor property items are
charged  to  maintenance  expense.  The  costs of units of property removed from
service,  net  of  removal  costs  and  salvage,  are  charged  to  accumulated
depreciation.

     5.  Depreciation.  The  Company  provides  for  depreciation  using  the
straight-line  method  based on the cost and estimated remaining service life of
the  depreciable  property outstanding at the beginning of the year and adjusted
for  salvage  value  and  cost  of  removal  of  the  property.
          The annual depreciation provision was approximately 3.2 percent at the
beginning of 2002, 3.5 percent of total depreciable property at the beginning of
2001,  and  3.5  percent  at  the  beginning  of  2000.

     6. Cash and Cash Equivalents.  Cash and cash equivalents include short-term
investments  with  original  maturities  less  than  ninety  days.

     7.  Operating Revenues.  Operating revenues consist principally of sales of
electric  energy  at regulated rates.  Revenue is recognized when electricity is
delivered.  The Company accrues utility revenues, based on estimates of electric
service  rendered and not billed at the end of an accounting period, in order to
match  revenues  with  related  costs.

     8.  Deferred  Charges.  Prior  to  the  sale  of  the Vermont Yankee ("VY")
nuclear generating plant (See Note B) the Company deferred and amortized certain
replacement power, maintenance and other costs associated with outages at the VY
generating  plant.  In  addition,  the  Company  accrued  and  amortized  other
replacement  power  expenses  to  reflect more accurately its cost of service to
better  match  revenues  and expenses consistent with regulatory treatment.  The
Company  also  defers  and amortizes costs associated with its investment in its
demand  side  management  program  and  other  regulatory  assets,  in  a manner
consistent  with  authorized  or  expected  ratemaking  treatment.
     Other  deferred charges totaled $11.4 million and $12.3 million at December
31,  2002  and  2001,  respectively, consisting of regulatory deferrals of storm
damages,  rights-of-way maintenance, other employee benefits, preliminary survey
and  investigation charges, transmission interconnection charges, regulatory tax
assets  and  various  other  projects  and  deferrals.

     9.  Earnings  Per  Share.  Earnings  per  share  are  based on the weighted
average  number  of common and common stock equivalent shares outstanding during
each  year.  During  the year ended December 31, 2000, the Company established a
stock  incentive plan for all employees, and granted 335,300 options exercisable
over vesting schedules of between one and four years.  During 2002 and 2001, the
Company granted additional options of 80,300 and 56,450, respectively.  See Note
C for additional information.  SFAS 123 requires disclosure of pro-forma
information  regarding  net  income  and  earnings  per  share.  The information
presented below has been determined as if the Company accounted for its employee
and  director  stock  options  under  the  fair  value method of that statement.

<TABLE>
<CAPTION>

Pro-forma  net  income  (loss)       For  the  years  ended December 31,
                                          2002     2001      2000
                                         -------  -------  --------
In thousands, except per share amounts
<S>                                      <C>      <C>      <C>
Net income (loss) reported. . . . . . .  $11,398  $10,678  $(6,854)
Pro-forma net income (loss) . . . . . .  $11,246  $10,527  $(6,911)
Net income (loss) per share
  As reported-basic . . . . . . . . . .  $  2.04  $  1.90  $ (1.25)
  Pro-forma basic . . . . . . . . . . .  $  2.01  $  1.87  $ (1.26)
  As reported-diluted . . . . . . . . .  $  1.98  $  1.85  $ (1.25)
  Pro-forma diluted . . . . . . . . . .  $  1.95  $  1.82  $ (1.26)
</TABLE>

10.  Major  Customers.  The Company had one major retail customer, International
Business  Machines  Corporation  ("IBM"),  that accounted for 25.7 percent, 26.6
percent,  and  26.6  percent of retail MWh sales, and 17.3 percent, 19.2 percent
and  16.5  percent  of the Company's retail operating revenues in 2002, 2001 and
2000,  respectively.

     11.  Fair  Value  of  Financial  Instruments.  The  present  value  of  the
Company's  first  mortgage  bonds and preferred stock outstanding, if refinanced
using  prevailing  market  rates  of  interest, would decrease from the balances
outstanding  at December 31, 2002 by approximately 4.7 percent.  In the event of
such  a  refinancing,  there  would be no gain or loss because under established
regulatory  precedent,  any such difference would be reflected in rates and have
no  effect  upon  net  income.

     12. Deferred Credits.  At December 31, 2002, the Company had other deferred
credits  and  long-term liabilities of $21.8 million, consisting of reserves for
damage  claims  and  accruals  for employee benefits, compared with a balance of
$18.2  million  at  December  31,  2001.
          13.  Environmental  Liabilities.  The  Company  is subject to federal,
state  and  local  regulations  addressing  air and water quality, hazardous and
solid  waste  management  and  other  environmental  matters.  Only  those  site
investigation,  characterization  and  remediation  costs  currently  known  and
determinable can be considered "probable and reasonably estimable" under SFAS 5,
"Accounting  for  Contingencies".  As  costs  become  probable  and  reasonably
estimable,  reserves  are  adjusted  as  appropriate.  As reserves are recorded,
regulatory  assets  are  recorded  to  the extent environmental expenditures are
expected  to  be recovered in rates.  Estimates are based on studies provided by
third  parties.
          14.  Income  Taxes.  The Company recognizes tax assets and liabilities
according  to SFAS 109, "Accounting for Income Taxes", for the cumulative effect
of  all  temporary  differences between financial statement carrying amounts and
the tax basis of assets and liabilities.  Investment tax credits associated with
utility  plant  are deferred and amortized over the lives of the related assets.
Valuation  allowances  are  provided when necessary against certain deferred tax
assets.
          15.  Purchased  Power.  The  Company  records the annual cost of power
obtained  under  long-term  contracts  as  operating  expenses.
           SFAS  133  establishes  accounting  and reporting standards requiring
that  every  derivative  instrument  (including  certain  derivative instruments
embedded in other contracts) be recorded on the balance sheet as either an asset
or  liability measured at its fair value.  SFAS 133 requires that changes in the
derivative's  fair  value  be  recognized  currently in earnings unless specific
hedge  accounting  criteria  are  met.  SFAS  133,  as  amended by SFAS 137, was
effective  for  the  Company  beginning  2001.
               One  objective  of  the  Company's  risk management program is to
stabilize cash flow and earnings by minimizing power supply risks.  Transactions
permitted  by  the  risk  management program include futures, forward contracts,
option  contracts, swaps and transmission congestion rights with counter-parties
that  have  at  least  investment grade ratings.  These transactions are used to
mitigate  the  risk  of fossil fuel and spot market electricity price increases.
The  Company's  risk  management  policy  specifies risk measures, the amount of
tolerable  risk  exposure,  and  authorization  limits  for  transactions.
      On  April  11, 2001, the VPSB issued an accounting order that requires the
Company  to  defer  recognition  of  any  earnings or other comprehensive income
effects  relating  to  future  periods  caused  by  application of SFAS 133.  At
December  31, 2002, the Company had a liability reflecting the net negative fair
value  of  the  two  derivatives  described  below,  as  well as a corresponding
regulatory  asset of approximately $18.4 million.  The Company believes that the
regulatory asset, determined using the Black's or Black-Scholes option valuation
method,  is  probable  of recovery in future rates.  The regulatory liability is
based  on current estimates of future market prices that are likely to change by
material  amounts.
          If  a derivative instrument is terminated early because it is probable
that  a  transaction  or forecasted transaction will not occur, any gain or loss
would  be recognized in earnings immediately.  For derivatives held to maturity,
the  earnings impact would be recorded in the period that the derivative is sold
or  matures.
               The  Company  has  a  contract with Morgan Stanley Capital Group,
Inc. ("MS") used to hedge against increases in fossil fuel prices.  MS purchases
the  majority  of  the  Company's  power  supply resources at index (fossil fuel
resources) or specified (i.e., contracted resources) prices and then sells to us
at  a  fixed  rate  to  serve  pre-established load requirements.  This contract
allows  management  to  fix  the  cost of much of its power supply requirements,
subject  to  power  resource availability and other risks.  The MS contract is a
derivative  under  SFAS  133  and  is  effective  through  December  31,  2006.
Management's  estimate  of  the  fair  value  of  the future net benefit of this
contract  at  December  31,  2002  is  approximately  $8.8  million.
            We  currently have an arrangement that grants Hydro-Quebec an option
("9701")  to  call  power  at  prices  below current and estimated future market
rates.  This  arrangement  is  a  derivative  and  is  effective  through  2015.
Management's  estimate  of  the  fair  value  of  the  future  net cost for this
arrangement at December 31, 2002 is approximately $27.2 million.  We use futures
contracts  to  hedge  the  9701  call  option.
     16.  Use  of  Estimates.  The  preparation  of  financial  statements  in
conformity  with  accounting  principles generally accepted in the United States
requires  the  use  of  estimates  and  assumptions  that  affect  assets  and
liabilities,  the  disclosure of contingent assets and liabilities, and revenues
and  expenses.  Actual  results  could  differ  from  those  estimates.

     17.  Reclassifications.  Certain  items  on  the  prior year's consolidated
financial  statements  have  been reclassified to be consistent with the current
year  presentation.


          18. New Accounting Standards.  In June 2001, the FASB issued Statement
of  Financial  Accounting Standards No. 141, Business Combinations ("SFAS 141"),
and  Statement  of  Financial  Accounting  Standards No. 142, Goodwill and Other
Intangible  Assets  ("SFAS  142").  SFAS  141  requires  the use of the purchase
method  to  account  for business combinations initiated after June 30, 2001 and
uses  a  non-amortization  approach  to  purchased  goodwill  and  other
indefinite-lived  intangible  assets.  Under  SFAS  142,  effective  for  2002,
goodwill and intangible assets deemed to have indefinite lives will no longer be
amortized  and  will  be subject to annual impairment tests.  The application of
these  accounting  standards  does not materially impact the Company's financial
position  or  results  of  operations.
          In  August  2001,  the  FASB  issued Statement of Financial Accounting
Standards  No.  143, "Accounting for Asset Retirement Obligations" ("SFAS 143"),
effective  for  fiscal  years  beginning  after  June  15,  2002, which provides
guidance  on  accounting  for  nuclear  plant  decommissioning  and  other asset
retirement  costs.  SFAS  143  prescribes  fair  value  accounting  for  asset
retirement  liabilities,  including  nuclear  decommissioning  obligations,  and
requires  recognition of such liabilities at the time incurred.  The application
of  this  accounting standard is not expected to materially impact the Company's
financial  position  or  results  of  operations.
          In  October  2001,  the  FASB issued Statement of Financial Accounting
Standards  No.  144,  "Accounting  for  the Impairment or Disposal of Long-lived
Assets"  ("SFAS  144").  SFAS  144  specifies  accounting  and reporting for the
impairment or disposal of long-lived assets.  The application of this accounting
standard  does not materially impact the Company's financial position or results
of  operations.
               In  June  2002, the FASB issued Statement of Financial Accounting
Standards  No.  146,  "Accounting  for  Costs  Associated  with Exit or Disposal
Activities" ("SFAS 146").  SFAS 146 specifies accounting and reporting for costs
associated with exit or disposal activities.  The application of this accounting
standard,  which  is effective for us during 2003, is not expected to materially
impact  the  Company's  financial  position  or  results  of  operations.
          In  December  2002,  the FASB issued Statement of Financial Accounting
Standards  No.  148,  "Accounting  for  Stock-based  Compensation-Transition and
Disclosure"  ("SFAS  148").  SFAS  148  amends Statement of Financial Accounting
Standards  No.  123,  "Accounting  for  Stock-Based  Compensation",  to  provide
alternative methods of transition for a voluntary change to the fair value based
method  of  accounting and reporting for stock-based employee compensation.  The
application of this accounting standard is not expected to materially impact the
Company's  financial  position  or  results  of  operations.


B.  INVESTMENTS  IN  ASSOCIATED  COMPANIES

          The  Company  accounts  for  investments  in  the following associated
companies  by  the  equity  method:

<TABLE>
<CAPTION>

                                          PERCENT OWNERSHIP INVESTMENT IN EQUITY
                                            AT DECEMBER 31,   AT DECEMBER 31,
                                             2002      2001     2002    2001
                                           --------  --------  ------  ------
(IN THOUSANDS)
<S>                                        <C>       <C>       <C>     <C>
VELCO-common. . . . . . . . . . . . . . .    28.41%    29.50%  $2,309  $1,932
VELCO-preferred . . . . . . . . . . . . .    30.00%    30.00%     305     420
                                                               ------  ------
Total VELCO . . . . . . . . . . . . . . .                       2,614  2,352

Vermont Yankee- Common. . . . . . . . . .    18.99%    17.88%   9,721   9,725
New England Hydro Transmission-Common . .     3.18%     3.18%     660     761
New England Hydro Transmission Electric-
    Common. . . . . . . . . . . . . . . .     3.18%     3.18%   1,106   1,255
                                                               ------  ------
Total investment in associated companies.                     $14,101  $14,093
                                                             ========  ========
</TABLE>
Undistributed earnings in associated companies totaled approximately $484,000 at
December  31,  2002.

          VELCO.  VELCO is a corporation engaged in the transmission of electric
power  within  the  State  of  Vermont.  VELCO  has  entered  into  transmission
agreements  with  the  State  of Vermont and other electric utilities, and under
these  agreements, VELCO bills all costs, including interest on debt and a fixed
return  on  equity,  to  the State and others using VELCO's transmission system.
The  Company's purchases of transmission services from VELCO were $12.7 million,
$11.5 million, and $9.8 million for the years 2002, 2001 and 2000, respectively.
Pursuant  to VELCO's Amended Articles of Association, the Company is entitled to
approximately 29 percent of the dividends distributed by VELCO.  The Company has
recorded  its  equity in earnings on this basis and also is obligated to provide
its  proportionate  share  of  the  equity capital requirements of VELCO through
continuing  purchases  of  its  common  stock,  if  necessary.
<TABLE>
<CAPTION>

Summarized  unaudited  financial  information  for  VELCO  is  as  follows:
                      At  and  for  the  years  ended  December  31,
                                          2002     2001     2000
                                        --------  -------  -------
  (In thousands)
<S>                                     <C>       <C>      <C>
Net income applicable to common stock.  $  1,094  $ 1,118  $ 1,257
Company's equity in net income . . . .  $    319  $   308  $   395
                                        ========  =======  =======
Total assets . . . . . . . . . . . . .  $106,613  $89,322  $82,123
Less:
Liabilities and long-term debt . . . .    97,417   81,335   73,874
                                        --------  -------  -------
Net assets . . . . . . . . . . . . . .  $  9,196  $ 7,987  $ 8,249
                                        ========  =======  =======
Company's equity in net assets . . . .  $  2,614  $ 2,352  $ 2,456
                                        ========  =======  =======
</TABLE>
VERMONT YANKEE.  On July 31, 2002, Vermont Yankee ("VY") announced that the sale
of  its  nuclear  power  plant to Entergy Nuclear Vermont Yankee ("Entergy") had
been  completed.  See  Note  K  for further information concerning our long-term
power  contract  with  VY.
        During May 2002, prior to the sale of the plant to Entergy, the VY plant
had fuel rods that required repair, a maintenance requirement that is not unique
to  VY.  VY closed the plant for a twelve-day period, beginning on May 11, 2002,
to  repair  the rods.  The Company's share of the cost for the repair, including
incremental  replacement  energy  costs,  was  approximately  $2.0 million.  The
Company  received  an accounting order from the VPSB on August 2, 2002, allowing
it  to  defer the additional costs related to the outage, and believes that such
amounts  are  probable  of  future  recovery.
The  Company's  ownership  share  of  VY  has  increased from approximately 17.9
percent in 2001 to approximately 19.0 percent currently, due to VY's purchase of
certain  minority  shareholders' interests.  The Company's entitlement to energy
produced  by  the  Entergy  Vermont  Yankee  nuclear  plant  has  increased from
approximately  18  percent to 20 percent of plant production through a series of
transactions  in  connection  with  the  sale  of  the  plant  to  Entergy.
The  increase  in  equity  in  earnings  of VY resulted from VY's recognition of
certain  deferred  tax  assets  as  a  result  of the sale of the nuclear plant.


Summarized  unaudited  financial  information  for Vermont Yankee is as follows:
<TABLE>
<CAPTION>
At  and  for  the  years  ended  December  31,
                                            2002      2001      2000
                                          --------  --------  --------
(In thousands)
<S>                                       <C>       <C>       <C>
Earnings:
  Operating revenues . . . . . . . . . .  $175,722  $178,840  $178,294
  Net income applicable to common stock.     9,454     6,119     6,583
  Company's equity in net income . . . .  $  1,745  $  1,131  $  1,177
                                          ========  ========  ========
Total assets . . . . . . . . . . . . . .  $201,616  $723,815  $706,984
Less:
  Liabilities and long-term debt . . . .   150,413   669,640   652,663
                                          --------  --------  --------
Net Assets . . . . . . . . . . . . . . .  $ 51,203  $ 54,175  $ 54,321
                                          ========  ========  ========
Company's equity in net assets . . . . .  $  9,721  $  9,725  $  9,641
                                          ========  ========  ========
</TABLE>
C.  COMMON  STOCK  EQUITY
          The  Company maintains a Dividend Reinvestment and Stock Purchase Plan
("DRIP")  under  which 416,328 shares were reserved and unissued at December 31,
2002.  The  Company also funds an Employee Savings and Investment Plan ("ESIP").
At  December  31, 2002, there were 82,754 shares reserved and unissued under the
ESIP.
     During  2000, the Company's Board of Directors, with subsequent approval of
the  Company's  common  shareholders, established a stock incentive plan.  Under
this plan, options for a total of 500,000 shares may be granted to any employee,
officer,  consultant,  contractor or director providing services to the Company.
Outstanding  options  become exercisable at between one and four years after the
grant  date  and  remain  exercisable  until  10  years  from  the  grant  date.
          As  permitted  by Statement of Financial Accounting Standards No. 123,
"Accounting  for  Stock-Based Compensation ("SFAS 123"), the Company has elected
to  follow Accounting Principles Board Opinion No. 25 ("APB 25") "Accounting for
Stock  Issued  to  Employees", and related interpretations in accounting for its
employee  stock  options.  Under  APB  25, because the exercise price equals the
market  price  of  the  underlying  stock  on the date of grant, no compensation
expense  is recorded.  Options have only been issued to employees and directors.
            The  fair  values  of the options granted in 2002, 2001 and 2000 are
$2.27 $4.16 and $2.03 per share, respectively.  They were estimated at the grant
date using the Black-Scholes option-pricing model.  The following table presents
information  about  the  assumptions  that  were  used for each plan year, and a
summary  of  the  options  outstanding  at  December  31,  2002:

<TABLE>
<CAPTION>

             Weighted                     Assumptions  used  in  option  pricing  model
                                          ---------------------------------------------
             average              Remaining   Risk  Free  Expected  Expected
      Plan  exercise Outstanding  Contractual Interest    Life in    Stock     Dividend
       year    price   options       Life     rate        Years   Volatility   Yield
              -------  -----------  -------  -------  - ----  -----------  -----
<S>        <C>     <C>        <C>       <C>      <C>      <C>    <C>          <C>
 2000        $ 7.90  236,900    7.6 years    6.05%        5  30.58         4.5%
2001         $16.63   50,400    8.6 years    5.25%        6  32.69         4.0%
2002         $17.37   78,500    9.6 years    4.50%      6.5  16.89         4.5%
Total . . .  $11.14   365,800
            =======  =======
</TABLE>
<TABLE>
<CAPTION>
                                        Weighted     Range of
                                Total     Average     Exercise     Options
                                  Options  Price      Prices      Exercisable
                                  -------  ------  -------------  -----------
<S>                               <C>      <C>     <C>            <C>
Outstanding at January 1, 2000 .        -  $    -
Granted. . . . . . . . . . . . .  335,300    7.90  $        7.90
Exercised. . . . . . . . . . . .        -       -
Forfeited. . . . . . . . . . . .    3,400    7.90
Outstanding at December 31, 2000  331,900  $ 7.90  $        7.90            -
                                  -------  ------  -------------  -----------
Granted. . . . . . . . . . . . .   55,450  $16.67  $14.50-$16.78
Granted. . . . . . . . . . . . .    1,000   12.28  $       12.28
Exercised. . . . . . . . . . . .   17,400    7.90  $        7.90
Forfeited. . . . . . . . . . . .    6,800   10.61  $ 7.90-$16.78
Outstanding at December 31, 2001  364,150  $ 9.20  $ 7.90-$16.78       95,350
                                  -------  ------  -------------  -----------
Granted. . . . . . . . . . . . .   80,300   17.82  $16.78-$17.83
Exercised. . . . . . . . . . . .   53,250    8.12  $ 7.90-$16.78
Forfeited. . . . . . . . . . . .   25,400    9.35  $ 7.90-$18.67
Outstanding at December 31, 2002  365,800  $11.23  $ 7.90-$17.82      151,775
                                  =======  ======  =============  ===========
</TABLE>
Options granted are not exercisable until one year after the date of grant.  The
pro-forma  amounts  may  not  be representative of future results and additional
options  may  be  granted in future years.  For 2000, the number of total shares
after  giving  effect to anti-dilutive common stock equivalents does not change.
          The  following  table  presents  a reconciliation of net income to net
income  available  to  common  shareholders,  and  the  average common shares to
average  common  equivalent  shares  outstanding:
<TABLE>
<CAPTION>

         Reconciliation of net income available     For the years ended
           for common shareholders and average shares     December 31,
                                                2002     2001      2000
                                               -------  -------  --------
(in thousands)
<S>                                            <C>      <C>      <C>
Net income (loss) before preferred dividends.  $11,397  $11,611  $(5,840)
Preferred stock dividend requirement. . . . .       96      933    1,014
                                               -------  -------  --------
Net income (loss) applicable to common
   stock. . . . . . . . . . . . . . . . . . .  $11,493  $10,678  $(6,854)
                                               =======  =======  ========

Average number of common shares-basic . . . .    5,592    5,630    5,491
Dilutive effect of stock options. . . . . . .      164      159        -
                                               -------  -------  --------
Average number of common shares-diluted . . .    5,756    5,789    5,491
                                               =======  =======  ========
</TABLE>
During  2000,  the  Compensation Program for Officers and Certain Key Management
personnel,  that  authorized  payment of cash, restricted and unrestricted stock
grants  based  on  corporate  performance, was replaced with the stock incentive
plan discussed above.  Approximately 1,262 restricted shares, issued during 1996
and  1997,  became  vested  under this program during 2002, and no shares remain
unvested  or  unissued  at  December  31,  2002.
          On  November  19,  2002,  the  Company  completed  a  "Dutch  Auction"
self-tender  offer  and  repurchased  811,783 common shares, or approximately 14
percent,  of  its  common  stock  outstanding  for  approximately $16.3 million.
          Dividend  Restrictions.  Certain  restrictions  on the payment of cash
dividends  on common stock are contained in the Company's indentures relating to
long-term  debt  and  in  the  Restated Articles of Association.  Under the most
restrictive of such provisions, approximately $12.1 million of retained earnings
were  free  of  restrictions  at  December  31,  2002.
     The  properties  of  the  Company  include  several  hydroelectric projects
licensed under the Federal Power Act, with license expiration dates ranging from
2001  to  2025.  At  December  31,  2002,  $220,000 of retained deficit had been
appropriated as excess earnings on hydroelectric projects as required by Section
10(d)  of  the  Federal  Power  Act.

D.  PREFERRED  STOCK
          The  holders  of  the  preferred stock are entitled to specific voting
rights  with  respect  to  certain  types  of  corporate actions.  They are also
entitled  to  elect  the  smallest number of directors necessary to constitute a
majority  of  the  Board  of  Directors in the event of preferred stock dividend
arrearages  equivalent to or exceeding four quarterly dividends.  Similarly, the
holders  of the preferred stock are entitled to elect two directors in the event
of  default in any purchase and sinking fund requirements provided for any class
of  preferred  stock.

     The  outstanding  Class B preferred stock is subject to annual purchase and
sinking  fund  requirements.  The  sinking  fund  requirement is mandatory.  The
purchase  fund requirement is mandatory, but holders may elect not to accept the
purchase  offer.  The redemption or purchase price to satisfy these requirements
may  not  exceed  $100 per share plus accrued dividends.  All shares redeemed or
purchased  in connection with these requirements must be canceled and may not be
reissued.  The annual purchase and sinking fund requirements for the outstanding
Class  B preferred stock is 300 shares in 2003 and 2004, and 250 shares in 2005.
     Under  the  Restated  Articles  of  Association  relating  to  Redeemable
Cumulative  Preferred Stock, the annual aggregate amount of purchase and sinking
fund  requirements for the next three years are  $30,000 each for 2003 and 2004,
and  $25,000  for  2005.
          Class B preferred stock is redeemable at the option of the Company or,
in  the  case of voluntary liquidation, at various prices on various dates.  The
prices  include  the  par  value  of the issue plus any accrued dividends and an
early  redemption  premium.  The  redemption  premium  for  Class B is $1.00 per
share.  During  2002,  the  Company  repurchased  all  $12.0 million of the 7.32
percent  Class  E  preferred  stock  outstanding.  On  May  1, 2002, the Company
redeemed  $0.3  million  of the 7.0 percent Class C preferred stock outstanding.
During  November  2002,  the  Company redeemed the remaining $0.2 million of the
9.375  percent  Class  D  preferred  stock  outstanding.

E.  SHORT-TERM  DEBT
          The  Company  has  a  $20.0 million 364-day revolving credit agreement
with  Fleet  Financial Services ("Fleet") joined by KeyBank National Association
("KeyBank"),  expiring  June  2003  (the  "Fleet-Key Agreement").  The Fleet-Key
Agreement  is  unsecured,  and allows the Company to choose any blend of a daily
variable  prime  rate and a fixed term LIBOR-based rate.  There was $2.5 million
outstanding  at  a  weighted  average  rate  of 4.25 percent under the Fleet-Key
Agreement  at  December  31,  2002.  There  was  no  non-utility short-term debt
outstanding  at  December  31,  2002  or  2001.
          The Fleet-Key Agreement requires the Company to certify on a quarterly
basis  that  it  has  not suffered a "material adverse change".  Similarly, as a
condition  to  further  borrowings,  the  Company must certify that no event has
occurred or failed to occur that has had or would reasonably be expected to have
a  materially adverse effect on the Company since the date of the last borrowing
under this agreement.  The Fleet-Key Agreement allows the Company to continue to
borrow  until  such  time  that:
*     a  "material  adverse  effect"  has  occurred;  or
*     the Company no longer complies with all other provisions of the agreement,
in  which  case  further  borrowing  will  not  be  permitted;  or
*     there  has  been  a "material adverse change," in which case the banks may
declare  the  Company  in  default.

F.  LONG-TERM  DEBT
          On December 16, 2002, the Company issued through private placement $42
million  principal  amount  of  first  mortgage  bonds  bearing interest at 6.04
percent  per year and maturing on December 1, 2017.  The average duration of the
bond  issuance  is  twelve years and the bonds are subject to seven equal annual
principal  payments beginning on December 1, 2011.  Proceeds were used to retire
all of the Company's short and intermediate term debt, and to repurchase 811,783
shares  of  the  Company's  common  stock.
          Substantially  all  of  the property and franchises of the Company are
subject  to the lien of the indenture under which first mortgage bonds have been
issued.  The  weighted  average rate on long-term borrowings outstanding was 7.0
percent and 7.1 percent at December 31, 2002 and 2001, respectively.  The annual
sinking  fund  requirements (excluding amounts that may be satisfied by property
additions) and long-term debt maturities for the next five years, as of December
31,  2002,  are:
<TABLE>
<CAPTION>
                                       Sinking
                                       Fund and

                      Maturities
                      -----------
<S>                   <C>

2003 . . . . . . . .  $     8,000
2004 . . . . . . . .            -
2005 . . . . . . . .            -
2006 . . . . . . . .       14,000
2007 . . . . . . . .            -
Thereafter . . . . .       79,000
Total Long-term debt  $   101,000
                      ===========
</TABLE>





On  March  15,  2002,  the  Company redeemed the outstanding $5.1 million, 10.0%
first  mortgage  bonds  due  June  1,  2004.
          The  Company  executed  and  delivered  a  $12.0  million,  two-year,
unsecured  loan  agreement  with  Fleet,  joined by KeyBank, on August 24, 2001.
This  $12.0  million  loan  was  repaid  on  December  16,  2002.
          On August 29, 2002, Moody's upgraded the Company's senior secured debt
rating  to  Baa1 from Baa2.  The outlook for the rating is stable.  On September
29,  2002,  Fitch  Ratings  upgraded  the rating of the Company's first mortgage
bonds  to BBB+ from BBB, with a stable outlook.  On September 23, 2002, Standard
and  Poor's  Ratings  Services  affirmed  its BBB rating of the Company's senior
secured  debt,  with  a  stable  outlook.



G.  INCOME  TAXES

     Utility.  The Company accounts for income taxes using the liability method.
This  method  accounts  for deferred income taxes by applying statutory rates to
the  differences  between  the  book  and  tax  bases of assets and liabilities.

          The regulatory tax assets and liabilities represent taxes that will be
collected  from or returned to customers through rates in future periods.  As of
December  31,  2002  and  2001,  the  net  regulatory assets were $1,042,000 and
$1,096,000,  respectively,  and  included  in  Other  Deferred  Charges  on  the
Company's  consolidated  balance  sheets.
          The  temporary  differences  which  gave  rise to the net deferred tax
liability  at  December  31,  2002  and  December  31,  2001,  were  as follows:
<TABLE>
<CAPTION>

                   AT  DECEMBER  31,

                                        2002     2001
                                       -------  -------
(In thousands)
<S>                                    <C>      <C>
DEFERRED TAX ASSETS
Contributions in aid of construction.  $11,130  $10,435
Deferred compensation and
     postretirement benefits. . . . .    4,570    4,382
Self insurance and other reserves . .    1,369        -
Other . . . . . . . . . . . . . . . .    3,032    5,525
                                       -------  -------
                                       $20,101  $20,342
                                       -------  -------

DEFERRED TAX LIABILITIES
Property related. . . . . . . . . . .  $41,967  $39,518
Demand side management. . . . . . . .    1,870    2,059
Deferred purchased power costs. . . .      943    1,450
Pine Street reserve . . . . . . . . .    1,792      855
Other . . . . . . . . . . . . . . . .        -      219
                                       -------  -------
                                       $46,572  $44,101
                                       -------  -------
  Net accumulated deferred income
    tax liability . . . . . . . . . .  $26,471  $23,759
                                       =======  =======
</TABLE>
The following table reconciles the change in the net accumulated deferred income
tax  liability  to  the  deferred  income  tax  expense  included  in the income
statement  for  the  periods  presented:
<TABLE>
<CAPTION>

                                    YEARS  ENDED  DECEMBER  31,
                                         2002      2001    2000
                                       --------  --------  -----
(In thousands)
<S>                                    <C>       <C>       <C>
Net change in deferred income tax . .  $ 2,712   $(1,885)  $ 443
  liability
Change in income tax related
  regulatory assets and liabilities .    2,759    (1,149)    184
Change in alternative minimum
  tax credit. . . . . . . . . . . . .        -         -       -
Change in tax effect of accumulated
  other comprehensive income. . . . .   (1,612)        -       -
                                       --------  --------  -----
Deferred income tax expense (benefit)  $ 3,859   $(3,034)  $ 627
                                       ========  ========  =====
</TABLE>

The  components  of  the  provision  for  income  taxes  are  as  follows:
<TABLE>
<CAPTION>

                  YEARS  ENDED  DECEMBER  31,

                                 2002      2001      2000
                                -------  --------  --------
(In thousands)
<S>                             <C>      <C>       <C>
Current federal income taxes .  $1,873   $ 7,846   $  (786)
Current state income taxes . .     593     2,418      (249)
                                -------  --------  --------
Total current income taxes . .   2,466    10,264    (1,035)
Deferred federal income taxes.   2,920    (2,296)      461
Deferred state income taxes. .     939      (738)      166
                                -------  --------  --------
Total deferred income taxes. .   3,859    (3,034)      627
Investment tax credits-net . .    (282)     (282)     (283)
                                -------  --------  --------
Income tax provision (benefit)  $6,043   $ 6,948   $  (691)
                                =======  ========  ========
</TABLE>
Total  income  taxes  differ  from  the amounts computed by applying the federal
statutory  tax rate to income before taxes.  The reasons for the differences are
as  follows:

<TABLE>
<CAPTION>

                                                YEARS ENDED DECEMBER 31,
                                                 2002      2001      2000
                                               --------  --------  --------
(In thousands)
<S>                                            <C>       <C>       <C>
Income (loss) before income taxes and
  preferred dividends . . . . . . . . . . . .  $17,537   $18,559   $(6,531)
Federal statutory rate. . . . . . . . . . . .     34.0%     35.0%     34.0%
Computed "expected" federal income
  taxes . . . . . . . . . . . . . . . . . . .    5,963     6,496    (2,221)
Increase (decrease) in taxes resulting from:
Tax versus book depreciation. . . . . . . . .       41        45        83
Dividends received and paid credit. . . . . .     (575)     (440)     (435)
AFUDC-equity funds. . . . . . . . . . . . . .      (80)      (72)      (33)
Amortization of ITC . . . . . . . . . . . . .     (282)     (282)     (282)
State tax (benefit) . . . . . . . . . . . . .    1,011     1,705       (83)
Excess deferred taxes . . . . . . . . . . . .      (60)      (60)      (60)
Tax attributable to subsidiaries. . . . . . .      (31)       63     2,213
Other . . . . . . . . . . . . . . . . . . . .       56      (507)      127
                                               --------  --------  --------
Total federal and state income tax (benefit).  $ 6,043   $ 6,948   $  (691)
                                               ========  ========  ========
Effective combined federal and state
  income tax rate . . . . . . . . . . . . . .     34.5%     37.4%     10.6%
</TABLE>

Non-Utility.  The  Company's  non-utility  subsidiaries,  excluding  NWR,  had
accumulated  deferred  income  taxes  of  approximately  $2,000 on their balance
sheets  at  December  31, 2002, attributable to depreciation timing differences.
          The  components  of the provision for the income tax expense (benefit)
for  the  non-utility  operations,  excluding  NWR,  are:
<TABLE>
<CAPTION>


                               YEARS ENDED DECEMBER 31,
                                      2002              2001   2000
                              --------------------------  ------  -----
<S>                           <C>                         <C>     <C>
    (In thousands)
State income taxes . . . . .  $                      (1)  $   -   $   7
Federal income taxes . . . .                         (3)     (1)     21
                              --------------------------  ------  -----
Income tax expense (benefit)  $                      (4)  $  (1)  $  28
                              ==========================  ======  =====
</TABLE>
          The  effective  combined  federal  and  state  income tax rate for the
continuing  non-utility  operations was approximately 40 percent for each of the
years  ended  December  31,  2002,  2001  and  2000.  See  Note L for income tax
information  on  the  discontinued  operations  of  NWR.

H.  PENSION  AND  RETIREMENT  PLANS.

     The  Company  has a defined benefit pension plan covering substantially all
of  its employees.  The retirement benefits are based on the employees' level of
compensation and length of service.  The Company's policy is to fund all accrued
pension  costs.  The Company records annual expense and accounts for its pension
plan  in  accordance  with  Statement  of Financial Accounting Standards No. 87,
Employers'  Accounting  for  Pensions.  The Company provides certain health care
benefits  for retired employees and their dependents.  Employees become eligible
for  these  benefits if they reach retirement age while working for the Company.
The  Company  accrues  the  cost  of  these  benefits during the service life of
covered employees.  The pension plan assets consist primarily of cash equivalent
funds,  fixed  income  securities  and  equity  securities.
     Due to sharp declines in the equity markets during 2001 and 2002, the value
of  assets  held in trusts to satisfy the Company's pension plan obligations has
decreased.  Fluctuations  in  actual equity market returns as well as changes in
general  interest  rates  may  result in increased or decreased pension costs in
future  periods.
     The  Company's  funding  policy  is  to make voluntary contributions to its
defined  benefit  plans  before  ERISA  or  Pension Benefit Guaranty Corporation
requirements mandate such contributions under minimum funding rules, and so long
as  the Company's liquidity needs do not preclude such investments.  The Company
made  voluntary  pension  plan  contributions  totaling  $1.0  million  between
September  1,  2002  and  December  31,  2002  and  plans  to  make  voluntary
contributions  totaling  an  additional  $1.0  million  by  June  30, 2003.  The
Company's  pension  costs and cash funding requirements could increase in future
years  in  the  absence  of  recovery  in  the  equity  markets.
     As  a  result of GMP's retirement plan asset return experience, at December
31,  2002,  the  Company  has recognized an additional minimum liability of $2.4
million,  net  of  applicable  income taxes, as prescribed by generally accepted
accounting  principles.  The  liability  is  recorded  as  a reduction to common
equity  through  a  charge  to other comprehensive income and did not affect net
income  for  2002.

          Accrued  postretirement health care expenses are recovered in rates to
the  extent  those expenses are funded.  In order to maximize the tax-deductible
contributions  that  are  allowed under IRS regulations, the Company amended its
postretirement  health  care  plan to establish a 401-h sub-account and separate
VEBA trusts for its union and non-union employees.  The VEBA plan assets consist
primarily  of  cash  equivalent  funds,  fixed  income  securities  and  equity
securities.  The  following  provides  a  reconciliation of benefit obligations,
plan  assets,  and  funded status of the plans as of December 31, 2002 and 2001.

<TABLE>
<CAPTION>

                                                     At and for the years ended December 31,
                                            Pension Benefits          Other Postretirement Benefits
                                            ----------------          -----------------------------

                                                      2002      2001      2002       2001
                                                    --------  --------  ---------  --------
(In thousands)
Change in projected benefit obligation:
<S>                                                 <C>       <C>       <C>        <C>
Projected benefit obligation as of prior year end.  $25,895   $23,332   $ 16,491   $14,947
Service cost . . . . . . . . . . . . . . . . . . .      668       537        296       241
Interest cost. . . . . . . . . . . . . . . . . . .    1,849     1,737      1,119     1,043
Participant contributions. . . . . . . . . . . . .        -         -        147       151
Change in actuarial assumptions. . . . . . . . . .        -       367          -         -
Actuarial (gain) loss. . . . . . . . . . . . . . .    3,230     1,650      3,619     1,021
Benefits paid. . . . . . . . . . . . . . . . . . .   (1,650)   (1,670)      (965)     (912)
Administrative expense . . . . . . . . . . . . . .      (55)      (58)         -         -
                                                    --------  --------  ---------  --------
Projected benefit obligation as of year end. . . .  $29,937   $25,895   $ 20,707   $16,491
                                                    ========  ========  =========  ========

Change in plan assets:
Fair value of plan assets as of prior year end . .  $24,341   $27,760   $ 10,016   $10,944
Administrative expenses paid . . . . . . . . . . .      (55)      (58)         -         -
Participant contributions. . . . . . . . . . . . .        -         -        147       151
Employer contributions . . . . . . . . . . . . . .    1,000         -        819       761
Actual return on plan assets . . . . . . . . . . .   (2,532)   (1,691)    (1,257)     (928)
Benefits paid. . . . . . . . . . . . . . . . . . .   (1,650)   (1,670)      (965)     (912)
                                                    --------  --------  ---------  --------
Fair value of plan assets as of year end . . . . .  $21,104   $24,341   $  8,760   $10,016
                                                    ========  ========  =========  ========

Funded status as of year end . . . . . . . . . . .  $(8,833)  $(1,554)  $(11,948)  $(6,475)
Unrecognized transition obligation (asset) . . . .      (77)     (241)     3,280     3,608
Unrecognized prior service cost. . . . . . . . . .      839       986       (462)     (519)
Unrecognized net actuarial (gain) loss . . . . . .    6,982      (892)     8,379     2,711
                                                    --------  --------  ---------  --------
Accrued benefits at year end . . . . . . . . . . .  $(1,089)  $(1,701)  $   (751)  $  (675)
                                                    ========  ========  =========  ========
</TABLE>

The Company also has a supplemental pension plan for certain employees.  Pension
costs  for  the  years  ended  December  31,2002,  2001, and 2000 were $408,000,
$340,000,  and  $346,000, respectively, under this plan.  This plan is funded in
part  through  insurance  contracts.
          Net  periodic  pension  expense and other postretirement benefit costs
include  the  following  components:
<TABLE>
<CAPTION>

                                                         For the years ended December 31,
                                                  Pension Benefits     Other Postretirement Benefits
                                              2002      2001      2000     2002     2001     2000
                                            --------  --------  --------  -------  -------  -------
(In thousands)
<S>                                         <C>       <C>       <C>       <C>      <C>      <C>
Service cost . . . . . . . . . . . . . . .  $   668   $   537   $   655   $  296   $  241   $  216
Interest cost. . . . . . . . . . . . . . .    1,849     1,737     1,658    1,119    1,043    1,049
Expected return on plan assets . . . . . .   (2,112)   (2,379)   (2,580)    (851)    (892)    (940)
Amortization of transition asset . . . . .     (164)     (164)     (164)       -        -        -
Amortization of prior service cost . . . .      147       147       121      (58)     (58)     (58)
Amortization of the transition obligation.        -         -         -      328      328      328
Recognized net actuarial gain. . . . . . .        -      (237)     (474)      60        -        -
                                            --------  --------  --------  -------  -------  -------
    Net periodic benefit cost (income) . .  $   388   $  (359)  $  (784)  $  894   $  662   $  595
                                            ========  ========  ========  =======  =======  =======
</TABLE>

          Assumptions  used  to  determine  postretirement benefit costs and the
related  benefit  obligation  were:
     For measurement purposes, a 10.0 percent annual rate of increase in the per
capita  cost  of  covered  medical  benefits was assumed for 2003.  This rate of
increase  gradually  declines  to  5.5  percent in 2009.  The medical trend rate
assumption  has  a  significant  effect  on  the amounts reported.  For example,
increasing  the  assumed health care cost trend rate by one percentage point for
all  future  years  would  increase  the  accumulated  postretirement  benefit
obligation  as of December 31, 2002 by $3.4 million and the total of the service
and  interest  cost  components of net periodic postretirement cost for the year
ended  December  31,  2002  by  $257,000.  Decreasing  the  trend  rate  by  one
percentage  point  for  all  future  years  would  decrease  the  accumulated
postretirement  benefit obligation at December 31, 2002 by $2.7 million, and the
total of the service and interest cost components of net periodic postretirement
cost  for  2002  by  $202,000.


I.     COMMITMENTS  AND  CONTINGENCIES

     1.  INDUSTRY  RESTRUCTURING.  The  electric  utility  business  is  being
subjected  to  rapidly  increasing  competitive  pressures  stemming  from  a
combination  of  trends.  Certain  states,  including all the New England states
except  Vermont,  have  enacted  legislation to allow retail customers to choose
their  electric  suppliers,  with  incumbent  utilities required to deliver that
electricity  over  their  transmission  and  distribution systems.  Recent power
supply  management  difficulties  in  some  regulatory  jurisdictions,  such  as
California,  have  dampened any immediate push towards de-regulation in Vermont.
Alternative  forms  of performance-based regulation currently appear as possible
intermediate  steps  towards  deregulation.  There  can be no assurance that any
potential  future restructuring plan ordered by the VPSB, the courts, or through
legislation  will  include a mechanism that would allow for full recovery of our
stranded  costs  and  include  a  fair  return  on those costs as they are being
recovered.

   2.  ENVIRONMENTAL MATTERS.  The electric industry typically uses or generates
a  range  of potentially hazardous products in its operations.  The Company must
meet  various  land,  water,  air  and aesthetic requirements as administered by
local,  state  and  federal  regulatory  agencies.  We  believe  that  we are in
substantial  compliance  with  those  requirements,  and  that  there  are  no
outstanding  material complaints about our compliance with present environmental
protection regulations, except for developments related to the Pine Street Barge
Canal  site.  The  Company  maintains an environmental compliance and monitoring
program  that  includes  employee  training,  regular  inspection  of  Company
facilities,  research  and  development  projects,  waste  handling  and  spill
prevention  procedures  and  other  activities.
          Pine Street Barge Canal Site.  The Federal Comprehensive Environmental
Response,  Compensation,  and  Liability  Act  ("CERCLA"), commonly known as the
"Superfund"  law,  generally  imposes  strict,  joint  and  several  liability,
regardless  of  fault,  for  remediation of property contaminated with hazardous
substances.  The  Company  has  been  notified  by  the Environmental Protection
Agency  ("EPA")  that  it  is  one  of  several  potentially responsible parties
("PRPs")  for cleanup of the Pine Street Barge Canal site in Burlington, Vermont
where  coal  tar  and  other  industrial  materials  were  deposited.
          In  September  1999,  we negotiated a final settlement with the United
States, the EPA, the State of Vermont, and other parties over terms of a Consent
Decree  that  covers  claims  addressed  in  the  earlier  negotiations  and
implementation of the selected remedy.  In November 1999, the Consent Decree was
filed in the federal district court.  The Consent Decree addresses claims by the
EPA  for past Pine Street Barge Canal site costs, natural resource damage claims
and  claims  for  past  and  future  oversight  costs.  The  Consent Decree also
provides  for  the  design  and  implementation of response actions at the site.
          As  of  December 31, 2002, the Company's total expenditures related to
the  Pine  Street  Barge Canal site since 1982 were approximately $27.1 million.
This  includes those amounts not recovered in rates, amounts recovered in rates,
and  amounts  for  which  rate  recovery has been sought but which are presently
waiting  further  VPSB  action.  The  bulk  of  these  expenditures consisted of
transaction  costs.  Transaction  costs  include  legal  and  consulting  costs
associated  with  the  Company's opposition to the EPA's earlier and more costly
proposals  for  the  site,  as well as litigation and related costs necessary to
obtain  settlements with insurers and other PRP's to provide amounts required to
fund  the  clean  up  (remediation costs) and to address liability claims at the
site.  A  smaller  amount  of  past  expenditures  was for site-related response
costs,  including  costs  incurred  pursuant  to  the  EPA and State orders that
resulted  in  funding  response activities at the site, and to reimburse the EPA
and  the  State for oversight and related response costs.  The EPA and the State
have  asserted  and  affirmed  that  all  costs  related  to  these  orders  are
appropriate  costs of response under CERCLA for which the Company and other PRPs
were  legally  responsible.
          We  estimate  that  we  have  recovered  or  secured, or will recover,
through  settlements  of  litigation  claims against insurers and other parties,
amounts that exceed estimated future remediation costs, future federal and state
government  oversight  costs and past EPA response costs.  We currently estimate
our  unrecovered  transaction  costs  mentioned  above,  which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $13.0 million over the next 32
years.  The  estimated  liability is not discounted, and it is possible that our
estimate  of  future  costs  could  change  by  a material amount.  We also have
recorded an offsetting regulatory asset, and we believe that it is probable that
we  will  receive  future  revenues to recover these costs.  Although it did not
eliminate  the  rate  base  deferral of these expenditures, or make any specific
order  in  this  regard,  the  VPSB indicated that it was inclined to agree with
other  parties  in  the  case  that  the ultimate costs associated with the Pine
Street  Barge Canal site, taking into account recoveries from insurance carriers
and  other  PRPs,  should  be  shared  between customers and shareholders of the
Company.  In  response  to  our  Motion for Reconsideration, the VPSB on June 8,
1998  stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
The  VPSB  Settlement Order regarding the Company's 1998 retail rate request did
not  change  the  status  of  Pine  Street  cost  recovery.

          Clean Air Act.     The Company purchases most of its power supply from
other  utilities  and does not anticipate that it will incur any material direct
costs  as  a  result  of  the  Federal  Clean  Air Act or proposals to make more
stringent  regulations  under  that  Act.


     3.  JOINTLY-OWNED FACILITIES.  The Company has joint-ownership interests in
electric  generating  and  transmission  facilities  at  December  31,  2002, as
follows:
<TABLE>
<CAPTION>

                          Ownership     Share of     Utility     Accumulated
                          Interest   Capacity        Plant       Depreciation
                          ---------  ---------  ---------------  -------------
                           (In %)    (In MWh)   (In thousands)
<S>                       <C>        <C>        <C>              <C>
Highgate . . . . . . . .       33.8       67.6  $        10,296  $       4,657
McNeil . . . . . . . . .       11.0        5.9            8,989          5,078
Stony Brook (No. 1). . .        8.8         31           10,377          8,521
Wyman (No. 4). . . . . .        1.1        6.8            1,980          1,318
Metallic Neutral Return.       59.4          -            1,563            744
</TABLE>


Metallic  Neutral  Return  is  a  neutral  conductor  for  NEPOOL/Hydro-Quebec
Interconnection
The  Company's  share  of  expenses  for  these  facilities  is reflected in the
Consolidated  Statements  of  Income.  Each participant in these facilities must
provide  its  own  financing.

   4.  RATE  MATTERS.

RETAIL  RATE  CASES-  The  Company reached a final settlement agreement with the
Department  in  its  1998  rate  case during November 2000. The final settlement
agreement  contained  the  following  provisions:

*     The Company received a rate increase of 3.42 percent above existing rates,
beginning  with  bills  rendered  January  23,  2001,  and  prior temporary rate
increases  became  permanent;
*     Rates  were  set at levels that recover the Company's Hydro-Quebec Vermont
Joint  Owners  ("VJO")  contract  costs,  effectively  ending  the  regulatory
disallowances  experienced  by  the  Company  from  1998  through  2000;
*     The  Company  agreed  not  to  seek any further increase in electric rates
prior  to  April  2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a request
for  additional  rate  relief  if power supply costs increase in excess of $3.75
million  over  forecasted  levels;
*     The  Company  agreed  to  write  off in 2000 approximately $3.2 million in
unrecovered rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
*     Seasonal  rates  were  eliminated  in  April  2001,  which  generated
approximately  $8.5 million in additional cash flow in 2001 that can be utilized
to  offset  increased  costs  during  2002  and  2003;
*     The  Company  agreed  to consult extensively with the Department regarding
capital  spending commitments for upgrading our electric distribution system and
to  adopt  customer  care and reliability performance standards, in a first step
toward  possible  development  of  performance-based  rate-making;
*     The  Company  agreed  to  withdraw its Vermont Supreme Court appeal of the
VPSB's  Order  in  the  1997  rate  case;  and
*     The  Company  agreed to an earnings limitation for its electric operations
in  an amount equal to its allowed rate of return of 11.25 percent, with amounts
earned  over  the  limit  being  used  to  write  off  regulatory  assets.


     On  January  23,  2001, the VPSB approved the Company's settlement with the
Department,  with  two  additional  conditions:
*     The Company and customers shall share equally any premium above book value
realized by the Company in any future merger, acquisition or asset sale, subject
to  an  $8.0  million limit on the customers' share, adjusted for inflation; and
*     The  Company's further investment in non-utility operations is restricted.

     The Company earned approximately $4.4 million less than its allowed rate of
return  during  2002 before recognition of deferred revenues in the same amount.

          The  VPSB, in its order approving VY's sale of its nuclear power plant
to  Entergy, ordered the Company and Central Vermont Public Service each to file
on  or before April 15, 2003, a cost-of-service study based on actual 2002 data,
to  enable  the VPSB to determine whether an adjustment to rates is justified in
2003  or  2004.  The  Company  believes  this  filing will support the Company's
current  rates  and  does not intend to request a rate increase or decrease when
this  filing is made.  The VPSB could initiate an investigation of the Company's
rates  based  on this filing, requiring the Company to complete a rate case, and
the  VPSB could order an adjustment to the Company's rates based on its findings
and  conclusions.  If  the VPSB ordered the Company to reduce its rates in  2003
or  2004,  this  could  have a material adverse effect on our operating results,
cash  flows  and  ability  to  pay  dividends  at  current  levels.

     5.  OTHER  DEFERRED  CHARGES  NOT  INCLUDED  IN RATE BASE.  The Company has
incurred  and  deferred  approximately  $11.1  million  in costs for demand side
conservation  programs, tree trimming, storm damage, unscheduled VY outage costs
and  federal regulatory commission work of which $1.2 million is being amortized
on  an  annual  basis.  Currently,  the  Company  amortizes  such costs based on
amounts  being  recovered  and  does  not  receive  a  return on certain amounts
deferred.  Management expects to seek and receive ratemaking treatment for these
costs  in  future  filings.
          The  Settlement  Order  directed  the  Company  to  write-off deferred
charges applicable to the state regulatory commission of $3.2 million as part of
the  rate  case  agreement with the Department.  The charge is included in other
operating  expense  for  the year ended December 31, 2000.  The Settlement Order
requires  the  remaining  balance and future expenditures of deferred regulatory
commission  charges  be  amortized  over  seven  years.

     6.  COMPETITION.     During  2001,  the  Town of Rockingham ("Rockingham"),
Vermont  initiated  inquiries and legal procedures, and on March 5, 2002, voters
in  Rockingham  authorized  the  town  to establish its own electric utility, by
acting  to acquire an existing hydro-generation facility from a third party, and
the  associated  distribution plant owned by the Company within Rockingham.  The
Company  receives  annual  revenues  of  approximately  $4.0  million  from  its
customers  in  Rockingham.  Should  Rockingham  create  a  municipal system, the
Company  would  vigorously  pursue reimbursement such that neither our remaining
customers  nor  our  shareholders  subsidize  Rockingham.

     7.  OTHER LEGAL MATTERS. In a series of Vermont regulatory proceedings, the
Company  has  agreed  to  undertake  a  process  known  as  "distributed utility
planning"  as  part  of  its  transmission  and  distribution  planning process.
Distributed  utility  planning  requires  the  Company  to  evaluate
conservation-related  alternatives  and  distributed  generation alternatives to
typical  transmission  and  distribution  capital  investments.  In  certain
circumstances,  the  Company  may  be  required  to  implement  conservation  or
distributed  generation  alternatives in lieu of, or in addition to, traditional
transmission  and  distribution capital investments, where societal cost savings
associated  with  conservation  or  distributed  generation, including the costs
associated  with  avoided  electricity  sales,  justify  the  expenditures.  The
Company  is uncertain of the potential magnitude of future spending requirements
for  this  program,  but  note  they  could  be material.  Costs associated with
conservation  measures  or  distributed  generation  facilities not owned by the
Company  would be deferred as regulatory assets pending future rate proceedings.
     In  2002,  the  owners  of  property  along the shoreline of Joe's Pond, an
impoundment located in Danville, Vermont, created by the Company's West Danville
Dam  hydroelectric  generating  facility, filed an inquiry with the VPSB seeking
review of certain dam improvements made by the Company in 1995, complaining that
the  Company  did  not  obtain  all  necessary regulatory approvals for the 1995
improvements and that the Company's improvements and subsequent operation of the
dam  have caused flooding of the shoreline and property damage.  The Company has
petitioned  the  VPSB  to make additional dam improvements at the facility at an
estimated cost of $350,000.  The VPSB must approve the Company's petition before
the  proposed  improvements  can  be implemented.  This regulatory proceeding is
pending and the Company is unable to predict whether the Company's petition will
be  approved or whether the VPSB will impose regulatory conditions or penalties.
           The Company is involved in other legal and administrative proceedings
in  the normal course of business and does not believe that the ultimate outcome
of  these  proceedings  will have a material effect on the financial position or
the  results  of  operations  of  the  Company.

J.     OBLIGATIONS  UNDER  TRANSMISSION  INTERCONNECTION  SUPPORT  AGREEMENT

          Agreements  executed in 1985 among the Company, VELCO and other NEPOOL
members  and  Hydro-Quebec  provided  for  the  construction of the second phase
(Phase  II)  of the interconnection between the New England electric systems and
that  of  Hydro-Quebec.  Phase  II  expands  the  Phase  I  facilities  from 690
megawatts to 2,000 megawatts and provides for transmission of Hydro-Quebec power
from  the  Phase  I  terminal  in  northern  New  Hampshire  to  Sandy  Pond,
Massachusetts.  Construction  of Phase II commenced in 1988 and was completed in
late  1990.  The Company is entitled to 3.2 percent of the Phase II power-supply
benefits.  Total  construction  costs  for  Phase  II  were  approximately  $487
million.  The  New  England participants, including the Company, have contracted
to  pay  monthly  their  proportionate  share of the total cost of constructing,
owning  and  operating  the  Phase II facilities, including capital costs.  As a
supporting participant, the Company must make support payments under thirty-year
agreements.  These  support  agreements  meet  the  capital  lease  accounting
requirements.  At  December  31,  2002,  the  present  value  of  the  Company's
obligation  is  approximately  $5.3  million.

          Projected  future  minimum  payments  under  the  Phase  II  support
agreements  are  as  follows:
<TABLE>
<CAPTION>


                       Year ending
                       December 31
                     ---------------
                     (In thousands)
<S>                  <C>
2003. . . . . . . .  $           407
2004. . . . . . . .              407
2005. . . . . . . .              406
2006. . . . . . . .              407
2007. . . . . . . .              407
Total for 2008-2015            3,253
    Total . . . . .  $         5,287
                     ===============
</TABLE>

     The  Phase  II  portion  of  the  project  is  owned  by  New  England
Hydro-Transmission  Electric  Company  and  New  England  Hydro-Transmission
Corporation,  subsidiaries  of  New England Electric System, in which certain of
the  Phase  II  participating  utilities,  including  the  Company,  own  equity
interests.  The  Company  holds  approximately  3.2 percent of the equity of the
corporations  owning  the  Phase  II  facilities.

K.     LONG-TERM  POWER  PURCHASES

     1.  Unit  Purchases.  Under  long-term  contracts  with  various  electric
utilities  in  the  region, the Company is purchasing certain percentages of the
electrical  output  of  production  plants  constructed  and  financed  by those
utilities.  Such  contracts  obligate  the Company to pay certain minimum annual
amounts representing the Company's proportionate share of fixed costs, including
debt  service  requirements  whether or not the production plants are operating.
The  cost  of  power obtained under such long-term contracts, including payments
required when a production plant is not operating, is reflected as "Power Supply
Expenses"  in  the  accompanying  Consolidated  Statements  of  Income.
          Information  (including estimates for the Company's portion of certain
minimum  costs and ascribed long-term debt) with regard to significant purchased
power  contracts  of  this  type  in  effect  during  2002  follows:
<TABLE>
<CAPTION>

                                            STONY
                                            BROOK
                                   -----------------------
                                   (Dollars in thousands)
<S>                                <C>
Plant capacity. . . . . . . . . .                352.0 MW
Company's share of output . . . .                    4.40%
Contract period expires:. . . . .                    2006
Company's annual share of:
  Interest. . . . . . . . . . . .  $                  140
  Other debt service. . . . . . .                     435
  Other capacity. . . . . . . . .                     306
Total annual capacity . . . . . .  $                  881
                                   =======================

Company's share of long-term debt  $                2,314
</TABLE>

2.  Vermont  Yankee
          The  Company  has  a  long-term  power  purchase contract with Vermont
Yankee  Nuclear Power Corporation, which sold its nuclear power plant to Entergy
Nuclear  Vermont  Yankee on July 31, 2002.  The Company is no longer required to
pay  its  proportionate  share of fixed costs associated with the Entergy plant,
including when the plant is not operating, though the Company is responsible for
finding  replacement  power  at  such  times.
          The  VY  sale  of  its  nuclear  power plant to Entergy also calls for
Entergy,  through its power contract with VY, to provide 20 percent of the plant
output to the Company through 2012, which represents approximately 35 percent of
the  Company's  energy requirements.  The Company continues to own approximately
19 percent of the common stock of VY.  Our benefits of the plant sale and the VY
power  contract  with  Entergy  include:
     VY receives cash approximately equal to the book value of the plant assets,
removing  the  potential  for  stranded  costs  associated  with  the  plant.
     VY  and  its  owners  will  no  longer bear operating risks associated with
running  the  plant.
     VY  and  its  owners  will  no  longer  bear  the risks associated with the
eventual  decommissioning  of  the  plant.
     Prices  under  the  Power  Purchase  Agreement  between VY and Entergy (the
"PPA")  range from $39 to $45 per megawatt-hour for the period beginning January
2003,  substantially  lower  than the forecasted cost of continued ownership and
operation  by  VY.  Contract prices ranged from $49 to $55 for 2002, higher than
the  forecasted  cost  of  continued  ownership  for  2002.
     The  PPA  calls for a downward adjustment in the price if market prices for
electricity  fall  by defined amounts beginning no later than November 2005.  If
market  prices  rise,  however,  the  contract  prices  are not adjusted upward.

          A  summary  of  the  PPA,  including  projected  charges for the years
indicated,  follows:
<TABLE>
<CAPTION>

                                         Vermont Yankee

                                          Contract
                                       --------------
<S>                                    <C>             <C>
(Dollars in thousands except per KWh)
Capacity acquired . . . . . . . . . .                  106 MW
Contract period expires . . . . . . .                    2012
Company's share of output . . . . . .                      20%
Annual energy charge. . . . . . . . .  2002(5 months)  $15,965
  estimated . . . . . . . . . . . . .      2003-2015    33,352
Average cost per KWh. . . . . . . . .           2002     0.052
  estimated . . . . . . . . . . . . .      2003-2015     0.042
</TABLE>

     Payments  totaling  $0.5  million  were  made  in  2002 to VY's non-Vermont
sponsors in return for guarantees those sponsors made to Entergy to finalize the
VY  sale.
Although  the  sale  closed  on July 31, 2002, the Company's distribution of the
sale  proceeds  and final accounting for the sale are pending certain regulatory
approvals  and  the  resolution of certain closing items between VY and Entergy.
The  Company  expects  its  share of the VY power plant sale proceeds, currently
estimated  at between $7 million and $8 million, to be distributed in the latter
part  of  2003.
The  sale  required  various  regulatory approvals, all of which were granted on
terms  acceptable  to the parties to the transaction. Certain intervener parties
to  the  VPSB  approval  proceeding  appealed  the  VPSB approval to the Vermont
Supreme  Court.  That  appeal  is  pending.  If  the appellants prevail on their
appeal,  the  VPSB  could  be  required  to conduct additional proceedings or to
reconsider  its  order  approving  the  sale.

     3.  Hydro-Quebec System Power Purchase and Sale Commitments.  Under various
contracts,  the  details  of which are described in the table below, the Company
purchases  capacity  and  associated energy produced by the Hydro-Quebec system.
Such  contracts obligate the Company to pay certain fixed capacity costs whether
or  not  energy  purchases  above a minimum level set forth in the contracts are
made.  Such  minimum  energy  purchases  must be made whether or not other, less
expensive  energy  sources  might be available.  These contracts are intended to
complement  the  other  components  in the Company's power supply to achieve the
most  economic  power supply mix reasonably available.     The Company's current
purchases  pursuant  to  the contract with Hydro-Quebec entered into in December
1987  (the  "1987  Contract") are as follows:  (1) Schedule B -- 68 megawatts of
firm  capacity  and  associated  energy  to  be  delivered  at  the  Highgate
interconnection  for  twenty years beginning in September 1995; and (2) Schedule
C3  --  46  megawatts  of firm capacity and associated energy to be delivered at
interconnections  to  be  determined  at  any  time for 20 years, which began in
November  1995.  There  are specific step-up provisions that provide that in the
event  any 1987 Contract participant fails to meet its obligation under the 1987
Contract  with  Hydro-Quebec, the remaining contract participants, including the
Company,  will  "step-up"  to  the  defaulting participant's share on a prorated
basis.

          Hydro-Quebec  also  has  the  right  to reduce the load factor from 75
percent  to  65  percent under the 1987 Contract a total of three times over the
life  of  the  contract.  The Company can delay such reduction by one year under
the  1987  Contract.  During  2001,  Hydro-Quebec  exercised  the first of these
options  for  2002,  and the Company delayed the effective date of this exercise
until  2003.  The Company estimates that the net cost of Hydro-Quebec's exercise
of  its  option  will increase power supply expense during 2003 by approximately
$0.4  million.
          During  1994,  the Company negotiated an arrangement with Hydro-Quebec
that reduced the cost impacts associated with the purchase of Schedules B and C3
under the 1987 Contract, over the November 1995 through October 1999 period (the
"July 1994 Agreement").  Under the July 1994 Agreement, the Company, in essence,
will  take  delivery of the amounts of energy as specified in the 1987 Contract,
but  the  associated  fixed  costs  will  be  significantly  reduced  from those
specified  in  the  1987  Contract.
          As part of the July 1994 Agreement, we were obligated to purchase $4.0
million  (in  1994  dollars)  worth  of  research  and  development  work  from
Hydro-Quebec  over  a period ending October 1999, which has since been extended,
and  made  an  additional  $6.5  million  (plus  accrued  interest)  payment  to
Hydro-Quebec  in  1995.  Hydro-Quebec retains the right to curtail annual energy
deliveries  by  10  percent  up  to five times, over the 2001 to 2015 period, if
documented  drought  conditions  exist in Quebec.  The period for completing the
research  and  development  purchase  was  subsequently  extended to March 2003.
          During  the  first  year  of  the July 1994 Agreement (the period from
November  1995  through  October  1996),  the  average cost per kilowatt-hour of
Schedules  B  and C3 combined was cut from 6.4 to 4.2 cents per kilowatt-hour, a
34  percent  or  $16 million cost reduction.  Over the period from November 1996
through  December  2000  and  accounting  for  the payments to Hydro-Quebec, the
combined  unit  costs  were  lowered  from  6.5  to 5.9 cents per kilowatt-hour,
reducing  unit  costs  by  10 percent and saving $20.7 million in nominal terms.
          All of the Company's contracts with Hydro-Quebec call for the delivery
of  system  power  and  are  not  related  to  any  particular facilities in the
Hydro-Quebec  system.  Consequently,  there  are  no  identifiable  debt-service
charges  associated  with  any  particular  Hydro-Quebec  facility  that  can be
distinguished  from  the  overall  charges  paid  under  the  contracts.

          A  summary  of  the  Hydro-Quebec  contracts  through  the  July  1994
Agreement,  including  historic  and  projected charges for the years indicated,
follows:
<TABLE>
<CAPTION>

                                                                          THE 1987 CONTRACT
                                                               SCHEDULE B                 SCHEDULE C3
                                                  -------------------------------------  -------------
                                                                (Dollars in thousands except per KWh)
<S>                       <C>                                    <C>            <C>       <C>      <C>
Capacity acquired. . . .                                            68 MW                    46 MW
Contract period. . . . .                                            1995-2015               1995-2015
Minimum energy purchase.                                              75%                       75%
(annual load factor)
Annual energy charge . .                                  2002   $     11,946                 $ 8,163
  estimated. . . . . . .                             2003-2015         13,362        (1)        9,131   (1)
Annual capacity charge .                                  2002   $     16,850                 $11,514
  estimated. . . . . . .                             2003-2015   $     17,122        (1)      $11,700   (1)
Average cost per KWh . .                                  2002   $      0.065                 $ 0.065
  estimated. . . . . . .                             2003-2015   $      0.069        (2)      $ 0.069   (2)
</TABLE>
(1)Estimated  average  includes  load  factor  reduction  to  65 percent in 2003
(2)Estimated  average  in  nominal  dollars  levelized over the period indicated
  includes  amortization of payments to Hydro-Quebec for the July 1994 Agreement


          Under  a  separate arrangement established in December 1997 (the "9701
arrangement"), Hydro-Quebec provided a payment of $8.0 million to the Company in
1997.  In  return  for this payment, the Company provided Hydro-Quebec an option
for  the  purchase  of  power.  Commencing  April 1, 1998, and effective through
October  2015,  Hydro-Quebec can exercise an option to purchase up to 52,500 MWh
("option A") on an annual basis, at energy prices established in accordance with
the  1987  Contract.   The  cumulative amount of energy purchased under the 9701
arrangement  shall  not  exceed  950,000  MWh.  Hydro-Quebec's option to curtail
energy  deliveries pursuant to the 1987 Contract and the July 1994 Agreement may
be  exercised  in  addition  to  these  purchase  options.
          Over the same period, Hydro-Quebec can exercise an option on an annual
basis  to  purchase  a  total  of  600,000 MWh ("option B") at the 1987 Contract
energy  price.  Hydro-Quebec  can purchase no more than 200,000 MWh in any given
contract  year  ending  October  31.  As  of December 31, 2002, Hydro-Quebec had
purchased  or  called  to  purchase  458,000  MWh  under  option  B.
          In  2002, Hydro-Quebec exercised option A and called for deliveries to
third  parties  at  a  net expense to the Company of approximately $3.0 million,
including  capacity  charges.
          In  2001, Hydro-Quebec exercised option A and option B, and called for
deliveries  to  third  parties  at a net expense to the Company of approximately
$6.5  million,  including  capacity  charges.
          In  2000, Hydro-Quebec called for deliveries to third parties at a net
expense to the Company of approximately $14.0 million (including the cost of the
January  and February 2001 calls and related financial positions), which was due
to  higher  energy  replacement costs.  The 9701 arrangement costs are currently
being  recovered in rates on an annual basis.  The VPSB, in the Settlement Order
stated,  "The  record  does  not  demonstrate that any other New England utility
foresaw  the  extent  and  degree  of  volatility  that has developed in the New
England  wholesale  power  markets.  Absent that volatility, the 97-01 Agreement
would  not have had adverse effects."  In conjunction with the Settlement Order,
Hydro-Quebec committed to the Department that it would not call any energy under
option  B  of  the  9701 arrangement during the contract year ending October 31,
2002.  The  Company's  estimate of the fair value of the future net cost for the
9701 arrangement, which is dependent upon the timing of any exercise of options,
and  the  market  price  for  replacement power, is approximately $27.2 million.
Future  estimates  could  change  by  a  material  amount.
          The  Company  believes that it is probable that Hydro-Quebec will call
options  A  and B for 2003, and has purchased replacement power at a net cost of
$4.7  million.
          On  April 17, 2001, an Arbitration Tribunal issued its decision in the
arbitration  brought  by  a  group  of  Vermont electric companies and municipal
utilities,  known  as the Vermont Joint Owners ("VJO"), against Hydro-Quebec for
its failure to deliver electricity pursuant to the VJO/Hydro-Quebec power supply
contract  during  the  1998  ice  storm.  The  Company  is  a member of the VJO.

          On  July  23,  2001,  the  Company received approximately $3.2 million
representing  its  share  of refunded capacity payments from Hydro-Quebec. These
proceeds  reduced  related deferred assets.  At December 31, 2002, the remaining
unamortized  balance  of  unrecovered  arbitration  costs  is approximately $0.9
million.  We  believe  it  is  probable  that  this  balance  will ultimately be
recovered  in  rates.

     4.  Morgan  Stanley Contract - In February 1999, the Company entered into a
contract  with MS.  In August 2002, the MS contract was modified and extended to
December  31, 2006.  The contract provides the Company a means of managing price
risks  associated  with  changing  fossil fuel prices.  On a daily basis, and at
MS's  discretion,  the Company will sell power to MS from either (i) all or part
of  our  portfolio  of  power  resources  at  predefined  operating  and pricing
parameters  or  (ii) any power resources available to the Company, provided that
sales  of power from sources other than Company-owned generation comply with the
predefined  operating  and  pricing  parameters.   MS  then  sells  to  us, at a
predefined  price,  power sufficient to serve pre-established load requirements.
MS  is  also  responsible  for scheduling supply resources.  The Company remains
responsible  for resource performance and availability.  MS provides no coverage
against  major  unscheduled  outages.
          The  Company  and  MS  have  agreed  to the protocols that are used to
schedule  power  sales  and  purchases and to secure necessary transmission.  We
anticipate  that  arrangements  we  make to manage power supply risks will be on
average  more  costly  than  the  expected cost of fuel during the periods being
hedged  because  these  arrangements would typically incorporate a risk premium.

     L.  DISCONTINUED  OPERATIONS.
          The Company sold or otherwise disposed of a significant portion of the
operations  and  assets  of  NWR, which owned and invested in energy generation,
energy  efficiency,  and wastewater treatment projects.  The provisions for loss
from discontinued operations reflect management's current estimate.  At December
31,  2002,  assets remaining include a wind power partnership investment, a note
receivable  from a regional hydro-power project, and notes receivable and equity
investments  with  two  wastewater  treatment  projects,  one  of which has risk
factors  that  include  the  outcome  of  warranty  litigation,  and future cash
requirements  necessary to minimize costs of winding down wastewater operations.
Several  municipalities  using  wastewater treatment equipment have commenced or
threatened  litigation.  The ultimate loss remains subject to the disposition of
remaining  assets  and  liabilities, and could exceed the amounts recorded.  The
residual  operations earned $0.02 per share in 2002, primarily as a result of an
adjustment  to  a  reserve  for  warranty claims.  The following illustrates the
results  and financial statement impact of discontinued operations during and at
the  periods  shown:
<TABLE>
<CAPTION>


                                     2002    2001      2000
                                    ------  -------  --------
(In thousands except per share)
<S>                                 <C>     <C>      <C>
Revenues . . . . . . . . . . . . .  $   88  $  156   $ 1,546
                                    ------  -------  --------
Gain (loss) on disposal. . . . . .      99    (182)   (6,549)
Net income (loss). . . . . . . . .  $   99  $ (182)  $(6,549)
                                    ======  =======  ========
Net income (loss) per share-basic.  $ 0.02  $(0.03)  $ (1.19)
Proceeds from asset sales. . . . .  $    -  $    -   $ 6,000
Total assets . . . . . . . . . . .  $2,619  $3,697   $ 8,411
State income taxes . . . . . . . .  $   19  $ (175)  $(1,064)
Federal income taxes . . . . . . .      52    (550)   (3,349)
Investment tax credits . . . . . .       -       -         -
                                    ------  -------  --------
Income tax expense (benefit) . . .  $   71  $ (725)  $(4,413)
                                    ======  =======  ========
</TABLE>

M.  QUARTERLY  FINANCIAL  INFORMATION  (UNAUDITED)

          The  following  quarterly  financial  information,  in  the opinion of
management, includes all adjustments necessary to a fair statement of results of
operations  for  such periods.  Variations between quarters reflect the seasonal
nature  of  the  Company's  business  and  the  timing  of  rate  changes.

<TABLE>
<CAPTION>

                                           2002  Quarter  ended
                                                 MARCH    JUNE    SEPTEMBER   DECEMBER    TOTAL
                                                -------  -------  ----------  ---------  --------
(Amounts in thousands except per share data)
<S>                                             <C>      <C>      <C>         <C>        <C>

Operating revenues . . . . . . . . . . . . . .  $68,866  $65,135  $   73,477  $  67,130  $274,608
Operating income . . . . . . . . . . . . . . .    4,441    2,814       3,745      4,080    15,080
Net income-continuing operations . . . . . . .  $ 3,354  $ 1,875  $    3,042  $   3,028  $ 11,299
Net income-discontinued operations . . . . . .        -        -           -         99        99
Net Income applicable to common stock. . . . .  $ 3,354  $ 1,875  $    3,042  $   3,127  $ 11,398
                                                =======  =======  ==========  =========  ========
Basic earnings per share from:
Continuing operations. . . . . . . . . . . . .  $  0.59  $  0.33  $     0.53       0.57  $   2.02
Discontinued operations. . . . . . . . . . . .        -        -           -       0.02      0.02
Basic earnings per share . . . . . . . . . . .  $  0.59  $  0.33  $     0.53  $    0.59  $   2.04
                                                =======  =======  ==========  =========  ========
Weighted average common shares outstanding . .    5,691    5,711       5,723      5,333     5,592
Diluted earnings per share from:
Continuing operations. . . . . . . . . . . . .  $  0.57  $  0.32  $     0.52       0.55  $   1.96
Discontinued operations. . . . . . . . . . . .        -        -           -       0.02      0.02
Diluted earnings per share . . . . . . . . . .  $  0.57  $  0.32  $     0.52  $    0.57  $   1.98
                                                =======  =======  ==========  =========  ========
Weighted average common and common equivalent.    5,870    5,877       5,879      5,497     5,756
shares outstanding
</TABLE>
<TABLE>
<CAPTION>

                                           2001  Quarter  ended
                                                 MARCH     JUNE    SEPTEMBER    DECEMBER     TOTAL
                                                -------  --------  ----------  ----------  ---------
(Amounts in thousands except per share data)
<S>                                             <C>      <C>       <C>         <C>         <C>

Operating revenues . . . . . . . . . . . . . .  $74,796  $67,471   $   76,051  $  65,146   $283,464
Operating income . . . . . . . . . . . . . . .    4,575    4,275        4,573      3,036     16,459
Net income-continuing operations . . . . . . .  $ 2,914  $ 2,884   $    3,387  $   1,675   $ 10,860
Net loss-discontinued operations . . . . . . .        -     (150)           -        (32)      (182)
Net Income applicable to common stock. . . . .  $ 2,914  $ 2,734   $    3,387  $   1,643   $ 10,678
                                                =======  ========  ==========  ==========  =========
Basic earnings (loss) per share from:
Continuing operations. . . . . . . . . . . . .  $  0.52  $  0.52   $     0.60  $    0.29   $   1.93
Discontinued operations. . . . . . . . . . . .        -    (0.03)           -          -      (0.03)
Basic earnings per share . . . . . . . . . . .  $  0.52  $  0.49   $     0.60  $    0.29   $   1.90
                                                =======  ========  ==========  ==========  =========
Weighted average common shares outstanding . .    5,588    5,615        5,644      5,672      5,630
Diluted earnings (loss) per share from:
Continuing operations. . . . . . . . . . . . .  $  0.51  $  0.50   $     0.58  $    0.29   $   1.88
Discontinued operations. . . . . . . . . . . .        -    (0.03)           -          -      (0.03)
Diluted earnings (loss) per share: . . . . . .  $  0.51  $  0.47   $     0.58  $    0.29   $   1.85
                                                =======  ========  ==========  ==========  =========
Weighted average common and common equivalent.    5,741    5,777        5,814      5,848          -
shares outstanding
</TABLE>

<TABLE>
<CAPTION>
                                           2000  Quarter  ended
                                                MARCH     JUNE    SEPTEMBER    DECEMBER     TOTAL
                                               -------  --------  ----------  ----------  ---------
(Amounts in thousands except per share data)
<S>                                            <C>      <C>       <C>         <C>         <C>

Operating revenues. . . . . . . . . . . . . .  $67,712  $61,927   $   78,143  $  69,544   $277,326
Operating income (loss) . . . . . . . . . . .    4,613   (2,997)       3,271        373      5,260
Net income (loss)-continuing operations . . .  $ 3,449  $(4,375)  $    1,961  $  (1,340)  $   (305)
Net loss-discontinued operations. . . . . . .        -   (1,530)           -     (5,019)    (6,549)
Net Income (loss) applicable to common stock.  $ 3,449  $(5,905)  $    1,961  $  (6,359)  $ (6,854)
                                               =======  ========  ==========  ==========  =========
Earnings (loss) per share from:
Continuing operations . . . . . . . . . . . .  $  0.63  $ (0.80)  $     0.36  $   (0.25)  $  (0.06)
Discontinued operations . . . . . . . . . . .        -    (0.28)           -      (0.91)     (1.19)
Basic and diluted . . . . . . . . . . . . . .  $  0.63  $ (1.08)  $     0.36  $   (1.16)  $  (1.25)
                                               =======  ========  ==========  ==========  =========
Weighted average common shares outstanding. .    5,437    5,472        5,505      5,551      5,491
</TABLE>

74

INDEPENDENT  AUDITORS'  REPORT
  TO  THE  BOARD  OF  DIRECTORS  OF
  GREEN  MOUNTAIN  POWER  CORPORATION:

     We  have  audited  the  accompanying  consolidated  balance  sheet of Green
Mountain  Power  Corporation  and  subsidiaries (the Company) as of December 31,
2002, and the related consolidated statements of income, changes in common stock
equity  and cash flows for the year then ended December 31, 2002.  The financial
statements  of  Green Mountain Power Corporation and subsidiaries as of December
31,  2001  and  2000 and for the years then ended were audited by other auditors
who  have  ceased  operations.  Those  auditors expressed an unqualified opinion
which  included an emphasis of matter paragraph on those financial statements in
their  report  dated  March  12,  2002.  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  audit.

     We  conducted  our  audit  in  accordance with auditing standards generally
accepted in the United States.  Those standards 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.  An audit also includes assessing the accounting principles used and
significant  estimates  made  by  management,  as well as evaluating the overall
financial  statement  presentation.  We  believe  that  our  audit  provides  a
reasonable  basis  for  our  opinion.

     In  our opinion, the financial statements referred to above present fairly,
in  all  material  respects,  the  financial  position  of  Green  Mountain
PowerCorporation  and  subsidiaries  as  of December 31, 2002 and the results of
their  operations  and  their  cash flows for the year then ended  in conformity
with  accounting  principles  generally  accepted  in  the  United  States.


Deloitte  &  Touche,  LLP






Boston,  Massachusetts
February  7,  2003

75

REPORT  OF  INDEPENDENT  PUBLIC  ACCOUNTANTS



To  the  Board  of  Directors  of
Green  Mountain  Power  Corporation:




We  have  audited  the accompanying consolidated balance sheets and consolidated
capitalization  data of Green Mountain Power Corporation (a Vermont corporation)
and  its  subsidiaries  as  of  December  31,  2001  and  2000,  and the related
consolidated statements of income, retained earnings, and cash flows for each of
the  three  years  in  the  period  ended  December  31,  2001.  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 in accordance with auditing standards generally accepted
in  the  United  States.  Those  standards  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.  An
audit  also  includes  assessing  the accounting principles used and significant
estimates  made  by  management,  as  well  as  evaluating the overall financial
statement  presentation.  We  believe that our audits provide a reasonable basis
for  our  opinion.

In  our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Green Mountain Power
Corporation  and  its  subsidiaries  as  of  December 31, 2001 and 2000, and the
consolidated  results  of  its  operations  and cash flows for each of the three
years  in  the  period  ended  December  31, 2001, in conformity with accounting
principles  generally  accepted  in  the  United  States.

As  discussed  in Note A to the financial statements, effective January 1, 2001,
the  company  adopted  Statement  of  Financial  Accounting  Standards  No. 133,
"Accounting  for  Derivative  Instruments  and  Hedging Activities," as amended.




/s/  Arthur  Andersen  LLP
Boston,  Massachusetts
March  12,  2002

The  above  report  of  Arthur  Andersen  LLP is a copy of the previously issued
report,  and  the  report  has  not  been  reissued  by  Arthur  Andersen  LLP.


<TABLE>
<CAPTION>

Schedule  II
GREEN  MOUNTAIN  POWER  CORPORATION
VALUATION  AND  QUALIFYING  ACCOUNTS  AND  RESERVES
For  the  Years  Ended  December  31,  2002,  2001,  and  2000
                                Balance at     Additions     Additions          Balance at
                                Beginning of     Charged to     Charged to          End of

                                                  Period     Cost & Expenses  Other Accounts  Deductions    Period
                                                -----------  ---------------  --------------  ----------  -----------
<S>                                             <C>          <C>              <C>             <C>         <C>

Injuries and Damages (1)
----------------------------------------------
2002 . . . . . . . . . . . . . . . . . . . . .  $12,064,548          325,000         134,505   2,034,547  $10,489,506
2001 . . . . . . . . . . . . . . . . . . . . .   13,382,713          212,555         312,229   1,842,949   12,064,548
2000 . . . . . . . . . . . . . . . . . . . . .   10,129,130          111,667       3,193,383      51,467   13,382,713

Bad Debt Reserve
----------------------------------------------
2002 . . . . . . . . . . . . . . . . . . . . .      575,890                -               -      65,844      510,046
2001 . . . . . . . . . . . . . . . . . . . . .      425,890          150,000         575,890
2000 . . . . . . . . . . . . . . . . . . . . .      390,495           35,395               -           -      425,890
(1) Includes Pine Street Barge Canal reserves
</TABLE>

INDEPENDENT  AUDITORS'  REPORT

To  the  Board  of  Directors  and  Stockholders  of
Green  Mountain  Power  Corporation
Colchester,  VT

We  have audited the financial statements of Green Mountain Power Corporation as
of  December  31,  2002  and for the year then ended, and have issued our report
thereon  dated  February 7, 2003; such report is included elsewhere in this Form
10-K.  Our  audit  also  included  the  financial  statement  schedules of Green
Mountain Power Corporation, listed in Item 8.  This financial statement schedule
is the responsibility of the Corporation's management.  Our responsibility is to
express  an  opinion  based  on  our audit.  The financial statement schedule of
Green  Mountain  Power  Corporation and subsidiaries as of December 31, 2001 and
2000  was  audited by other auditors who have ceased operations.  Those auditors
expressed  an  unqualified  opinion on that schedule in their report dated March
12, 2002.  In our opinion, such financial statement schedule, when considered in
relation  to the basic financial statements taken as a whole, presents fairly in
all  material  respects  the  information  set  forth  therein.

DELOITTE  &  TOUCHE  LLP
Boston,  MA
February  7,  2003




REPORT  OF  INDEPENDENT  PUBLIC  ACCOUNTANTS




We have audited, in accordance with auditing standards generally accepted in the
United  States,  the  consolidated  financial statements of Green Mountain Power
Corporation  included in this Form 10-K and have issued our report thereon dated
March  12,  2002.  Our  report included an explanatory paragraph indicating that
effective January 1, 2001, Green Mountain Power Corporation adopted Statement of
Financial  Accounting  Standards No. 133, "Accounting for Derivative Instruments
and  Hedging  Activities,"  as  amended.  Our  audit was made for the purpose of
forming  an  opinion  on  the  basic financial statements taken as a whole.  The
schedule  listed  in the accompanying index to consolidated financial statements
and  schedule  is  presented  for  purposes of complying with the Securities and
Exchange  Commission's rules and is not part of the basic consolidated financial
statements.  This schedule has been subjected to the auditing procedures applied
in the audit of the basic consolidated financial statements, and in our opinion,
fairly  states,  in all material respects, the financial data required to be set
forth  therein  in relation to the basic consolidated financial statements taken
as  a  whole.


/s/  Arthur  Andersen  LLP
Boston,  Massachusetts
March  12,  2002

The  above  report  of  Arthur  Andersen  LLP is a copy of the previously issued
report,  and  the  report  has  not  been  reissued  by  Arthur  Andersen  LLP.

75


79


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

     The  July  17, 2002 decision to engage Deloitte & Touche LLP was made after
careful consideration by the Green Mountain Power Corporation Board of Directors
and  senior  management.  The  decision  was  not the result of any disagreement
between  Green  Mountain  Power  and Arthur Andersen on any matter of accounting
principles  or  practices,  financial statement disclosure, or auditing scope or
procedure,  for  any periods audited and reported on by Arthur Andersen.  Arthur
Anderson's  audit reports for the years ended December 31, 2001 and 2000 did not
contain  any  qualification,  modification,  or  disclaimers.


                                    PART III

ITEMS  10,  11,  12  AND  13

     Certain  information  regarding  executive  officers called for by Item 10,
"Directors  and  Executive  Officers  of the Registrant," is furnished under the
caption,  "Executive  Officers"  in  Item 1 of Part I of this Report.  The other
information  called  for by Item 10, as well as that called for by Items 11, 12,
and  13,  "Executive  Compensation,"  "Security  Ownership of Certain Beneficial
Owners  and  Management"  and  "Certain Relationships and Related Transactions,"
will  be  set  forth  under  the  captions  "Election  of  Directors,"  Board
Compensation,  Meetings,  Committees  and  Other  Relationships,  "Section 16(a)
Beneficial  Ownership  Reporting  Compliance," "Executive Compensation and Other
Information",  "Compensation  Committee  Report  on  Executive  Compensation",
"Pension  Plan  Information  and  Other  Benefits"  and "Securities Ownership of
Certain  Beneficial  Owners  and  Management"  in the Company's definitive proxy
statement  relating  to its annual meeting of stockholders to be held on May 15,
2003.  Such  information  is  incorporated  herein  by  reference.  Such  proxy
statement  pertains  to the election of directors and other matters.  Definitive
proxy  materials  will  be  filed  with  the  Securities and Exchange Commission
pursuant  to  Regulation  14A  in  March  2003.


ITEM  14.  CONTROLS  AND  PROCEDURES
     Within  the 90 days prior to the filing date of this report, we carried out
an  evaluation,  under  the  supervision  and  with  the  participation  of  our
management,  including Christopher L. Dutton, President and Chief Executive
Officer  and  Robert  J.  Griffin, Treasurer and Controller (principal financial
officer),  of  the  effectiveness  of the design and operation of our disclosure
controls  and  procedures  pursuant to Rule 13a-14 under the Securities Exchange
Act  of  1934,  as amended.  Based upon that evaluation, our President and Chief
Executive  Officer,  and  Treasurer and Controller (principal financial officer)
concluded  that  our  disclosure controls and procedures are effective in timely
alerting them to material information relating to us (including our consolidated
subsidiaries)  required  to  be  included  in  our  periodic  SEC  filings.
     There  have  been  no  significant changes in internal controls or in other
factors that could significantly affect these controls subsequent to the date of
their  evaluation,  including  any corrective actions with regard to significant
deficiencies  and  material  weaknesses.

ITEM  15.  EXHIBITS,  FINANCIAL  STATEMENT  SCHEDULES,  AND  REPORTS ON FORM 8-K
Item  15(a)1.  Financial  Statements and Schedules. The financial statements and
financial  statement  schedules  of  the  Company  are  listed  on  the Index to
financial  statements  set  forth  in  Item  8  hereof.

Item  15(b)     The  following  filings on Form 8-K were filed by the Company on
the  topic  and  date  indicated:
A  Form  8-K  was filed on December 16, 2002 announcing the private placement of
$42.0  million in long term bonds maturing in 2017 with an interest rate of 6.04
percent.

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


<TABLE>
<CAPTION>

          ITEM  14(A)3  AND  ITEM  14(C).  EXHIBITS          SEC  DOCKET
               ,     INCORPORATED  BY
     EXHIBIT               REFERENCE  OR

                                                                                               NUMBER
                                                                     -----------------------------------------------------------
<S>                                                                  <C>

  3-A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  RESTATED ARTICLES OF ASSOCIATION, AS CERTIFIED
    JUNE 6, 1991.
  3-A-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO 3-A ABOVE, DATED AS OF MAY 20, 1993.

  3-A-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO 3-A ABOVE, DATED AS OF OCTOBER 11, 1996.

  3-B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  BY-LAWS OF THE COMPANY, AS AMENDED
    FEBRUARY 10, 1997.
  4-B-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  INDENTURE OF FIRST MORTGAGE AND DEED OF TRUST
    DATED AS OF FEBRUARY 1, 1955.
  4-B-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIRST SUPPLEMENTAL INDENTURE DATED AS OF
    APRIL 1, 1961.
  4-B-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  SECOND SUPPLEMENTAL INDENTURE DATED AS OF
    JANUARY 1, 1966.
  4-B-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  THIRD SUPPLEMENTAL INDENTURE DATED AS OF
    JULY 1, 1968.
  4-B-5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FOURTH SUPPLEMENTAL INDENTURE DATED AS OF
    OCTOBER 1, 1969.
  4-B-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIFTH SUPPLEMENTAL INDENTURE DATED AS OF
    DECEMBER 1, 1973.
  4-B-7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  SEVENTH SUPPLEMENTAL INDENTURE DATED AS
    AUGUST 1, 1976.
  4-B-8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  EIGHTH SUPPLEMENTAL INDENTURE DATED AS OF
    DECEMBER 1, 1979.
  4-B-9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  NINTH SUPPLEMENTAL INDENTURE DATED AS OF
    JULY 15, 1985.
  4-B-10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  TENTH SUPPLEMENTAL INDENTURE DATED AS OF
    JUNE 15, 1989.
  4-B-11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  ELEVENTH SUPPLEMENTAL INDENTURE DATED AS OF
    SEPTEMBER 1, 1990.
  4-B-12. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  TWELFTH SUPPLEMENTAL INDENTURE DATED AS OF
    MARCH 1, 1992.
  4-B-13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  THIRTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
    MARCH 1, 1992.
  4-B-14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FOURTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
    NOVEMBER 1, 1993.
  4-B-15. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIFTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
    NOVEMBER 1, 1993.
  4-B-16. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  SIXTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
    DECEMBER 1, 1995.
  4-B-17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  REVISED FORM OF INDENTURE AS FILED AS AN EXHIBIT
    TO REGISTRATION STATEMENT NO. 33-59383.
  4-B-18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  CREDIT AGREEMENT BY AND AMONG GREEN MOUNTAIN POWER
    THE BANK OF NOVA SCOTIA, STATE STREET BANK AND
    TRUST COMPANY, FLEET NATIONAL BANK, AND FLEET
    NATIONAL BANK, AS AGENT
  4-B-18(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO EXHIBIT 4-B-18

  4-B-19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  SEVENTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
    DECEMBER 1, 2002
  10-A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FORM OF INSURANCE POLICY ISSUED BY PACIFIC
    INSURANCE COMPANY, WITH RESPECT TO
    INDEMNIFICATION OF DIRECTORS AND OFFICERS.
  10-B-1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIRM POWER CONTRACT DATED SEPTEMBER 16, 1958,
    BETWEEN THE COMPANY AND THE STATE OF VERMONT
    AND SUPPLEMENTS  THERETO DATED SEPTEMBER 19,
    1958; NOVEMBER 15, 1958;  OCTOBER 1, 1960 AND
    FEBRUARY 1, 1964.
  10-B-2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  POWER CONTRACT, DATED FEBRUARY 1, 1968, BETWEEN THE COMPANY
    AND VERMONT YANKEE NUCLEAR POWER CORPORATION.
  10-B-3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT, DATED JUNE 1, 1972, TO POWER CONTRACT
    BETWEEN THE COMPANY AND VERMONT YANKEE NUCLEAR
    POWER CORPORATION.
  10-B-3(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT, DATED APRIL 15, 1983, TO POWER
    CONTRACT BETWEEN THE COMPANY AND VERMONT
    YANKEE NUCLEAR POWER CORPORATION.
  10-B-3(B) . . . . . . . . . . . . . . . . . . . . . . . . . . . .  ADDITIONAL POWER CONTRACT, DATED
    FEBRUARY 1, 1984,BETWEEN THE COMPANY AND
    VERMONT YANKEE NUCLEAR POWER CORPORATION.
  10-B-4. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  CAPITAL FUNDS AGREEMENT, DATED FEBRUARY 1,
    1968, BETWEEN THE COMPANY AND VERMONT
    YANKEE NUCLEAR POWER CORPORATION.
  10-B-5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT, DATED MARCH 12, 1968, TO CAPITAL
    FUNDS AGREEMENT BETWEEN THE COMPANY AND
    VERMONT YANKEE NUCLEAR POWER CORPORATION.
  10-B-6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  GUARANTEE AGREEMENT, DATED NOVEMBER 5, 1981, OF THE
    COMPANY FOR ITS PROPORTIONATE SHARE OF THE OBLIGATIONS
    OF VERMONT YANKEE NUCLEAR POWER CORPORATION
    UNDER A $40 MILLION LOAN ARRANGEMENT.
  10-B-7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  THREE-PARTY POWER AGREEMENT AMONG THE COMPANY,
    VELCO AND CENTRAL VERMONT PUBLIC SERVICE
    CORPORATION DATED NOVEMBER 21, 1969.
  10-B-8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO EXHIBIT 10-B-7, DATED JUNE 1, 1981.
  10-B-9. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  THREE-PARTY TRANSMISSION AGREEMENT AMONG THE
    COMPANY, VELCO AND CENTRAL VERMONT PUBLIC
    SERVICE CORPORATION, DATED NOVEMBER 21, 1969.
  10-B-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO EXHIBIT 10-B-9, DATED JUNE 1, 1981.
  10-B-14 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AGREEMENT WITH CENTRAL MAINE POWER COMPANY ET
    AL, TO ENTER INTO JOINT OWNERSHIP OF WYMAN
    PLANT, DATED NOVEMBER 1, 1974.
  10-B-15 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  NEW ENGLAND POWER POOL AGREEMENT AS AMENDED TO
    NOVEMBER 1, 1975.
  10-B-16 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  BULK POWER TRANSMISSION CONTRACT BETWEEN THE
    COMPANY AND VELCO DATED JUNE 1, 1968.
  10-B-17 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO EXHIBIT 10-B-16, DATED JUNE 1, 1970.
  10-B-20 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  POWER SALES AGREEMENT, DATED AUGUST 2, 1976, AS
    AMENDED OCTOBER 1, 1977, AND RELATED
    TRANSMISSION AGREEMENT, WITH THE MASSACHUSETTS
    MUNICIPAL WHOLESALE ELECTRIC COMPANY.
  10-B-21 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AGREEMENT DATED OCTOBER 1, 1977, FOR JOINT OWNERSHIP,
    CONSTRUCTION AND OPERATION OF THE MMWEC PHASE I
    INTERMEDIATE UNITS, DATED OCTOBER 1, 1977
  10-B-28 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  CONTRACT DATED FEBRUARY 1, 1980, PROVIDING FOR
    THE SALE OF FIRM POWER AND ENERGY BY THE POWER
    AUTHORITY OF THE STATE OF NEW YORK TO THE
    VERMONT PUBLIC SERVICE BOARD.
  10-B-30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  BULK POWER PURCHASE CONTRACT DATED APRIL 7,
    1976, BETWEEN VELCO AND THE COMPANY.
  10-B-33 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT
    DATED AS OF DECEMBER 1, 1981, PROVIDING FOR USE OF
    TRANSMISSION INTER-CONNECTION BETWEEN NEW ENGLAND
    AND HYDRO-QUEBEC.
  10-B-34 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  PHASE I TRANSMISSION LINE SUPPORT AGREEMENT
    DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
    NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
    VETCO AND PARTICIPATING NEW ENGLAND UTILITIES
    FOR CONSTRUCTION, USE AND SUPPORT OF VERMONT
    FACILITIES OF TRANSMISSION INTERCONNECTION
    BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-35 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  PHASE I TERMINAL FACILITY SUPPORT AGREEMENT
    DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
    NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
    NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
    AND PARTICIPATING NEW ENGLAND UTILITIES FOR
    CONSTRUCTION, USE AND SUPPORT OF NEW HAMPSHIRE
    FACILITIES OF TRANSMISSION INTERCONNECTION
    BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-36 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AGREEMENT WITH RESPECT TO USE OF QUEBEC
    INTERCONNECTION DATED AS OF DECEMBER 1, 1981,
    AMONG PARTICIPATING NEW ENGLAND UTILITIES
    FOR USE OF TRANSMISSION INTERCONNECTION
    BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-39 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  VERMONT PARTICIPATION AGREEMENT FOR QUEBEC
    INTERCONNECTION DATED AS OF JULY 15, 1982,
    BETWEEN VELCO AND PARTICIPATING VERMONT
    UTILITIES FOR ALLOCATION OF VELCO'S RIGHTS
    AND OBLIGATIONS AS A PARTICIPATING NEW
    ENGLAND UTILITY IN THE TRANSMISSION INTER-
    CONNECTION BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-40 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  VERMONT ELECTRIC TRANSMISSION COMPANY, INC.
    CAPITAL FUNDS AGREEMENT DATED AS OF JULY 15,
    1982, BETWEEN VETCO AND VELCO FOR VELCO TO PROVIDE
    CAPITAL TO VETCO FOR CONSTRUCTION OF THE VERMONT FACILITIES
    OF THE TRANSMISSION INTER-CONNECTION BETWEEN NEW
    ENGLAND AND HYDRO-QUEBEC.
  10-B-41 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  VETCO CAPITAL FUNDS SUPPORT AGREEMENT DATED AS
    OF JULY 15, 1982, BETWEEN VELCO AND PARTICIPATING VERMONT
    UTILITIES FOR ALLOCATION OF VELCO'S OBLIGATION TO VETCO
    UNDER THE CAPITAL FUNDS AGREEMENT.
  10-B-42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  ENERGY BANKING AGREEMENT DATED MARCH 21, 1983,
    AMONG HYDRO-QUEBEC, VELCO, NEET AND PARTI-
    CIPATING NEW ENGLAND UTILITIES ACTING BY AND
    THROUGH THE NEPOOL MANAGEMENT COMMITTEE FOR
    TERMS OF ENERGY BANKING BETWEEN PARTICIPATING
    NEW ENGLAND UTILITIES AND HYDRO-QUEBEC.
  10-B-43 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  INTERCONNECTION AGREEMENT DATED MARCH 21, 1983,
    BETWEEN HYDRO-QUBEC AND PARTICIPATING NEW
    ENGLAND UTILITIES ACTING BY AND THROUGH THE
    NEPOOL MANAGEMENT COMMITTEE FOR TERMS AND
    CONDITIONS OF ENERGY TRANSMISSION BETWEEN
    NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-44 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  ENERGY CONTRACT DATED MARCH 21, 1983, BETWEEN
    HYDRO-QUEBEC AND PARTICIPATING NEW ENGLAND
    UTILITIES ACTING BY AND THROUGH THE NEPOOL
    MANAGEMENT COMMITTEE FOR PURCHASE OF
    SURPLUS ENERGY FROM HYDRO-QUEBEC.
  10-B-50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AGREEMENT FOR JOINT OWNERSHIP, CONSTRUCTION AND
    OPERATION OF THE HIGHGATE TRANSMISSION
    INTERCONNECTION, DATED AUGUST 1, 1984,
    BETWEEN CERTAIN ELECTRIC DISTRIBUTION
    COMPANIES, INCLUDING THE COMPANY.
  10-B-51 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  HIGHGATE OPERATING AND MANAGEMENT AGREEMENT,
    DATED AS OF AUGUST 1, 1984, AMONG VELCO AND
    VERMONT ELECTRIC-UTILITY COMPANIES, INCLUDING
    THE COMPANY.
  10-B-52 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  ALLOCATION CONTRACT FOR HYDRO-QUEBEC FIRM POWER
    DATED JULY 25, 1984, BETWEEN THE STATE OF
    VERMONT AND  VARIOUS VERMONT ELECTRIC UTILITIES,
    INCLUDING THE COMPANY.
  10-B-53 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  HIGHGATE TRANSMISSION AGREEMENT DATED AS OF
    AUGUST 1, 1984, BETWEEN THE OWNERS OF THE
    PROJECT AND VARIOUS VERMONT ELECTRIC
    DISTRIBUTION COMPANIES.
  10-B-61 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AGREEMENTS ENTERED IN CONNECTION WITH PHASE II
    OF THE NEPOOL/HYDRO-QUEBEC + 450 KV HVDC
    TRANSMISSION INTERCONNECTION.
  10-B-62 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AGREEMENT BETWEEN UNITIL POWER CORP. AND THE
    COMPANY TO SELL 23 MW CAPACITY AND ENERGY FROM
    STONY BROOK INTERMEDIATE COMBINED CYCLE UNIT.
  10-B-68 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIRM POWER AND ENERGY CONTRACT DATED DECEMBER 4,
    1987, BETWEEN HYDRO-QUEBEC AND PARTICIPATING
    VERMONT UTILITIES, INCLUDING THE COMPANY, FOR
    THE PURCHASE OF FIRM POWER FOR UP TO THIRTY YEARS.
  10-B-69 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIRM POWER AGREEMENT DATED AS OF OCTOBER 26, 1987,
    BETWEEN ONTARIO HYDRO AND VERMONT DEPARTMENT OF
    PUBLIC SERVICE.
  10-B-70 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIRM POWER AND ENERGY CONTRACT DATED AS OF
    FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT
    OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-
    QUEBEC FOR UP TO 50 MW OF CAPACITY.
  10-B-70(A). . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO 10-B-70.

  10-B-71 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  INTERCONNECTION AGREEMENT DATED AS OF
    FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT
    OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-QUEBEC.
  10-B-72 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  PARTICIPATION AGREEMENT DATED AS OF APRIL 1, 1988,
    BETWEEN HYDRO-QUEBEC AND PARTICIPATING VERMONT. . . . . . . . .  JUNE 1988
    UTILITIES, INCLUDING THE COMPANY, IMPLEMENTING
    THE PURCHASE OF FIRM POWER FOR UP TO 30 YEARS
    UNDER THE FIRM POWER AND ENERGY CONTRACT DATED
    DECEMBER 4, 1987 (PREVIOUSLY FILED WITH THE
    COMPANY'S ANNUAL REPORT ON FORM 10-K FOR 1987,
    EXHIBIT NUMBER 10-B-68).
  10-B-72(A). . . . . . . . . . . . . . . . . . . . . . . . . . . .  RESTATEMENT OF THE PARTICIPATION AGREEMENT FILED
    AS EXHIBIT 10-B-72 ON FORM 10-Q FOR JUNE 1988.
  10-B-77 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIRM POWER AND ENERGY CONTRACT DATED DECEMBER 29,
    1988, BETWEEN HYDRO-QUEBEC AND PARTICIPATING
    VERMONT UTILITIES, INCLUDING THE COMPANY, FOR THE
    PURCHASE OF UP TO 54 MW OF FIRM POWER AND ENERGY.
  10-B-78 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  TRANSMISSION AGREEMENT DATED DECEMBER 23, 1988,
    BETWEEN THE COMPANY AND NIAGARA MOHAWK POWER
    CORPORATION (NIAGARA MOHAWK), FOR NIAGARA
    MOHAWK TO PROVIDE ELECTRIC TRANSMISSION TO
    THE COMPANY FROM ROCHESTER GAS AND ELECTRIC
    AND CENTRAL HUDSON GAS AND ELECTRIC.
  10-B-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  SALES AGREEMENT DATED MAY 24, 1989, BETWEEN
    THE TOWN OF HARDWICK, HARDWICK ELECTRIC DEPARTMENT. . . . . . .  JUNE 1989
    AND THE COMPANY FOR THE COMPANY TO PURCHASE
    ALL OF THE OUTPUT OF HARDWICK'S GENERATION AND
    TRANSMISSION SOURCES AND TO PROVIDE HARDWICK
    WITH ALL-REQUIREMENTS ENERGY AND CAPACITY EXCEPT
    FOR THAT PROVIDED BY THE VERMONT DEPARTMENT OF
    PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
  10-B-82 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  SALES AGREEMENT DATED JULY 14, 1989, BETWEEN
    NORTHFIELD ELECTRIC DEPARTMENT AND THE COMPANY. . . . . . . . .  JUNE 1989
    FOR THE COMPANY TO PURCHASE ALL OF THE OUTPUT
    OF NORTHFIELD'S GENERATION AND TRANSMISSION
    SOURCES AND TO PROVIDE NORTHFIELD WITH ALL-
    REQUIREMENTS ENERGY AND CAPACITY EXCEPT FOR
    THAT PROVIDED BY THE VERMONT DEPARTMENT OF
    PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
  10-B-85 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  POWER PURCHASE AND SALE AGREEMENT BETWEEN
    MORGAN STANLEY CAPITAL GROUP INC. AND THE
    COMPANY
  10-B-86 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  REVOLVING CREDIT AGREEMENT WITH KEYBANK

  10-B-87 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO FLEET REVOLVING CREDIT AGREEMENT

  10-B-88 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  ENERGY EAST POWER PURCHASE OPTION AGREEMENT

  10-B-89 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  SECOND AMENDED AND RESTATED CREDIT AGREEMENT BETWEEN
    KEYBANK NATIONAL ASSOCIATION, FLEET NATIONAL BANK, AND
    THE COMPANY DATED JUNE 20, 2001
  10-B-90 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  PURCHASE POWER AGREEMENT BETWEEN ENTERGY NUCLEAR VERMONT
    YANKEE LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION
  10-B-91 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  FIRST AMENDMENT TO PURCHASE POWER AGREEMENT LISTED AS
    EXHIBIT NUMBER 10-B-90, BETWEEN ENTERGY NUCLEAR VERMONT YANKEE
    LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION
  10-B-92 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO POWER PURCHASE AND SALE AGREEMENT
    BETWEEN MORGAN STANLEY CAPITAL GROUP, INC. AND THE
    COMPANY

                                                                     DESCRIPTION         EXHIBIT         PAGE FILED HEREWITH
                                                                     ------------  --------------------  --------------------
<S>                                                                  <C>           <C>                   <C>

  3-A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           3-A  FORM 10-K 1993
    JUNE 6, 1991.                                                                              (1-8291)
  3-A-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         3-A-1  FORM 10-K 1993
                                                                                                                     (1-8291)
  3-A-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         3-A-2  FORM 10-Q SEPT.
                                                                                                                1996 (1-8291)
  3-B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           3-B  FORM 10-K 1996
    FEBRUARY 10, 1997.                                                                         (1-8291)
  4-B-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           4-B              2-27300
    DATED AS OF FEBRUARY 1, 1955.
  4-B-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-B-2              2-75293
    APRIL 1, 1961.
  4-B-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-B-3              2-75293
    JANUARY 1, 1966.
  4-B-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-B-4              2-75293
    JULY 1, 1968.
  4-B-5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-B-5              2-75293
    OCTOBER 1, 1969.
  4-B-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-B-6              2-75293
    DECEMBER 1, 1973.
  4-B-7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-A-7              2-99643
    AUGUST 1, 1976.
  4-B-8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-A-8              2-99643
    DECEMBER 1, 1979.
  4-B-9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         4-B-9              2-99643
    JULY 15, 1985.
  4-B-10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-10  FORM 10-K 1989
    JUNE 15, 1989.                                                                             (1-8291)
  4-B-11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-11  FORM 10-Q SEPT.
    SEPTEMBER 1, 1990.                                                                    1990 (1-8291)
  4-B-12. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-12  FORM 10-K 1991
    MARCH 1, 1992.                                                                             (1-8291)
  4-B-13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-13  FORM 10-K 1991
    MARCH 1, 1992.                                                                             (1-8291)
  4-B-14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-14  FORM 10-K 1993
    NOVEMBER 1, 1993.                                                                          (1-8291)
  4-B-15. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-15  FORM 10-K 1993
    NOVEMBER 1, 1993.                                                                          (1-8291)
  4-B-16. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-16  FORM 10-K 1995
    DECEMBER 1, 1995.                                                                          (1-8291)
  4-B-17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-17  FORM 10-Q SEPT.
    TO REGISTRATION STATEMENT NO. 33-59383.                                               1995 (1-8291)
  4-B-18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-18  FORM 10-K 1997
    THE BANK OF NOVA SCOTIA, STATE STREET BANK AND                                             (1-8291)
    TRUST COMPANY, FLEET NATIONAL BANK, AND FLEET
    NATIONAL BANK, AS AGENT
  4-B-18(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . .     4-B-18(A)  FORM 10-Q SEPT.
                                                                                          1998 (1-8291)
  4-B-19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4-B-19  FORM 10-K 2002
    DECEMBER 1, 2002                                                                           (1-8291)
  10-A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          10-A              33-8146
    INSURANCE COMPANY, WITH RESPECT TO
    INDEMNIFICATION OF DIRECTORS AND OFFICERS.
  10-B-1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          13-B              2-27300
    BETWEEN THE COMPANY AND THE STATE OF VERMONT
    AND SUPPLEMENTS  THERETO DATED SEPTEMBER 19,
    1958; NOVEMBER 15, 1958;  OCTOBER 1, 1960 AND
    FEBRUARY 1, 1964.
  10-B-2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          13-D              2-34346
    AND VERMONT YANKEE NUCLEAR POWER CORPORATION.
  10-B-3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        13-F-1              2-49697
    BETWEEN THE COMPANY AND VERMONT YANKEE NUCLEAR
    POWER CORPORATION.
  10-B-3(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . .     10-B-3(A)              33-8164
    CONTRACT BETWEEN THE COMPANY AND VERMONT
    YANKEE NUCLEAR POWER CORPORATION.
  10-B-3(B) . . . . . . . . . . . . . . . . . . . . . . . . . . . .     10-B-3(B)              33-8164
    FEBRUARY 1, 1984,BETWEEN THE COMPANY AND
    VERMONT YANKEE NUCLEAR POWER CORPORATION.
  10-B-4. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          13-E              2-34346
    1968, BETWEEN THE COMPANY AND VERMONT
    YANKEE NUCLEAR POWER CORPORATION.
  10-B-5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          13-F              2-34346
    FUNDS AGREEMENT BETWEEN THE COMPANY AND
    VERMONT YANKEE NUCLEAR POWER CORPORATION.
  10-B-6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        10-B-6              2-75293
    COMPANY FOR ITS PROPORTIONATE SHARE OF THE OBLIGATIONS
    OF VERMONT YANKEE NUCLEAR POWER CORPORATION
    UNDER A $40 MILLION LOAN ARRANGEMENT.
  10-B-7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          13-I              2-49697
    VELCO AND CENTRAL VERMONT PUBLIC SERVICE
    CORPORATION DATED NOVEMBER 21, 1969.
  10-B-8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        10-B-8              2-75293
  10-B-9. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          13-J              2-49697
    COMPANY, VELCO AND CENTRAL VERMONT PUBLIC
    SERVICE CORPORATION, DATED NOVEMBER 21, 1969.
  10-B-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-10              2-75293
  10-B-14                                                                 5.16               2-52900
    AL, TO ENTER INTO JOINT OWNERSHIP OF WYMAN
    PLANT, DATED NOVEMBER 1, 1974.
  10-B-15                                                                  4.8               2-55385
    NOVEMBER 1, 1975.
  10-B-16 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          13-V         2-49697
    COMPANY AND VELCO DATED JUNE 1, 1968.
  10-B-17 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        13-V-I         2-49697
  10-B-20 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-20         33-8164
    AMENDED OCTOBER 1, 1977, AND RELATED
    TRANSMISSION AGREEMENT, WITH THE MASSACHUSETTS
    MUNICIPAL WHOLESALE ELECTRIC COMPANY.
  10-B-21 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-21         33-8164
    CONSTRUCTION AND OPERATION OF THE MMWEC PHASE I
    INTERMEDIATE UNITS, DATED OCTOBER 1, 1977
  10-B-28 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-28         33-8164
    THE SALE OF FIRM POWER AND ENERGY BY THE POWER
    AUTHORITY OF THE STATE OF NEW YORK TO THE
    VERMONT PUBLIC SERVICE BOARD.
  10-B-30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-32         2-75293
    1976, BETWEEN VELCO AND THE COMPANY.
  10-B-33 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-33         33-8164
    DATED AS OF DECEMBER 1, 1981, PROVIDING FOR USE OF
    TRANSMISSION INTER-CONNECTION BETWEEN NEW ENGLAND
    AND HYDRO-QUEBEC.
  10-B-34 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-34         33-8164
    DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
    NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
    VETCO AND PARTICIPATING NEW ENGLAND UTILITIES
    FOR CONSTRUCTION, USE AND SUPPORT OF VERMONT
    FACILITIES OF TRANSMISSION INTERCONNECTION
    BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-35 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-35         33-8164
    DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
    NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
    NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
    AND PARTICIPATING NEW ENGLAND UTILITIES FOR
    CONSTRUCTION, USE AND SUPPORT OF NEW HAMPSHIRE
    FACILITIES OF TRANSMISSION INTERCONNECTION
    BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-36 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-36         33-8164
    INTERCONNECTION DATED AS OF DECEMBER 1, 1981,
    AMONG PARTICIPATING NEW ENGLAND UTILITIES
    FOR USE OF TRANSMISSION INTERCONNECTION
    BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-39 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-39         33-8164
    INTERCONNECTION DATED AS OF JULY 15, 1982,
    BETWEEN VELCO AND PARTICIPATING VERMONT
    UTILITIES FOR ALLOCATION OF VELCO'S RIGHTS
    AND OBLIGATIONS AS A PARTICIPATING NEW
    ENGLAND UTILITY IN THE TRANSMISSION INTER-
    CONNECTION BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-40 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-40         33-8164
    CAPITAL FUNDS AGREEMENT DATED AS OF JULY 15,
    1982, BETWEEN VETCO AND VELCO FOR VELCO TO PROVIDE
    CAPITAL TO VETCO FOR CONSTRUCTION OF THE VERMONT FACILITIES
    OF THE TRANSMISSION INTER-CONNECTION BETWEEN NEW
    ENGLAND AND HYDRO-QUEBEC.
  10-B-41 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-41         33-8164
    OF JULY 15, 1982, BETWEEN VELCO AND PARTICIPATING VERMONT
    UTILITIES FOR ALLOCATION OF VELCO'S OBLIGATION TO VETCO
    UNDER THE CAPITAL FUNDS AGREEMENT.
  10-B-42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-42         33-8164
    AMONG HYDRO-QUEBEC, VELCO, NEET AND PARTI-
    CIPATING NEW ENGLAND UTILITIES ACTING BY AND
    THROUGH THE NEPOOL MANAGEMENT COMMITTEE FOR
    TERMS OF ENERGY BANKING BETWEEN PARTICIPATING
    NEW ENGLAND UTILITIES AND HYDRO-QUEBEC.
  10-B-43 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-43         33-8164
    BETWEEN HYDRO-QUBEC AND PARTICIPATING NEW
    ENGLAND UTILITIES ACTING BY AND THROUGH THE
    NEPOOL MANAGEMENT COMMITTEE FOR TERMS AND
    CONDITIONS OF ENERGY TRANSMISSION BETWEEN
    NEW ENGLAND AND HYDRO-QUEBEC.
  10-B-44 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-44         33-8164
    HYDRO-QUEBEC AND PARTICIPATING NEW ENGLAND
    UTILITIES ACTING BY AND THROUGH THE NEPOOL
    MANAGEMENT COMMITTEE FOR PURCHASE OF
    SURPLUS ENERGY FROM HYDRO-QUEBEC.
  10-B-50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-50         33-8164
    OPERATION OF THE HIGHGATE TRANSMISSION
    INTERCONNECTION, DATED AUGUST 1, 1984,
    BETWEEN CERTAIN ELECTRIC DISTRIBUTION
    COMPANIES, INCLUDING THE COMPANY.
  10-B-51 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-51         33-8164
    DATED AS OF AUGUST 1, 1984, AMONG VELCO AND
    VERMONT ELECTRIC-UTILITY COMPANIES, INCLUDING
    THE COMPANY.
  10-B-52 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-52         33-8164
    DATED JULY 25, 1984, BETWEEN THE STATE OF
    VERMONT AND  VARIOUS VERMONT ELECTRIC UTILITIES,
    INCLUDING THE COMPANY.
  10-B-53 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-53        33-8164
    AUGUST 1, 1984, BETWEEN THE OWNERS OF THE
    PROJECT AND VARIOUS VERMONT ELECTRIC
    DISTRIBUTION COMPANIES.
  10-B-61 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-61         33-8164
    OF THE NEPOOL/HYDRO-QUEBEC + 450 KV HVDC
    TRANSMISSION INTERCONNECTION.
  10-B-62 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-62         33-8164
    COMPANY TO SELL 23 MW CAPACITY AND ENERGY FROM
    STONY BROOK INTERMEDIATE COMBINED CYCLE UNIT.
  10-B-68 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-68  FORM 10-K 1992
    1987, BETWEEN HYDRO-QUEBEC AND PARTICIPATING                                    (1-8291)
    VERMONT UTILITIES, INCLUDING THE COMPANY, FOR
    THE PURCHASE OF FIRM POWER FOR UP TO THIRTY YEARS.
  10-B-69 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-69  FORM 10-K 1992
    BETWEEN ONTARIO HYDRO AND VERMONT DEPARTMENT OF                                    (1-8291)
    PUBLIC SERVICE.
  10-B-70 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-70  FORM 10-K 1992
    FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT                                        (1-8291)
    OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-
    QUEBEC FOR UP TO 50 MW OF CAPACITY.
  10-B-70(A). . . . . . . . . . . . . . . . . . . . . . . . . . . .    10-B-70(A)  FORM 10-K 1992
                                                                                        (1-8291)
  10-B-71 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-71  FORM 10-K 1992
    FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT                                     (1-8291)
    OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-QUEBEC.
  10-B-72 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-72  FORM 10-Q
    BETWEEN HYDRO-QUEBEC AND PARTICIPATING VERMONT
    UTILITIES, INCLUDING THE COMPANY, IMPLEMENTING                                    (1-8291)
    THE PURCHASE OF FIRM POWER FOR UP TO 30 YEARS
    UNDER THE FIRM POWER AND ENERGY CONTRACT DATED
    DECEMBER 4, 1987 (PREVIOUSLY FILED WITH THE
    COMPANY'S ANNUAL REPORT ON FORM 10-K FOR 1987,
    EXHIBIT NUMBER 10-B-68).
  10-B-72(A). . . . . . . . . . . . . . . . . . . . . . . . . . . .    10-B-72(A)  FORM 10-K 1988
    AS EXHIBIT 10-B-72 ON FORM 10-Q FOR JUNE 1988.                                     (1-8291)
  10-B-77 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-77  FORM 10-K 1988
    1988, BETWEEN HYDRO-QUEBEC AND PARTICIPATING                                        (1-8291)
    VERMONT UTILITIES, INCLUDING THE COMPANY, FOR THE
    PURCHASE OF UP TO 54 MW OF FIRM POWER AND ENERGY.
  10-B-78 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-78  FORM 10-K 1988
    BETWEEN THE COMPANY AND NIAGARA MOHAWK POWER                                       (1-8291)
    CORPORATION (NIAGARA MOHAWK), FOR NIAGARA
    MOHAWK TO PROVIDE ELECTRIC TRANSMISSION TO
    THE COMPANY FROM ROCHESTER GAS AND ELECTRIC
    AND CENTRAL HUDSON GAS AND ELECTRIC.
  10-B-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-81  FORM 10-Q
    THE TOWN OF HARDWICK, HARDWICK ELECTRIC DEPARTMENT
    AND THE COMPANY FOR THE COMPANY TO PURCHASE                                     (1-8291)
    ALL OF THE OUTPUT OF HARDWICK'S GENERATION AND
    TRANSMISSION SOURCES AND TO PROVIDE HARDWICK
    WITH ALL-REQUIREMENTS ENERGY AND CAPACITY EXCEPT
    FOR THAT PROVIDED BY THE VERMONT DEPARTMENT OF
    PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
  10-B-82 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-82  FORM 10-Q
    NORTHFIELD ELECTRIC DEPARTMENT AND THE COMPANY
    FOR THE COMPANY TO PURCHASE ALL OF THE OUTPUT                                   (1-8291)
    OF NORTHFIELD'S GENERATION AND TRANSMISSION
    SOURCES AND TO PROVIDE NORTHFIELD WITH ALL-
    REQUIREMENTS ENERGY AND CAPACITY EXCEPT FOR
    THAT PROVIDED BY THE VERMONT DEPARTMENT OF
    PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
  10-B-85 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-85  FORM 10-K 1998
    MORGAN STANLEY CAPITAL GROUP INC. AND THE                                           (1-8291)
    COMPANY
  10-B-86 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-86  FORM 10-Q SEPT.
                                                                                    2000 (1-8291)
  10-B-87 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-87  FORM 10-Q SEPT.
                                                                                    2000 (1-8291)
  10-B-88 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-88  FORM 10-Q SEPT.
                                                                                    2000 (1-8291)
  10-B-89 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-89  FORM 10-K 2001
    KEYBANK NATIONAL ASSOCIATION, FLEET NATIONAL BANK, AND
    THE COMPANY DATED JUNE 20, 2001
  10-B-90 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-90  FORM 10-Q JUNE 2002
    YANKEE LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION                                    (1-8291)
  10-B-91 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-90  FORM 10-Q JUNE 2002
    EXHIBIT NUMBER 10-B-90, BETWEEN ENTERGY NUCLEAR VERMONT YANKEE                             (1-8291)
    LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION
  10-B-92 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       10-B-92  FORM 10-K 2002
    BETWEEN MORGAN STANLEY CAPITAL GROUP, INC. AND THE                                         (1-8291)
    COMPANY
</TABLE>


<TABLE>
<CAPTION>
          MANAGEMENT  CONTRACTS  OR  COMPENSATORY  PLANS  OR  ARRANGEMENTS
          REQUIRED  TO  BE  FILED  AS  EXHIBITS  TO  THIS  FORM  10-K

                                                            PURSUANT TO ITEM 14(C)., ALL UNDER SEC DOCKET 1-8291
                                                            -----------------------------------------------------
<S>                                                         <C>                                                    <C>

  10-D-1B. . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER CORPORATION SECOND AMENDED         10-D-1B
    AND RESTATED DEFERRED COMPENSATION PLAN FOR DIRECTORS.
  10-D-1C. . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER CORPORATION SECOND AMENDED         10-D-1C
    AND RESTATED DEFERRED COMPENSATION PLAN FOR
    OFFICERS.
  10-D-1D. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT NO. 93-1 TO THE AMENDED AND RESTATED          10-D-1D
    DEFERRED COMPENSATION PLAN FOR OFFICERS.
  10-D-1E. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT NO. 94-1 TO THE AMENDED AND RESTATED          10-D-1E
    DEFERRED COMPENSATION PLAN FOR OFFICERS. . . . . . . .  JUNE 1994
  10-D-2 . . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER CORPORATION MEDICAL EXPENSE         10-D-2
    REIMBURSEMENT PLAN.
  10-D-4 . . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER CORPORATION OFFICER                 10-D-4
    INSURANCE PLAN.
  10-D-4A. . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER CORPORATION OFFICERS'              10-D-4A
    INSURANCE PLAN AS AMENDED.
  10-D-8 . . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER CORPORATION OFFICERS'               10-D-8
    SUPPLEMENTAL RETIREMENT PLAN.
  10-D-15B . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER CORPORATION COMPENSATION PROGRAM  10-D-15B
    FOR OFFICERS AND KEY MANAGEMENT PERSONNEL AS AMENDED
    AUGUST 4, 1997
  10-D-15C . . . . . . . . . . . . . . . . . . . . . . . .  GREEN MOUNTAIN POWER 2000 STOCK INCENTIVE PLAN         10-D-15C
  10-D-21. . . . . . . . . . . . . . . . . . . . . . . . .  SEVERANCE AGREEMENT WITH N. R. BROCK                    10-D-21
  10-D-22. . . . . . . . . . . . . . . . . . . . . . . . .  SEVERANCE AGREEMENT WITH C. L. DUTTON                   10-D-22
  10-D-23. . . . . . . . . . . . . . . . . . . . . . . . .  SEVERANCE AGREEMENT WITH R. J. GRIFFIN                  10-D-23
  10-D-27. . . . . . . . . . . . . . . . . . . . . . . . .  SEVERANCE AGREEMENT WITH W. S. OAKES                    10-D-27
  10-D-28. . . . . . . . . . . . . . . . . . . . . . . . .  SEVERANCE AGREEMENT WITH M. G. POWELL                   10-D-28
  10-D-29. . . . . . . . . . . . . . . . . . . . . . . . .  SEVERANCE AGREEMENT WITH S. C. TERRY                    10-D-29
  10-D-31. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO SEVERANCE AGREEMENT WITH N. R. BROCK       10-D-31
  10-D-32. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO SEVERANCE AGREEMENT WITH C. L. DUTTON      10-D-32
  10-D-33. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO SEVERANCE AGREEMENT WITH R. J. GRIFFIN     10-D-33
  10-D-34. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO SEVERANCE AGREEMENT WITH W. S. OAKES       10-D-34
  10-D-35. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO SEVERANCE AGREEMENT WITH M. G. POWELL      10-D-35
  10-D-36. . . . . . . . . . . . . . . . . . . . . . . . .  AMENDMENT TO SEVERANCE AGREEMENT WITH S. C. TERRY       10-D-36
  10-D-37. . . . . . . . . . . . . . . . . . . . . . . . .  SEVERANCE AGREEMENT WITH D.J. RENDALL                   10-D-37

  *23-A-1. . . . . . . . . . . . . . . . . . . . . . . . .  CONSENT OF ARTHUR ANDERSEN LLP                           23-A-1
  23-A-2 . . . . . . . . . . . . . . . . . . . . . . . . .  CONSENT OF DELOITTE AND TOUCHE LLP                       23-A-2






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

  10-D-1B. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1993
    AND RESTATED DEFERRED COMPENSATION PLAN FOR DIRECTORS.
  10-D-1C. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1993
    AND RESTATED DEFERRED COMPENSATION PLAN FOR
    OFFICERS.
  10-D-1D. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1993
    DEFERRED COMPENSATION PLAN FOR OFFICERS.
  10-D-1E. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-Q
    DEFERRED COMPENSATION PLAN FOR OFFICERS.
  10-D-2 . . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1991
    REIMBURSEMENT PLAN.
  10-D-4 . . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1991
    INSURANCE PLAN.
  10-D-4A. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1990
    INSURANCE PLAN AS AMENDED.
  10-D-8 . . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1990
    SUPPLEMENTAL RETIREMENT PLAN.
  10-D-15B . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1997
    FOR OFFICERS AND KEY MANAGEMENT PERSONNEL AS AMENDED
    AUGUST 4, 1997
  10-D-15C . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 2001
  10-D-21. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1998
  10-D-22. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1998
  10-D-23. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1998
  10-D-27. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1998
  10-D-28. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1998
  10-D-29. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 1998
  10-D-31. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 2001
  10-D-32. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 2001
  10-D-33. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 2001
  10-D-34. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 2001
  10-D-35. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 2001
  10-D-36. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-K 2001
  10-D-37. . . . . . . . . . . . . . . . . . . . . . . . .  FORM 10-Q MARCH 2002
 21  SUBSIDIARIES OF THE REGISTRANT   21  FORM 10-K 1996
  *23-A-1
  23-A-2
  24  LIMITED POWER OF ATTORNEY        24


</TABLE>




Exhibit  23.1

Independent  Auditors'  Consent
 We  consent  to  the  incorporation by reference in Registration Statement Nos.
333-38722,  333-39822  and  333-42356 of Green Mountain Power Corporation of our
report  dated February 7, 2003 relating to the consolidated financial statements
of  Green  Mountain  Power Corporation as of and for the year ended December 31,
2002  appearing  in  this  Annual  Report  on  Form 10-K of Green Mountain Power
Corporation  for  the  year  ended  December  31,  2002.


/s/DELOITTE  &  TOUCHE  LLP

March  21,  2003

Exhibit  23.2
Statement  of  Company  Concerning  Consent  of  Arthur  Andersen  LLP
Prior to 2002, Arthur Andersen LLP was our independent accountants.  As a result
of  the  2002  closing  of  the  applicable Arthur Andersen LLP offices, we were
unable  to  obtain  the  consent  of Arthur Andersen LLP to the incorporation by
reference  of  their  report  in  this  Form  10-K with respect to our financial
statements  as of December 31, 2001, and for the fiscal years ended December 31,
2001  and  2000.  We  have dispensed with the requirement under Section 7 of the
Securities Act of 1933, as amended (the "Securities Act"), to file their consent
in  reliance on Rule 437(a) promulgated under the Securities Act. Because Arthur
Andersen LLP has not consented to the incorporation by reference of their report
in  this  Form 10-K, a person who purchases the Company's securities in reliance
upon  such  report  may  be  unable to recover against Arthur Andersen LLP under
Section  11  of  the Securities Act for any untrue statements of a material fact
contained  in  the  financial  statements  audited  by  Arthur  Andersen  LLP
incorporated  by reference or any omissions to state a material fact required to
be  stated  therein.

89
89

                                                                      EXHIBIT 24

                                POWER OF ATTORNEY
                                -----------------

     We,  the  undersigned directors of Green Mountain Power Corporation, hereby
severally  constitute  Christopher  L.  Dutton,  Mary  G.  Powell, and Robert J.
Griffin,  and  each of them singly, our true and lawful attorney with full power
of  substitution,  to  sign  for us and in our names in the capacities indicated
below,  the  Annual  Report on Form 10-K of Green Mountain Power Corporation for
the  fiscal year ended December 31, 2002, and generally to do all such things in
our  name  and  behalf  in  our capacities as directors to enable Green Mountain
Power  Corporation  to comply with the provisions of the Securities Exchange Act
of 1934, as amended, all requirements of the Securities and Exchange Commission,
and all requirements of any other applicable law or regulation, hereby ratifying
and  confirming  our  signatures  as they may be signed by our said attorney, to
said  Annual  Report.

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

/s/Christopher  L.  Dutton  President  and  Director     March  6,  2003
--------------------------
Christopher  L.  Dutton      (Principal  Executive
                            Officer)

/s/Nordahl  L.  Brue                              March  13,  2003
--------------------
Nordahl  L.  Brue            Chairman  of  the  Board

/s/Elizabeth  A.  Bankowski                         March  11,  2003
---------------------------
Elizabeth  A.  Bankowski      Director

/s/William  H.  Bruett                         March  17,  2003
----------------------
William  H.  Bruett           Director

/s/Merrill  O.  Burns                         March  14,  2003
---------------------
Merrill  O.  Burns            Director

/s/Lorraine  E.  Chickering                    March  12,  2003
---------------------------
Lorraine  E.  Chickering      Director

/s/John  V.  Cleary                         March  10,  2003
-------------------
John  V.  Cleary              Director

/s/David  R.  Coates                         March  4,  2003
--------------------
David  R.  Coates             Director

/s/Euclid  A.  Irving                         March  10,  2003
---------------------
Euclid  A.  Irving            Director


91

                                   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.

                                           GREEN  MOUNTAIN  POWER  CORPORATION



    Date:  March  24,  2003                    By:  /s/  Christopher  L. Dutton
           -
                                             Christopher  L.  Dutton,  President
                                             and  Chief  Executive  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/ Christopher L. Dutton_   President, Chief Executive          March 24, 2003
---------------------------
Christopher  L.  Dutton         Officer,  and  Director


 /s/  Mary G. Powell_______   Chief Operating Officer,            March 24, 2003
---------------------------
   Mary  G.  Powell             Senior  Vice  President

 /s/  Robert  J.  Griffin   Controller,  Treasurer               March  24, 2003
-------------------------
   Robert  J.  Griffin          (Principal  Accounting  Officer)

     *Nordahl  L.  Brue       )     Chairman  of  the  Board

     *Elizabeth  Bankowski

     *William  H.  Bruett      )

     *Merrill  O.  Burns       )

     *David  R.  Coates         )

     *Lorraine  E.  Chickering   )

     *John  V.  Cleary        )
                               Directors
     *Euclid  A.  Irving      )


*By:  _/s/ Christopher L. Dutton                                  March 24, 2003
      --------------------------
     Christopher  L.  Dutton
     (Attorney  -  in  -  Fact)
















I,  Christopher  L.  Dutton,  certify  that:
1.  I  have  reviewed  this  annual  report on Form 10-K of Green Mountain Power
Corporation;

2.  Based  on  my  knowledge,  this  annual  report  does not contain any untrue
statement  of a material fact or omit to state a material fact necessary to make
the  statements  made, in light of the circumstances under which such statements
were  made,  not  misleading  with  respect to the period covered by this annual
report;

3.  Based  on  my  knowledge,  the  financial  statements,  and  other financial
information  included  in  this  annual  report,  fairly present in all material
respects  the  financial  condition, results of operations and cash flows of the
registrant  as  of,  and  for,  the  periods  presented  in  this annual report;

4.  The  registrant's  other  certifying  officers  and  I  are  responsible for
establishing  and  maintaining disclosure controls and procedures (as defined in
Exchange  Act  Rules  13a-14  and  15d-14)  for  the  registrant  and  we  have:

a)  designed  such  disclosure  controls  and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is  made  known  to  us by others within those entities, particularly during the
period  in  which  this  annual  report  is  being  prepared;

b)  evaluated  the  effectiveness  of  the  registrant's disclosure controls and
procedures  as  of a date within 90 days prior to the filing date of this annual
report  (the  "Evaluation  Date");  and

c)  presented  in  this annual report our conclusions about the effectiveness of
the  disclosure  controls  and  procedures  based  on  our  evaluation as of the
Evaluation  Date;

5. The registrant's other certifying officers and I have disclosed, based on our
most  recent evaluation, to the registrant's auditors and the audit committee of
registrant's  board of directors (or person performing the equivalent function):

a)  all significant deficiencies in the design or operation of internal controls
which  could  adversely  affect  the  registrant's  ability  to record, process,
summarize  and  report  financial  data and have identified for the registrant's
auditors  any  material  weaknesses  in  internal  controls;  and

b)  any  fraud,  whether  or  not  material,  that  involves management or other
employees who have a significant role in the registrant's internal controls; and

6.  The  registrant's  other  certifying  officers  and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard  to  significant  deficiencies  and  material  weaknesses

Date:  March  24,  2003

/s/Christopher  L.  Dutton
--------------------------

Christopher  L.  Dutton,  Chief  Executive  Officer  and  President














I,  Robert  J.  Griffin,  certify  that:
1.  I  have  reviewed  this  annual  report on Form 10-K of Green Mountain Power
Corporation;

2.  Based  on  my  knowledge,  this  annual  report  does not contain any untrue
statement  of a material fact or omit to state a material fact necessary to make
the  statements  made, in light of the circumstances under which such statements
were  made,  not  misleading  with  respect to the period covered by this annual
report;

3.  Based  on  my  knowledge,  the  financial  statements,  and  other financial
information  included  in  this  annual  report,  fairly present in all material
respects  the  financial  condition, results of operations and cash flows of the
registrant  as  of,  and  for,  the  periods  presented  in  this annual report;

4.  The  registrant's  other  certifying  officers  and  I  are  responsible for
establishing  and  maintaining disclosure controls and procedures (as defined in
Exchange  Act  Rules  13a-14  and  15d-14)  for  the  registrant  and  we  have:

a)  designed  such  disclosure  controls  and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is  made  known  to  us by others within those entities, particularly during the
period  in  which  this  annual  report  is  being  prepared;

b)  evaluated  the  effectiveness  of  the  registrant's disclosure controls and
procedures  as  of a date within 90 days prior to the filing date of this annual
report  (the  "Evaluation  Date");  and

c)  presented  in  this annual report our conclusions about the effectiveness of
the  disclosure  controls  and  procedures  based  on  our  evaluation as of the
Evaluation  Date;

5. The registrant's other certifying officers and I have disclosed, based on our
most  recent evaluation, to the registrant's auditors and the audit committee of
registrant's  board of directors (or person performing the equivalent function):

a)  all significant deficiencies in the design or operation of internal controls
which  could  adversely  affect  the  registrant's  ability  to record, process,
summarize  and  report  financial  data and have identified for the registrant's
auditors  any  material  weaknesses  in  internal  controls;  and

b)  any  fraud,  whether  or  not  material,  that  involves management or other
employees who have a significant role in the registrant's internal controls; and

6.  The  registrant's  other  certifying  officers  and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard  to  significant  deficiencies  and  material  weaknesses

Date:  March  24,  2003

/s/Robert  J.  Griffin
----------------------

Robert  J.  Griffin,  Treasurer  and  Controller  (Principal  Financial Officer)