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, 2003
                         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 FEBRUARY 27, 2004, WAS APPROXIMATELY $132,657,931 BASED ON
THE  CLOSING PRICE OF $26.27 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 FEBRUARY 27, 2004, WAS
5,049,788
                       DOCUMENTS INCORPORATED BY REFERENCE
     The  Company's Definitive Proxy Statement relating to its Annual Meeting of
Stockholders  to  be  held  on  May  20,  2004,  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.




<PAGE>


Green  Mountain  Power  Corporation
Form  10-K  for  the  fiscal  year  ended  December  31,  2003
Table  of  contents                              Page

Part  I
Item  1,  Business                                      3

Item  2,  Properties                              16

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,  Financial  Statements  and  Supplementary  Data     41

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

Item  9A,  Controls  and  Procedures                    79

Items  10  through  13,  Certain  Officer  Information     79

Item  14,  Principal  Accountant  Fees  and  Services          79

Item  15,  Exhibits,  Financial  Statement  Schedules,     80
     And  Reports  on  Form  8-K




















<PAGE>

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 2003 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 service territory with approximately one
quarter  of Vermont's population.  We serve approximately 89,000 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, 2003 were as
follows:
*     26.9  percent  from  residential  customers;
*     26.4  percent  from  small  commercial  and  industrial  customers;
*     17.1  percent  from  large  commercial  and  industrial  customers;
*     28.1  percent  from  sales  to  other  utilities;  and
*     1.5  percent  from  other  sources.
     See  the Annual Report and MD and A for further information about revenues.

     During  2003,  our  energy  resources  for  retail  and  wholesale sales of
electricity,  excluding  purchases  made  pursuant  to  the contract with Morgan
Stanley  Capital  Group, Inc. (the "Morgan Stanley Contract") discussed under MD
and  A-Power  Contract  Commitments,  were  obtained  as  follows:
*     35.4  percent  from  hydroelectric sources (28.1 percent Hydro-Quebec, 4.5
percent  Company-owned,  and  2.8  percent  independent  power  producers);
*     37.4 percent from a nuclear generating source (the Entergy Nuclear Vermont
Yankee,  LLC  ("ENVY")  nuclear  plant  described  below);
*     3.5  percent  from  wood;
*     1.3  percent  from  natural  gas;
*     2.7  percent  from  oil;  and
*     0.5  percent  from  wind.
     The  remaining  19.2 percent was purchased on a short-term basis from other
utilities  through  the  Independent System Operator of New England ("ISO-NE" or
"ISO  New  England"),  formerly  the  New  England  Power  Pool  ("NEPOOL").
     In  2003,  we  estimate  that  we  purchased or generated in excess of 90.0
percent  of  our  energy  resources to satisfy our retail and wholesale sales of
electricity under long-term arrangements, including the Morgan Stanley Contract.
Remaining  retail  and  wholesale  sales  were  met  through  short-term  market
purchases  and represent volumetric differences between purchase commitments and
our  customers'  retail  demand.  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 ENVY.  We have a 33.6 percent equity interest in Vermont Yankee
Nuclear  Power  Corporation  ("Vermont  Yankee"  or "VY"), which has a long-term
power  supply  contract with ENVY 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  United  States.  The  ISO-NE  was created to manage the operations of
NEPOOL,  effective  May  1,  1999.  ISO-NE operates a market for all New England
states  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,  to  replace  energy  repurchased  by
Hydro-Quebec  under  an  arrangement negotiated in 1997 and to replace power not
delivered  under  our contracts and entitlements due to outages, curtailments or
other  events  that  result  in  reduced  deliveries.  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 ENVY 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,
                                                      2003         2002         2001         2000         1999
                                                   -----------  -----------  -----------  -----------  -----------
<S>                                                <C>          <C>          <C>          <C>          <C>
Total capability (MW) . . . . . . . . . . . . . .       393.9        406.9        408.0        411.1        393.2
Net system peak . . . . . . . . . . . . . . . . .       330.2        342.0        341.2        323.5        317.9
                                                   -----------  -----------  -----------  -----------  -----------
Reserve (MW). . . . . . . . . . . . . . . . . . .        63.7         64.9         66.8         87.6         75.3
                                                   ===========  ===========  ===========  ===========  ===========
Reserve % of peak . . . . . . . . . . . . . . . .        19.3%        19.0%        19.6%        27.1%        23.7%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . .     838,855      901,998      951,146    1,053,223    1,095,738
Wind. . . . . . . . . . . . . . . . . . . . . . .      10,828       11,458       12,135       12,246        7,956
Nuclear . . . . . . . . . . . . . . . . . . . . .     884,585      771,781      736,420      803,303      731,431
Conventional steam. . . . . . . . . . . . . . . .   2,524,233    2,431,115    2,670,249    2,704,427    2,328,267
Internal combustion . . . . . . . . . . . . . . .      12,603        4,090       18,291       35,699       12,312
Combined cycle. . . . . . . . . . . . . . . . . .      68,488       81,362       72,653       73,433       99,962
                                                   -----------  -----------  -----------  -----------  -----------
                    Total production. . . . . . .   4,339,592    4,201,804    4,460,894    4,682,331    4,275,666
Less non-firm sales to other utilities. . . . . .   2,284,003    2,104,172    2,365,809    2,573,576    2,152,781
                                                   -----------  -----------  -----------  -----------  -----------
Production for firm sales . . . . . . . . . . . .   2,055,589    2,097,632    2,095,085    2,108,755    2,122,885
Less firm sales and  lease transmissions. . . . .   1,937,376    1,951,959    1,956,232    1,954,898    1,920,257
                                                   -----------  -----------  -----------  -----------  -----------
Losses and company use (MWH). . . . . . . . . . .     118,213      145,673      138,853      153,857      202,628
                                                   ===========  ===========  ===========  ===========  ===========
Losses as a % of total production . . . . . . . .        2.72%        3.47%        3.11%        3.29%        4.74%
System load factor (***). . . . . . . . . . . . .        71.1%        70.0%        70.1%        74.2%        76.2%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . .        19.3%        21.5%        21.3%        22.5%        25.6%
Wind. . . . . . . . . . . . . . . . . . . . . . .         0.2%         0.3%         0.3%         0.3%         0.2%
Nuclear . . . . . . . . . . . . . . . . . . . . .        20.4%        18.3%        16.5%        17.1%        17.1%
Conventional steam. . . . . . . . . . . . . . . .        58.2%        57.9%        59.9%        57.8%        54.5%
Internal combustion . . . . . . . . . . . . . . .         0.3%         0.1%         0.4%         0.8%         0.3%
Combined cycle. . . . . . . . . . . . . . . . . .         1.6%         1.9%         1.6%         1.6%         2.3%
                                                   -----------  -----------  -----------  -----------  -----------
                  Total . . . . . . . . . . . . .       100.0%       100.0%       100.0%       100.0%       100.0%
                                                   ===========  ===========  ===========  ===========  ===========

Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . .     581,047      553,294      549,151      558,682      544,447
Commercial & industrial - small . . . . . . . . .     703,036      695,504      691,029      704,126      688,493
Commercial & industrial - large . . . . . . . . .     645,271      689,618      710,944      683,296      664,110
Other . . . . . . . . . . . . . . . . . . . . . .       4,986        9,773        2,030        6,713        3,138
                                                   -----------  -----------  -----------  -----------  -----------
Total retail sales and lease transmissions. . . .   1,934,340    1,948,189    1,953,154    1,952,817    1,900,188
Sales to Municipals & Cooperatives (Rate W) . . .       3,036        3,770        3,078        2,081       20,069
                                                   -----------  -----------  -----------  -----------  -----------
Total Requirements Sales. . . . . . . . . . . . .   1,937,376    1,951,959    1,956,232    1,954,898    1,920,257
Other Sales for Resale. . . . . . . . . . . . . .   2,284,003    2,104,172    2,365,809    2,573,576    2,152,781
                                                   -----------  -----------  -----------  -----------  -----------
Total sales and  lease transmissions(MWH) . . . .   4,221,379    4,056,131    4,322,041    4,528,474    4,073,038
                                                   ===========  ===========  ===========  ===========  ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . .      74,693       73,861       73,249       72,424       71,515
Commercial and industrial small . . . . . . . . .      13,344       13,165       12,976       12,746       12,438
Commercial and industrial large . . . . . . . . .          25           29           30           23           23
Other . . . . . . . . . . . . . . . . . . . . . .          65           65           65           65           66
                                                   -----------  -----------  -----------  -----------  -----------
             Total. . . . . . . . . . . . . . . .      88,127       87,120       86,320       85,258       84,042
                                                   ===========  ===========  ===========  ===========  ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . .       12.98        12.96        13.33        12.50        12.32
Commercial & industrial - small . . . . . . . . .       10.40        10.44        10.90        10.00         9.88
Commercial & industrial - large . . . . . . . . .        7.41         7.31         7.70         6.51         6.55
                                                   -----------  -----------  -----------  -----------  -----------
Total retail including lease. . . . . . . . . . .       10.22        10.09        10.44         9.52         9.47
                                                   ===========  ===========  ===========  ===========  ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . .       7,779        7,491        7,497        7,717        7,617
Revenues including lease revenues . . . . . . . .  $    1,010   $      971   $      999   $      965   $      938
</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", or the "Board"), which extends to retail rates,
services  and  facilities,  securities  issues  and  various other matters.  The
separate  Vermont Department of Public Service (the "Department," or the "DPS"),
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 the public advocate 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  certain loads.  All such agreements must be approved by the VPSB.  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 2003.
     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  2003.

     On  July  17,  1997, the FERC approved our Open Access Transmission Tariff,
and  on August 30, 1997 we filed our compliance 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 have not
experienced  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.  The  amounts  appropriated  are  not  material.
     The  re-licensing  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  late  2004.  When repairs are
complete, we expect the project to be re-licensed for a 30-year term.  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 August 14, 2003, we filed with the VPSB and the Department an integrated
resource  plan  pursuant  to  Vermont  Statute 30 V.S.A.   218c.  That filing is
pending  before  the  VPSB.

RECENT  RATE  DEVELOPMENTS
The  VPSB issued an order on December 22, 2003 approving the Company's 2003 Rate
Plan (the "2003 Rate Plan"), jointly proposed by the Company and the Department.
Principal  terms  of  the  2003  Rate  Plan  include:
     Allows  the  Company to raise rates 1.9 percent, effective January 1, 2005;
and  0.9  percent  effective  January 1, 2006, if the increases are supported by
cost  of  service  schedules  submitted  60  days  prior to the effective dates.
     Allows  the  Company  the opportunity to file for rate increases during the
period  from  January  1,  2003  to  January  1, 2007 if the Company experiences
extraordinary  events, such as repair costs due to an ice storm or other natural
disaster.
     Reduces  the  Company's allowed return on equity from 11.25 percent to 10.5
percent  for  the  period  beginning  January  1,  2003  to  January  1,  2007.
     Approves  a  three-year  economic development agreement for IBM, as long as
IBM  does  not  reduce  employment  by more than five percent during the period.
     Provides  for  recovery  of  various  regulatory  assets,  including  the
remediation  of  the Pine Street environmental superfund site in Burlington, VT.


SINGLE  CUSTOMER  DEPENDENCE
     The  Company  had  one major retail customer, IBM, metered at two locations
that  accounted for 16.6 percent, 17.3 percent and 19.2 percent of the Company's
retail operating revenues in 2003, 2002 and 2001, respectively.  No other retail
customer  accounted  for  more  than  1.0 percent of our revenue during the past
three  years.
     IBM has reduced its Vermont workforce by approximately 2,500 since 2001, to
a  level  of  approximately  6,000  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  that  would  result  from  a
hypothetical  shutdown  of  the IBM facility to be in the range of five to eight
percent,  inclusive  of  projected  declines  in  sales to other 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.
     In  March  2002,  voters  in the Town of Rockingham, Vermont ("Rockingham")
approved  an article authorizing Rockingham to create a municipal utility and to
acquire  the electric distribution systems of the Company and/or Central Vermont
Public  Service  Corporation  located  within the Rockingham.  In November 2003,
Rockingham  notified  the Company that the town intended to initiate proceedings
before the town selectboard to condemn the Company's distribution and associated
property  located  within the town.  The Company sought and obtained in December
2003 a preliminary injunction from the State Superior Court prohibiting the town
from  proceeding  with  condemnation  before  the  selectboard.  The  Company
successfully  argued  that  Vermont  law  required Rockingham to pursue any such
municipalization  effort by petition to the VPSB, which is required to determine
both  the fair value of any assets subject to municipalization and the amount of
damages  to  the  utility  caused  by  severance  of  the  property  subject  to
municipalization.  The  preliminary  injunction remains in effect and Rockingham
has  not  filed  any petition with the VPSB seeking to municipalize assets.  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.  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 other 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 could potentially 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.
     There  are  currently  no  regulatory proceedings, court actions or pending
legislative  proposals  to  adopt  electric  industry  restructuring in Vermont.
Legislation  has  been  introduced  in the Vermont legislature that would permit
(but  not  require) the Company to negotiate with individual customers to permit
such  customers to procure their own electric power supply requirements, subject
to  VPSB  approval.  We cannot predict whether this legislation will be enacted.
If  enacted, the Company would not negotiate any such arrangement unless, in our
estimation,  the  arrangement  assured  the  Company  of  full  recovery  of any
resulting  stranded  costs  and that the Company's financial condition would not
otherwise  be  adversely  affected.
     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.  For further
information  regarding  Competition  and  Restructuring,  See Item 7. MD and A -
Regulatory  Risk  and  Other  Risk.

CONSTRUCTION  AND  CAPITAL  REQUIREMENTS
     Our  capital  expenditures for 2001 through 2003 and projected for 2004 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.  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.  ("Morgan  Stanley").  In August 2002, the Morgan
Stanley  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 Morgan Stanley Contract, see Note K
of  Notes.



     We  generated,  purchased or transmitted 2,364,130 MWh of energy for retail
and  requirements  wholesale  customers for the twelve months ended December 31,
2003.  The  corresponding  maximum one-hour integrated demand during that period
was  330.2 MW on August 5, 2003.  This compares to the previous all-time peak of
342.0  MW  on  August 15, 2002.  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 12/31/2003      of annual peak
                                    MWH     percent     KW     percent
                                 ---------  --------  -------  --------
<S>                              <C>        <C>       <C>      <C>
Wholly-owned plants:
Hydro . . . . . . . . . . . . .    107,406      4.5%   32,870      8.9%
Diesel and Gas Turbine. . . . .     12,603      0.5%   50,623     13.6%
Wind. . . . . . . . . . . . . .     10,828      0.5%      480      0.1%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . .     12,030      0.5%    6,968      1.9%
Stony Brook I . . . . . . . . .     43,833      1.9%   27,113      7.3%
McNeil. . . . . . . . . . . . .     25,328      1.1%    6,443      1.7%
Long Term Purchases:
Vermont Yankee/ENVY . . . . . .    884,585     37.4%  100,554     27.1%

Hydro Quebec. . . . . . . . . .    664,225     28.1%  114,174     30.8%
Stony Brook I . . . . . . . . .     24,655      1.0%   12,382      3.3%
Other:
Independent Power Producers . .    125,465      5.3%   19,286      5.2%
NEPOOL and Short-term purchases    453,172     19.2%      400      0.1%
                                 ---------  --------  -------  --------
Net Own Load. . . . . . . . . .  2,364,130    100.0%  371,293    100.0%
                                 =========  ========  =======  ========
</TABLE>
Vermont  Yankee.
     On  July  31,  2002, Vermont Yankee completed the sale of its nuclear power
plant  to  "ENVY".  In  addition  to  the  sale  of  the  generating  plant, the
transaction  calls  for  ENVY, 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.
     Prices  under  the Power Purchase Agreement between VY and ENVY (the "PPA")
range  from  $39 to $45 per megawatt-hour for the period beginning January 2003.
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  ENVY  plant.
     Prior  to  the  sale  of the VY plant to ENVY, the 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.  The  Company  expects  to amortize
(recover) these costs beginning in 2005 under the Company's 2003 Rate Plan.  The
Company  received  a  credit of approximately $600,000 from VY and has requested
permission  from  the  VPSB  to  apply  this  credit  to reduce the $2.0 million
regulatory asset.     Our ownership share of VY has increased from approximately
19.0  percent  last  year  to  approximately 33.6 percent currently, due to VY's
purchase  of  certain  minority  shareholders'  interests.  VY's  primary  role
consists  of administering its power supply contract with ENVY and its contracts
with  VY's  present  sponsors.  Our  entitlement  to energy produced by the ENVY
nuclear  plant  has  remained  at  20  percent  of  plant  production.

     Under  our  Capital  Funds  Agreement  with VY, we are 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  ENVY  power is unavailable, the costs of replacement
power occasionally exceed those costs that we would have incurred for ENVY power
purchased  from  Vermont  Yankee.  Replacement power is available to us from the
ISO-NE  and  through contractual arrangements with other utilities.  Replacement
power  costs  can  adversely  affect  cash  flow,  and,  unless  deferred and/or
recovered in rates, such costs could 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  and  recovery  of  such  costs.
     The  ENVY  nuclear  plant's  current  operating license expires March 2012.
     During  the  year  ended  December 31, 2003, we used 884,585 MWh of Vermont
Yankee  energy  (supplied  by  ENVY)  representing  37.4  percent  of  the  net
electricity  generated  and  purchased ("net power supply") by the Company.  The
average  cost  of  Vermont  Yankee  electricity  in  2003  was  $0.043  per kWh.
     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  approximately  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;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  originate  at  the  Des Cantons Substation on the Hydro-Quebec system near
Sherbrooke,  Canada  and  traverse  a portion of eastern Vermont and extend to a
converter  terminal  located  in  Comerford, New Hampshire.  VETCO was formed to
construct  and  operate  the portion of Phase I within the United States.  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.  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.  The
participants  in  this  project,  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, 2003, the present value of the Company's obligation
was  approximately  $4,647,000.  The Company's projected future minimum payments
under the Phase II support agreements are approximately $387,000 for each of the
years  2004-2008  and  an  aggregate  of  $2,712,000  for  the  years 2009-2015.
     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  in such companies.  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, 2003, the capital structure of such
corporations was approximately 44 percent common equity and 56 percent long-term
debt.  See  Note  B  and  Note  J  of  Notes.

Hydro-Quebec
     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 (the "VJO
Contract").  Under  these two schedules, we purchase 114.2 MW from Hydro-Quebec.
In  November  1996, we entered into an arrangement (the "9701 arrangement") with
Hydro-Quebec under which Hydro-Quebec paid $8,000,000 to the Company in exchange
for  certain  power  purchase  options.  See  Item  7.  MD  and A - Power Supply
Expenses,  Power  Contract  Commitments  and  Note  K  of  Notes.
     During  2003,  we  used 392,990 MWh under Schedule B, and 271,235 MWh under
Schedule  C3  of  the  VJO  Contract, representing 28.1 percent of our net power
supply.  The  average cost of Hydro-Quebec electricity in 2003 was approximately
$0.07  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 power on short
notice  and  generally  for  brief  periods  of  time  when  required to balance
electricity supply with demand.  Opportunity purchases are also arranged when it
is  possible  to  purchase  power for less than it would cost us to generate the
power  with  our  own  sources.  Purchases  may also help us save on replacement
power  costs during an outage of one of our base load sources.  Opportunity sale
prices  are  generally  set  so  as  to  recover  all  of the forecasted fuel or
production  costs  and  to  recover some, if not all, associated capacity costs.
During  2003, the Company purchased 453,172 MWh representing 19.2 percent of the
Company's  net  power  supply  at  an  average  cost  of  $0.06  per  kWh.


     During  2002,  the  FERC  accepted  ISO-NE's  request  to  implement  a SMD
governing  wholesale  energy  sales  in New England.  ISO-NE 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.  ISO-NE and NEPOOL
have  committed  to facilitation of a stakeholder process to examine alternative
pricing  options,  including  alternatives  to  nodal pricing, and to file their
report  with FERC in July 2004.  We believe that nodal pricing could result in a
material  adverse  impact on our power supply or transmission costs, if adopted.
     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 2003, we used 68,488 MWh from this plant representing 2.9 percent of
our net power supply at an average cost of $0.087 per kWh.  See Notes I and K 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  2003, we used 12,030 MWh from this unit representing 0.5 percent of
our  net  power  supply  at  an  average  cost  of  $0.06 per kWh, based only on
operation,  maintenance,  and  fuel  costs  incurred during 2003.  See Note I of
Notes.

     McNeil  Station.  The  J.C.  McNeil  station (the "McNeil Plant"), 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 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  2003, we used 25,328 MWh from this unit representing 1.1 percent of
our  net  power  supply  at  an  average  cost  of $0.055 per kWh, based only on
operation,  maintenance,  and  fuel  costs  incurred during 2003.  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-appointed
purchasing  agent under a variety of long-term 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's  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 2003 was approximately 34.03
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  2003,  through our direct contracts and VEPPI, we purchased 125,465 MWh
of  qualifying  facilities  production representing 5.3 percent of our net power
supply  at  an  average  cost  of  $0.122  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  2003,  Company  owned  hydroelectric  plants  produced  107,406  MWh,
representing 4.5 percent of our net power supply at an average cost of $0.03 per
kWh  based on operating and maintenance expenses, excluding depreciation expense
and  amortization  of  licensing  costs.  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 the New York Power Authority 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  2003,  our  retail  and  requirements  wholesale  sales were
provided  by  the  following  fuel  sources:
*     35.4  percent  from  hydroelectric sources (28.1 percent Hydro-Quebec, 4.5
percent  Company-owned,  and  2.8  percent  independent  power  producers;
*     37.4  percent  from  a nuclear generating source (the ENVY nuclear plant);
*     3.5  percent  from  wood;
*     1.3  percent  from  natural  gas;
*     2.7  percent  from  oil;
*     0.5  percent  from  wind;  and
*     19.2  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  2003.  None 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 330,503 tons of
wood  chips  and mill residue, 423,310 gallons of fuel oil, and 31 million cubic
feet  of  natural gas in 2003.  The McNeil plant, assuming any needed regulatory
approvals  are  obtained,  is  forecasting  2004 consumption of wood chips to be
400,000  tons,  fuel  oil  of  70,000  gallons and natural gas consumption of 36
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 expenditures 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  2003,  the  project  produced  10,828 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,  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,  2003,  the  Company  had 196 employees, exclusive of
temporary  employees.  The  Company considers its relations with employees to be
excellent.

ENERGY  EFFICIENCY
     In  2003,  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.  A charge per KW and per KWH is applied.  The
purpose  of these charges is to apply equal efficiency charges across Vermont to
customers  with  similar  usage,  regardless  of their local utility rates.  The
charge  represents  two to three percent of each customer's total electric bill.
The  funds  we  collect are remitted to a fiscal agent representing the State of
Vermont.

RATE  DESIGN
     The  Company  seeks  to design rates to encourage efficient electrical use.
Since  1976,  we  have  offered  optional  time-of-use rates for residential and
commercial  customers.  Currently,  approximately  1,800  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.
At  December  31,  2003, approximately 1,700 of the Company's largest customers,
comprising  approximately  51  percent  of  retail revenues, received service on
mandatory  time-of-use  rates.     As  a result of the VPSB approval of the 2003
Rate  Plan,  the  Company  will file with the VPSB a new fully-allocated cost of
service  study  and  rate  re-design,  which will allocate the Company's revenue
requirement  among  all customer classes on the basis of current costs.  The new
rate  design  will  be subject to VPSB approval and is not expected to adversely
affect  operating  results.


DISPATCHABLE  AND  INTERRUPTIBLE  SERVICE  CONTRACTS
     In  2003,  we  had  27  dispatchable  power  contracts:  22  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  business  in  the  process  of  completing dissolution.  For
information  regarding our remaining unregulated businesses, see Note A and Note
L  of  Notes.

EXECUTIVE  OFFICERS

The names, ages, and positions of our Executive Officers, in alphabetical order,
as  of  March  15,  2004  are:
Christopher  L.  Dutton    55
     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       47
     Chief  Financial  Officer  since  December 2003.  Vice President since July
2003.  Treasurer  since February 2002.  Controller from October 1996 to December
2003.  Manager  of  General  Accounting  from  1990  to  1996.
Walter  S.  Oakes         57
     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          43
     Senior  Vice  President-Chief  Operating  Officer since April 2001.  Senior
Vice  President-Customer  and  Organizational  Development from December 1999 to
April  2001.  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, Ms. Powell was President
of  HRworks, Inc., a human resources management firm, from January 1997 to March
1998.
Donald  J.  Rendall      48
     Vice  President,  General  Counsel and Corporate Secretary since July 2002,
March  2002, and December 2002, respectively.  Prior to joining the Company, Mr.
Rendall was a principal in the Burlington, Vermont law firm of Sheehey, Furlong,
Rendall  &  Behm,  P.C.  from  1988  to  February  2002.
Stephen  C.  Terry       61
     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.

     The Board of Directors of the Company and its wholly owned subsidiaries, as
appropriate, elects officers for one-year terms to 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 67.6 MW
and  an  estimated  aggregate claimed capability of 61.2 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:
*     33.6  percent  of  the  outstanding  common  stock  of Vermont Yankee and,
through  its  contract with ENVY, we are entitled to 20.0 percent (106.2 MW of a
total  531  MW)  of  the  capacity  of  the  ENVY  nuclear  generating  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, 2003, approximately 2 miles of 115 kV
transmission  lines,  10  miles  of  69  kV transmission lines, 5 miles of 44 kV
transmission lines, 244 miles of 34.5 kV transmission lines, and 2 miles of 13.8
kV  transmission  lines.  Our  distribution  system included approximately 2,573
miles  of overhead lines of 2.4 to 34.5 kV and 420 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 905,000 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 Turbine . . . . . .  Berlin, VT       Berlin #5        Oil        56.6
Turbine . . . . . . . .  Colchester, VT   Gorge #16        Oil        16.1
Wind. . . . . . . . . .  Searsburg, VT    Searsburg        Wind        5.9
Jointly Owned
Steam . . . . . . . . .  Yarmouth, ME     Wyman #4         Oil         7.1
Steam . . . . . . . . .  Burlington, VT   McNeil           Wood/Gas    6.6  (2)
Combined. . . . . . . .  Ludlow, MA       Stony Brook #1   Oil/Gas    31.0
Total Winter Capability                                              167.2
                                                                     =====
</TABLE>

(1)  Reservoir  has  been drained, dam awaiting repairs by the State of Vermont.
(2)  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.

CORPORATE  HEADQUARTERS
     Our headquarters and main service center are located in Colchester Vermont,
one  of  the  most  rapidly  growing  areas  of  our  service  territory.

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 - Other Risks, Environmental Matters,
Rates,  and  Note  I  of  Notes.

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


<PAGE>


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  2002  and  2003:

<TABLE>
<CAPTION>



                 HIGH    LOW
                ------  ------
<S>             <C>     <C>
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
2003
First Quarter.  $21.19  $19.02
Second Quarter   21.78   20.00
Third Quarter.   22.72   20.06
Fourth Quarter   23.84   21.98
</TABLE>
The  number  of  common  stockholders  of  record  as  of  February 18, 2004 was
approximately  5,119.


     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>
2002  $ 0.1375  $ 0.1375  $ 0.1375  $ 0.1900
2003  $ 0.1900  $ 0.1900  $ 0.1900  $ 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 increased its dividend from an annual rate of $0.76 per share
to $0.88 per share during February 2004, and intends to increase the dividend in
a measured consistent manner until the payout ratio falls between 50 percent and
70  percent  of anticipated earnings, so long as financial and operating results
permit.  We  believe  this  payout  ratio  to  be  consistent with that of other
electric  utilities  having  similar  risk  profiles.
<TABLE>
<CAPTION>

ITEM  6.   SELECTED  FINANCIAL  DATA

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


                                                                   2003       2002       2001       2000       1999
                                                                 ---------  ---------  ---------  ---------  ---------
In thousands, except per share data
<S>                                                              <C>        <C>        <C>        <C>        <C>
Operating Revenues. . . . . . . . . . . . . . . . . . . . . . .  $280,470   $274,608   $283,464   $277,326   $251,048
Operating Expenses. . . . . . . . . . . . . . . . . . . . . . .   265,164    259,528    267,005    272,066    243,102
      Operating Income. . . . . . . . . . . . . . . . . . . . .    15,306     15,080     16,459      5,260      7,946
                                                                 ---------  ---------  ---------  ---------  ---------
Other Income
      AFUDC - equity. . . . . . . . . . . . . . . . . . . . . .       387        233        210        284        134
      Other . . . . . . . . . . . . . . . . . . . . . . . . . .     1,692      2,252      2,163      2,422      3,319
      Total other income. . . . . . . . . . . . . . . . . . . .     2,079      2,485      2,373      2,706      3,453
                                                                 ---------  ---------  ---------  ---------  ---------
Interest Charges
      AFUDC - borrowed. . . . . . . . . . . . . . . . . . . . .      (267)      (103)      (188)      (228)       (91)
      Other . . . . . . . . . . . . . . . . . . . . . . . . . .     7,324      6,273      7,227      7,485      7,274
          Total interest charges. . . . . . . . . . . . . . . .     7,057      6,170      7,039      7,257      7,183
                                                                 ---------  ---------  ---------  ---------  ---------
Net Income (Loss) from continuing operations before . . . . . .    10,328     11,395     11,793        709      4,216
   preferred dividends
Net Income (Loss) from discontinued operations, including
   provisions for loss on disposal. . . . . . . . . . . . . . .        79         99       (182)    (6,549)    (7,279)
Dividends on Preferred Stock. . . . . . . . . . . . . . . . . .         3         96        933      1,014      1,155
                                                                 ---------  ---------  ---------  ---------  ---------
Net Income (Loss)Applicable
      to Common Stock . . . . . . . . . . . . . . . . . . . . .  $ 10,404   $ 11,398   $ 10,678   $ (6,854)  $ (4,218)
                                                                 =========  =========  =========  =========  =========
Common Stock Data
 Basic earnings per share-continuing operations . . . . . . . .  $   2.08   $   2.02   $   1.93   $  (0.06)  $   0.57
 Basic earnings per share-discontinued operations . . . . . . .  $   0.01   $   0.02   $  (0.03)  $  (1.19)  $  (1.36)
 Basic earnings per share . . . . . . . . . . . . . . . . . . .  $   2.09   $   2.04   $   1.90   $  (1.25)  $  (0.79)
                                                                 =========  =========  =========  =========  =========
 Diluted earnings (loss) per share from continuing operations .  $   2.01   $   1.96   $   1.88   $  (0.06)  $   0.57
 Diluted earnings (loss) per share from discontinued operations  $   0.01   $   0.02   $  (0.03)  $  (1.19)  $  (1.36)
 Diluted earnings (loss) per share. . . . . . . . . . . . . . .  $   2.02   $   1.98   $   1.85   $  (1.25)  $  (0.79)
                                                                 =========  =========  =========  =========  =========
Cash dividends declared per share . . . . . . . . . . . . . . .  $   0.60   $   0.60   $   0.55   $   0.55   $   0.55
 Weighted average shares outstanding-basic. . . . . . . . . . .     4,980      5,592      5,630      5,491      5,361
 Weighted average share equivalents outstanding-diluted . . . .     5,140      5,756      5,789      5,491      5,361
</TABLE>





<TABLE>
<CAPTION>

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

                                           2003      2002      2001      2000      1999
                                         --------  --------  --------  --------  --------
In thousands
<S>                                      <C>       <C>       <C>       <C>       <C>
ASSETS
Utility Plant, Net. . . . . . . . . . .  $228,862  $223,476  $196,858  $194,672  $192,896
Other Investments . . . . . . . . . . .    13,706    21,552    20,945    20,730    20,665
Current Assets. . . . . . . . . . . . .    31,688    31,432    36,183    53,652    33,238
Deferred Charges. . . . . . . . . . . .    55,590    60,390    72,468    46,036    41,853
Non-Utility Assets. . . . . . . . . . .     1,105       995     1,075     1,518    11,099
Total Assets. . . . . . . . . . . . . .  $330,951  $337,845  $327,529  $316,608  $299,751
                                         ========  ========  ========  ========  ========

CAPITALIZATION AND LIABILITIES
Common Stock Equity . . . . . . . . . .  $ 99,915  $ 91,722  $101,277  $ 92,044  $100,645
Redeemable Cumulative Preferred Stock .         -        55    12,560    12,795    14,435
Long-Term Debt, Less Current Maturities    93,000    93,000    74,400    72,100    81,800
Capital Lease Obligation. . . . . . . .     4,963     5,287     5,959     6,449     7,038
Current Liabilities . . . . . . . . . .    22,715    38,491    38,841    68,109    36,708
Deferred Credits and Other. . . . . . .   108,868   107,349    92,791    61,794    59,125
Non-Utility Liabilities . . . . . . . .     1,490     1,941     1,701     3,317         -
Total Capitalization and Liabilities. .  $330,951  $337,845  $327,529  $316,608  $299,751
                                         ========  ========  ========  ========  ========
</TABLE>
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF  OPERATIONS.
EXECUTIVE  OVERVIEW - Green Mountain Power Corporation (the "Company") generates
virtually  all  of  its  earnings  from  retail  electricity  sales.  Our retail
electricity sales grow at an average annual rate of between one and two percent,
about  average  for  most  electric  utility  companies  in  New England.  While
wholesale  revenues  are  significant,  they have relatively minor impact on our
operating  results and financial condition.  The Company is regulated and cannot
adjust  prices  of retail electricity sales without regulatory approval from the
Vermont  Public  Service  Board  ("VPSB").

     The  Company increased its dividend in February 2004 from an annual rate of
$0.76 per share to $0.88 per share.  The Company's dividend payout ratio remains
comparatively  low, at less than 45 percent of 2003 earnings.  We expect to grow
our dividend payout ratio to between 50 and 70 percent over the next five years,
in  line  with other electric utilities having similar risk profiles, so long as
financial  and  operating  results  permit.

     Fair  regulatory  treatment  is  fundamental  to  maintaining the Company's
financial  stability.  Rates must be set at levels to recover costs, including a
market rate of return to equity and debt holders.  In December 2003, the Company
received  approval  from  the  VPSB  of a new rate plan covering the period 2003
through  2006,  which  sets rates at levels the Company believes will provide an
improved  opportunity  to  recover  our  costs,  and to earn our allowed rate of
return.

     Power  supply  expenses are equivalent to approximately 70 percent of total
revenues.  The  Company's  need  to  seek  rate  increases  from  its  customers
frequently  moves  in  tandem with increases in our power supply costs.  We have
entered into long-term power supply contracts for most of our energy needs.  All
of  our  power supply contract costs are currently being recognized in the rates
we  charge our customers.  The risks associated with our power supply resources,
including  outage, curtailment, and other delivery risks, the timing of contract
expirations, the volatility of wholesale prices, and other factors impacting our
power  supply  resources  and  how  they relate to customer demand are discussed
below under Item 7a, "Quantitative and Qualitative Disclosure about Market Risk,
and  Other  Risk  Factors."




     We  also  discuss  other  risks, including load risk related to our largest
customer, International Business Machines Corporation ("IBM"), and contingencies
that  could  have  a  significant  impact  on  future  operating results and our
financial  condition.

     Growth  opportunities  beyond  the  Company's  normal  investment  in  its
infrastructure  are also discussed, and include a planned increase in our equity
investment  in  Vermont  Electric  Power  Company,  Inc. ("VELCO") and a planned
increase  in  sales  of  utility  services.

     In this section, we explain the general financial condition and the results
of  operations for 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  affect  our  overall  financial  condition.

     Our  critical  accounting  policies  are  discussed  below  under  Item 7a,
"Quantitative And Qualitative Disclosures About Market Risk, And Other Factors,"
under  "Liquidity  and  Capital  Resources  -  Pension," in Note A, "Significant
Accounting Policies," and in Note H, "Pension and Retirement Plans."  Management
believes the most critical accounting policies include the timing of expense and
revenue  recognition  under  the regulatory accounting framework within which we
operate;  the  manner  in which we account for certain power supply arrangements
that  qualify  as  derivatives;  the  assumptions that we make regarding defined
benefit  plans;  and revenue recognition, particularly as it relates to unbilled
and  deferred  revenues.  These  accounting  policies,  among others, affect the
Company's  significant  judgments  and  estimates used in the preparation of its
consolidated  financial  statements.

     There  are statements in this section that contain projections or estimates
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  include:
     regulatory  and  judicial  decisions  or  legislation
     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
     industry  restructuring  and  cost  recovery  (including  stranded  costs)
     weather

We  address  these  items  in  more  detail  below.

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

                        EARNINGS SUMMARY     YEARS ENDED

                                                  2003     2002     2001
                                                 -------  -------  -------
<S>                                              <C>      <C>      <C>
Consolidated earnings per share of common stock  $ 2.02   $ 1.98   $ 1.85
Consolidated return on average common equity. .   10.76%   11.03%   11.02%

</TABLE>
     The  Company  reported  consolidated  earnings of $2.02 per share of common
stock,  diluted,  in  2003 compared to consolidated earnings of $1.98 per share,
diluted, in 2002.  The improvement in earnings per share reflected reduced power
supply  expenses  to  serve  retail  sales,  an increase in sales to residential
customers  and  a  reduction  in  the number of common stock shares outstanding.
These  favorable  developments  more  than  offset  increased administrative and
general  costs,  a  reduction in the Company's allowed rate of return, increased
interest  expense  in  2003,  and  a  decrease  in  the  recognition of deferred
revenues,  compared  with  2002.

     Our  financial  health improved during 2001 and 2002.  As a result, we were
able  to  reduce significantly our cost of capital in the fourth quarter of 2002
by  issuing  new  long-term  debt and using a portion of the proceeds to acquire
approximately  812,000  shares of our common stock.  Our 2003 earnings per share
improved  by  approximately  $0.09  per  share as a result of the stock buyback.


In December 2003, the VPSB approved a rate plan for the period 2003 through 2006
(the  "2003  Rate  Plan"),  jointly  proposed  by  the  Company  and the Vermont
Department  of  Public  Service  (the "Department" or the "DPS").  The 2003 Rate
Plan  provides  the Company with a stable, predictable rate path through 2006, a
plan  for  full  recovery  of  the Company's principal regulatory assets, and an
improved  opportunity for the Company to earn its allowed rate of return through
2006.  The  2003  Rate  Plan calls for no retail rate increases in 2003 or 2004,
then  scheduled  increases  of  1.9  percent  effective January 1, 2005, and 0.9
percent  effective  January  1,  2006.  The  2003  Rate  Plan sets the Company's
allowed return on equity from core utility operations at 10.5 percent, effective
with  2003,  and  provides  for an earnings cap at that level through 2006.  The
2003  Rate  Plan  is  summarized  in  more  detail  below  under  "Rates."


The  VPSB's  January  2001  rate order (the "2001 Settlement Order") allowed the
Company  to  defer revenues of approximately $8.5 million, generated by leveling
winter/summer  rates  during  2001, to help offset costs and realize our allowed
rate  of  return  during the 2001-2003 period.  We recognized approximately $1.1
million  of these deferred revenues to achieve our allowed rate of return during
2003, compared with approximately $4.4 million recognized in 2002.  The VPSB has
permitted  the  Company  to  carry  over  unused  deferred  revenues  totaling
approximately  $3.0  million  to  2004  as  part  of  the  2003  Rate  Plan.



The  improvement  in  earnings from continuing operations in 2002, compared with
2001,  resulted primarily from lower capital costs and other operating expenses,
including:
     $0.9 million reduction in interest expense, reflecting lower interest rates
     and  average  debt  levels;
     $0.8  million  reduction  in  preferred  stock  dividends,  reflecting  the
Company's  redemption  of  outstanding  preferred  stock;  and
     Recognition  of  $4.4  million in revenue deferred from 2001 under the 2001
Settlement  Order.

     These  favorable  results  were  partially  offset by increased maintenance
expense,  transmission  expense  and  power  supply  expense  to  serve  retail
customers,  compared  to  2001.

ITEM  7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, AND OTHER
RISK  FACTORS.
     We  consider  our  principal  risks  to  include  power  supply  risks, our
regulatory  environment  (particularly  as  it relates to the Company's periodic
need  for  rate  relief),  risks  associated  with  our principal customer, IBM,
pension  and  postretirement  healthcare costs and weather.  Discussion of these
and  other  risks, as well as factors contributing to mitigation of these risks,
follows.

POWER  SUPPLY  RISK.
     The  Company's most significant power supply contracts are the Hydro-Quebec
Vermont  Joint  Owners  ("VJO")  Contract  (the  "VJO Contract") and the Vermont
Yankee  Nuclear  Power  Corporation  ("VY"  or  "Vermont  Yankee") contract (the
"Vermont  Yankee  Contract")  which  are  summarized  in  the  following  table.

<TABLE>
<CAPTION>

                          2003     2003     2002     2002     Contract
                           MWh    $/MWh     MWh    $/MWh   Expires
                         -------  ------  -------  ------  -------
<S>                      <C>      <C>     <C>      <C>     <C>
VJO Contract. . . . . .  664,225  $69.81  724,708  $66.11     2015
Vermont Yankee Contract  884,585  $43.08  771,782  $44.55     2012

</TABLE>
     All  of  the  Company's  power  supply  contract  costs are currently being
recovered  through  rates  approved  by  the  VPSB.

     We  expect  approximately  90  percent  of  our  estimated  customer demand
("load")  requirements  through  2006  to  be  met by these contracts and by our
generation  and  other  power  supply  resources.  These contracts and resources
significantly  reduce  the  Company's exposure to volatility in wholesale energy
market  prices.  The  Company's  power  supply  contracts  are described in more
detail  below  under  the  heading  "Power  Contract  Commitments."

     A  primary  factor  affecting future operating results is the volatility of
the  wholesale  electricity  market.  Implementation  of New England's wholesale
market  for  electricity  has  increased  volatility  of wholesale power prices.
Periods  frequently  occur  when weather, availability of power supply resources
and  other  factors  cause  significant  differences between customer demand and
electricity  supply.  Because  electricity cannot be stored, in these situations
the  Company  must  buy  or  sell  the  difference  into  a marketplace that has
experienced  volatile  energy  prices.  Volatility  and market price trends also
make  it  more  difficult  to extend or enter into new power supply contracts at
prices  that  avoid  the  need  for  rate  relief.

     During  2002,  we estimate that the Company paid an additional $1.0 million
for  replacement  power  as  the  result of an unscheduled outage at the Vermont
Yankee nuclear power plant.  While the Vermont Yankee plant has had an excellent
operating  record,  future  unscheduled  outages  could  occur  at  times  when
replacement  energy  costs  are  above  Vermont  Yankee  Contract  costs.

     We sometimes experience energy delivery deficiencies under the VJO Contract
as  a  result of outages or other problems with the transmission interconnection
facilities  over which we schedule deliveries.  When such deficiencies occur, we
purchase  replacement energy on the wholesale market, usually at prices that are
higher  than  VJO  Contract  costs.

     Under  the  VJO  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
contract.  Hydro-Quebec  exercised  the  first  of these load reduction options,
effective  for  the  year 2003.  The net cost of Hydro-Quebec's exercise of this
option increased power supply expense during 2003 by approximately $1.2 million.
During  2003, Hydro-Quebec exercised its second option to reduce the load factor
for  2004, which we estimate will increase power supply expense by approximately
$1.0  million.  We  expect Hydro-Quebec to exercise its third option in 2004 for
deliveries  occurring  principally  during  2005,  at  an estimated cost of $1.0
million  to  $1.2  million,  based  on current wholesale market prices for 2005.

Hydro-Quebec  also  retains  the  right under the VJO Contract 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.  Hydro-Quebec  has  not
exercised  this  right  and  has  not  communicated  to  the Company any present
intention  to  do  so.

Under  the  VJO  Contract,  the  VJO, including the Company, have two options to
adjust  deliveries  by a five percent load factor.  These options cannot be used
to  offset Hydro-Quebec's reductions through 2005, but may be used after 2005 to
manage  power  supply  costs.

     The Company has established a risk management program designed 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.  These transactions are
used  to  hedge  the  risk  of  fossil  fuel  and  spot market electricity price
increases.  Some of these transactions present the risk of potential losses from
adverse  changes in commodity prices.  Our risk management policy specifies risk
measures,  the  amount  of tolerable risk exposure, and authorization limits for
transactions.  Our  principal  power  supply  contract  counter-parties  and
generators,  Hydro-Quebec,  Entergy  Nuclear  Vermont  Yankee,  LLC ("ENVY") and
Morgan  Stanley  Capital  Group,  Inc.  ("Morgan  Stanley"),  all currently have
investment  grade  credit  ratings.

     The  Company  has  a  contract  with  Morgan  Stanley  (the "Morgan Stanley
Contract")  that  is  used  to hedge our power supply costs against increases in
fossil  fuel  prices.  Morgan  Stanley  purchases  the majority of the Company's
power  supply  resources at index prices for fossil fuel resources and specified
prices  for  contracted resources and then sells power to the Company at a fixed
rate  to  serve  pre-established  load  requirements.  This contract, along with
other  power  supply commitments, allows us to fix the cost of most of our power
supply  requirements,  subject  to  power resource availability and other risks.
The  Morgan Stanley Contract is described in more detail below under the heading
"Power Contract Commitments."  The Morgan Stanley Contract is a derivative under
Statement  of  Financial  Accounting  Standards  No.  133  ("SFAS  133")  and is
effective through December 31, 2006.  Management has estimated the fair value of
the  future  net  benefit  of  this  arrangement  at  December  31,  2003,  is
approximately  $4.0  million.

     We  currently  have  an arrangement that grants Hydro-Quebec an option (the
"9701  arrangement")  to  call  power  at  prices  that are expected to be below
estimated future market rates.  The 9701 arrangement is described in more detail
below  under  the  heading  "Power  Supply  Expenses."  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, 2003, is
approximately  $23.7  million.  We  sometimes  use  forward  contracts  to hedge
forecasted  calls  by  Hydro-Quebec  under  the  9701  arrangement.

     The table below presents assumptions used to estimate the fair value of the
Morgan  Stanley  Contract  and  the  9701  arrangement.  The  forward prices for
electricity  used  in  this  analysis  are consistent with the Company's current
long-term  wholesale  energy  price  forecast.
<TABLE>
<CAPTION>

                         Option Value     Risk Free     Price        Average        Contract
                             Model      Interest Rate   Volatility   Forward Price   Expires
                         -------------  --------------  -----------  --------------  -------
<S>                      <C>            <C>             <C>          <C>             <C>
Morgan Stanley Contract  Deterministic            3.4%      32%-29%  $           42     2006
9701 Arrangement. . . .  Black-Scholes            4.6%      48%-27%  $           60     2015

</TABLE>


The  table  below  presents  the Company's market risk of the Morgan Stanley and
Hydro-Quebec  derivatives,  estimated  as  the  potential  loss  in  fair  value
resulting  from  a  hypothetical  ten percent adverse change in wholesale energy
prices,  which  nets  to  approximately $1.2 million.  Actual results may differ
materially from the table illustration.  Under an accounting order issued by the
VPSB,  changes  in  the  fair  value  of  derivatives  are  deferred.
<TABLE>
<CAPTION>

Commodity Price Risk           At December 31, 2003
                         Fair Value(Cost)    Market Risk
                         -----------------  -------------
                          (in thousands)
<S>                      <C>                <C>
Morgan Stanley Contract  $          3,990   $      2,160
9701 Arrangement. . . .           (23,724)        (3,342)
                         -----------------  -------------
                                  (19,734)        (1,182)
</TABLE>

REGULATORY  RISK

     Management  believes  that  fair  regulatory  treatment  is  crucial  to
maintaining  its  financial stability, including its ability to attract capital.

Vermont  is  the  only state in the New England region that has not adopted some
form  of  electric industry restructuring.  The Company, like all other electric
utilities  in  Vermont, accordingly operates as a vertically integrated electric
utility,  with  the  obligation  to serve all customers in our service territory
with  electrical  transmission,  distribution  and energy supplies sufficient to
satisfy  customer  load  requirements.

Vermont  does  not  have  a fuel or purchased-power adjustment clause that would
allow  increases  in power supply costs to be recovered immediately in the rates
we  charge  customers.  Historically,  however,  the  VPSB  has allowed electric
utilities to defer material unexpected increases in power supply costs to future
periods  to  permit  recovery in future rates.  Vermont law also allows electric
utilities  to  seek  temporary rate increases if deemed necessary by the VPSB to
provide  adequate  and  efficient  service  or  to preserve the viability of the
utility.

     Electric  utility  rates  in Vermont are set based on the 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 filed its last
retail  rate  case  during  1998.  Since  that  time we have deferred a material
amount  of expenditures as regulatory assets.  These regulatory assets have been
judged as probable of recovery by management.  As of December 31, 2003, the most
significant  regulatory  assets  not  being  recovered  in current rates are the
following:
<TABLE>
<CAPTION>

Regulatory  assets
                                    At December 31,
                                  2003         2002
                             ---------------  -------
                             (in thousands)
<S>                          <C>              <C>
Pine Street barge canal . .  $        12,954  $13,019
Demand-side management. . .            6,713    6,434
Unscheduled VY outage costs            2,178    2,002
                             ---------------  -------
Total . . . . . . . . . . .  $        21,845  $21,455
                             ===============  =======
</TABLE>
     The  2003  Rate  Plan,  approved by the VPSB in December 2003, provides for
amortization  and  recovery  of  all  of  the  regulatory  assets  listed above,
beginning January 1, 2005.  The Pine Street Barge Canal regulatory asset will be
amortized over a period of 20 years without a return on the remaining balance of
the  asset.  The  remaining  assets  will  be amortized over a five-year period.
Both  the  demand-side  management  and the unscheduled VY outage costs accrue a
return defined by the Federal Energy Regulatory Commission ("FERC") based on the
capital  structure  of  the utility ("AFUDC rate").  The AFUDC rate for 2003 for
the  Company  was  approximately  8.5  percent.

The  Company  currently  complies  with  the  provisions  of SFAS 71.  If we had
determined that the Company no longer met the criteria for following SFAS 71, at
December  31,  2003,  the  accounting  impact  would  have been an extraordinary
non-cash charge to operations of $55.5 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;
     competition  that  limited our ability to sell utility services or products
at  rates  that  will  recover  costs;  or
     regulatory  actions  that  limit  rate  relief  to  a level insufficient to
recover  costs.

     There  are  currently  no  regulatory proceedings, court actions or pending
legislative  proposals  to  adopt  electric  industry  restructuring in Vermont.
Legislation  has  been  introduced  in the Vermont legislature that would permit
(but  not  require) the Company to negotiate with individual customers to permit
such  customers to procure their own electric power supply requirements, subject
to  VPSB  approval.  We cannot predict whether this legislation will be enacted.
If  enacted, the Company would not negotiate any such arrangement unless, in our
estimation,  the  arrangement  assured  the  Company  of  full  recovery  of any
resulting  stranded  costs  and that the Company's financial condition would not
otherwise  be  adversely  affected.

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  wholesale market price of power.  We have discussed various market price
scenarios with interested parties for the purpose of identifying stranded costs.
Based  on  preliminary  market price assumptions, which are likely to change, we
estimate  the  Company's  stranded  costs  to  be  between $206 million and $252
million  over  the  life  of  the  Company's  current  contracts.

If  Vermont  adopted  retail competition or some other form of electric industry
restructuring  or  if  the  VPSB issued a regulatory order containing provisions
that  did not allow the Company to recover above-market power costs, the Company
could  be required 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.

CUSTOMER  CONCENTRATION  RISK  - IBM, the Company's largest customer, operates a
manufacturing  facility  in  Essex  Junction,  Vermont.  IBM's  electricity
requirements  for  its facility accounted for approximately 24.1, 25.7, and 26.6
percent of the Company's retail MWh sales in 2003, 2002, and 2001, respectively,
and  16.6,  17.3, and 19.2 percent of the Company's retail operating revenues in
2003, 2002, and 2001, 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 22, 2003, the
VPSB  approved  a  new  three-year agreement between the Company and IBM, ending
December 31, 2006.  The price of power under the agreement is above our marginal
costs  of providing incremental service to IBM.  The VPSB approval provides that
the  agreement automatically terminates if IBM's full-time-equivalent employment
level  at  its  Vermont  facility  served  by the agreement drops by more than 5
percent  from  the  level  on  the  date  of  VPSB  approval.

     IBM has reduced its Vermont workforce by approximately 2,500 since 2001, to
a  level  of  approximately  6,000  employees.  Company  revenue  from  sales of
electricity  to  IBM  declined  $1.8  million  in  2003 compared with 2002.  Our
operating  results  were not adversely impacted by the reduction in sales to IBM
due  to continued revenue growth in other customer classes and because the gross
margin  on  sales  to  IBM  is  relatively  low.  If  we  experienced a material
reduction  in earnings as a result of significantly lower retail sales, we would
seek  a  retail  rate  increase from the VPSB.  The Company is permitted to seek
such  a  rate  increase  request  under our approved 2003 Rate Plan.  We are 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, that a
hypothetical  shutdown  of the IBM facility would require a retail rate increase
for  all  our  remaining  customers  in  the  range  of  five  to eight percent.

PENSION AND POSTRETIREMENT HEALTH CARE RISK - Other critical accounting policies
involve  the  Company's  defined  benefit pension and postretirement health care
benefit  plans.  The  reported costs of these plans depend upon numerous factors
relating  to  actual  plan  experience  and  assumptions  of  future experience.

     Pension  and  postretirement  health  care  costs  are  affected  by actual
employee  demographics,  Company  contributions  to  the plans, earnings on plan
assets,  and,  for our postretirement health care plan, health care cost trends.
The Company contributed $1.0 million and $3.5 million to its pension plan during
2002  and  2003, respectively, and we expect to contribute between $2.0 and $3.0
million  during  2004.

Our 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 increase or decrease 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.

On  December  17,  2003,  the  Company's  employees  ratified  a four-year labor
agreement  that  provides annual wage increases of between 3.5 and 4 percent and
improved  401(k)  and  pension  benefits for employees.  The new labor agreement
caps  future postretirement healthcare employee benefits provided by the Company
for the majority of the present workforce.  The cap on postretirement healthcare
benefits  is  set  approximately  13  percent  above 2003 costs and grows at a 3
percent  annual  rate.  This  cap should reduce the rate at which postretirement
healthcare  expenses  grow  in  the  future.

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.  The  liability was recorded as a reduction to common
equity  through  a  charge  to  Other  Comprehensive  Income ("OCI").  Favorable
pension  plan  investment returns during 2003 reduced the OCI charge and related
net  liability by $587,000.  The 2002 OCI charge and the 2003 OCI benefit had no
effect  on  net  income  for  either  year.

WEATHER - The Company now uses weather insurance to mitigate some of the risk of
lost  electricity  sales  caused by unfavorable weather conditions.  The Company
has  purchased  weather  insurance  coverage  for  2004.  Coverage  is  based on
cumulative  variations  from normal weather, measured in net heating and cooling
degree-days.















RESULTS  OF  OPERATIONS
OPERATING  REVENUES  AND  MWH  SALES  - Operating revenues, megawatthour ("MWh")
sales  and  number  of customers for the years ended 2003, 2002 and 2001 were as
follows:
<TABLE>
<CAPTION>

                                           Years ended December 31,
                                    2003               2002        2001
                           -----------------------  ----------  ----------
                                             (dollars in thousands)
<S>                        <C>                      <C>         <C>
 Operating Revenues
     Retail*. . . . . . .  $               198,717  $  201,052  $  195,093
     Sales for Resale . .                   78,901      70,646      83,804
     Other. . . . . . . .                    2,852       2,910       4,567
                           -----------------------  ----------  ----------
 Total Operating Revenues  $               280,470  $  274,608  $  283,464
                           =======================  ==========  ==========

 MWH Sales-Retail . . . .                1,934,340   1,948,190   1,953,154
 MWH Sales for Resale . .                2,287,039   2,107,941   2,368,887
                           -----------------------  ----------  ----------
 Total MWH Sales. . . . .                4,221,379   4,056,131   4,322,041
                           =======================  ==========  ==========
</TABLE>
*Retail revenues include $1.1 million, $4.4 million and $0.0 million of deferred
revenue  recognized  for  2003,  2002,  and  2001,  respectively.

<TABLE>
<CAPTION>

 Average  Number  of  Customers
                             Years ended December 31,
                                2003    2002    2001
                               ------  ------  ------
<S>                            <C>     <C>     <C>
    Residential . . . . . . .  74,693  73,861  73,249
    Commercial and Industrial  13,369  13,194  13,006
    Other . . . . . . . . . .      65      65      65
                               ------  ------  ------
 Total Number of Customers. .  88,127  87,120  86,320
                               ======  ======  ======
</TABLE>
     Comparative  changes  in  operating  revenues  are  summarized  below:

<TABLE>
<CAPTION>

  Change in Operating Revenues      2002 to      2001 to
                                    2003          2002
                               ---------------  ---------
                                (In thousands)
<S>                            <C>              <C>
 Retail Rates . . . . . . . .  $         (912)  $  6,471
 Retail Sales Volume. . . . .          (1,423)      (512)
 Resales and Other Revenues .           8,197    (14,815)
                               ---------------  ---------
 Change in Operating Revenues  $        5,862   $ (8,856)
                               ===============  =========
</TABLE>
In  2003,  total electricity sales increased 4.1 percent compared with 2002, due
to  increased wholesale sales and sales to residential and commercial customers,
partially  offset  by  decreased sales to industrial customers.  Total operating
revenues  increased $5.9 million, or 2.1 percent, compared with 2002 as a result
of  the  following:
     Increased  wholesale  revenues  of $8.3 million, primarily due to increased
system  sales  during  peak  demand  periods and increased sales to Hydro-Quebec
under  the  9701  arrangement;
     Increased  retail  residential  revenues  of  $3.2 million, or 4.5 percent,
arising  from  increased  sales  of  electricity;  and
     Increased  retail  small  commercial  and  industrial  ("C&I")  revenues of
$900,000,  or  1.3  percent,  arising  from  increased  sales  of  electricity.

These  increases  were  partially  offset  for  the  following  reasons:
     The  Company  recognized  $1.1  million in deferred revenues under the 2001
Settlement  Order,  reduced  from  $4.4  million  recognized  in  2002.
     Decreased  retail  large C&I revenues of $2.6 million, or 1.7 percent, when
compared  with  2002,  resulting  from a decline in sales of electricity to this
customer  class.

     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  Morgan  Stanley 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  2001 Settlement Order.  Increased sales to residential and
commercial  customers  also  contributed  to  higher  retail revenues, partially
offset  by  a  decline  in  revenues  from  IBM.

POWER  SUPPLY  EXPENSES  - Power supply expenses constituted 74.4, 74.5 and 75.3
percent  of  total  operating  expenses  for  the  years  2003,  2002, and 2001,
respectively.

     Power  supply  expenses  increased by $3.9 million, or 2.0 percent, in 2003
when  compared  with  2002,  and  resulted  from  the  following:
     an  $8.3  million  increase  in  the  cost  of  power purchased for resale;
     a  $2.7  million  increase  in  power supply expenses under agreements with
Hydro-Quebec;
     higher  costs  of  electricity supplied by independent power producers; and
     higher  wholesale  prices  for  electricity.

     These  increases  were  partially offset by an $8.9 million decrease in the
cost  of power under our contract with Morgan Stanley and lower unit prices from
Vermont  Yankee.

     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  Morgan  Stanley  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:
     a $6.2 million increase in the cost of power purchased from Morgan Stanley;
     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  CONTRACT  COMMITMENTS  - On February 11, 1999, the Company entered into a
contract  with Morgan Stanley (the "Morgan Stanley Contract") designed to manage
price  risks  associated  with changing fossil fuel prices.  In August 2002, the
Morgan  Stanley  Contract  was  modified  and  extended  to  December  31, 2006.

Under  the  Morgan  Stanley  Contract, on a daily basis, and at Morgan Stanley's
discretion,  we  sell power to Morgan Stanley 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.  Morgan  Stanley sells to the Company, at a predefined
price,  power  sufficient  to  serve  pre-established load requirements.  Morgan
Stanley  is  also  responsible  for  scheduling  supply  resources.  We  remain
responsible  for resource performance and availability.  Morgan Stanley provides
no  coverage  against major unscheduled power supply outages.  Beginning January
1,  2004,  the  Company  will  reduce the power that it sells to Morgan Stanley.
Some  of  our  power-supply  resources,  including  purchases  pursuant  to  our
Hydro-Quebec  and  Vermont  Yankee  contracts, which were sold to Morgan Stanley
through  2003,  will no longer be included in the Morgan Stanley Contract.  This
reduction in sales to Morgan Stanley is expected to reduce wholesale revenues by
approximately  $64 million and correspondingly to reduce power supply expense by
a  similar  amount.  We  do  not  expect  this  change  to  adversely affect the
Company's  opportunity  to  earn  its  allowed  rate  of  return  during  2004.


     The  Company's  current  purchases under the VJO Contract with Hydro-Quebec
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,  beginning  in  November  1995.

     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  also parties to the contract would be required to purchase
their  proportionate  share  of  the  power supply entitlement of any defaulting
utility.  The Company is not aware of any instance where this provision has been
invoked  by  Hydro-Quebec.

     Under the Company's 9701 arrangement, 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  VJO Contract, which ends in 2015, Hydro-Quebec may purchase up to
52,500  MWh  on  an  annual basis ("option A") at the VJO Contract energy price,
which  is  substantially  below current market prices.  The cumulative amount of
energy  that  may be purchased under option A may not exceed 950,000 MWh (52,500
MWh  in  each  contract  year.)

     Over the same period, Hydro-Quebec may exercise an option to purchase up to
200,000  MWh  on  an annual basis at the VJO Contract energy price ("option B").
The  cumulative  amount  of  energy that may be purchased under option B may not
exceed 600,000 MWh.  As of December 31, 2003, Hydro-Quebec had purchased 513,000
MWh  under  option  B.  The  Company  expects Hydro-Quebec to call its remaining
entitlements  under  option  B  during  2004  and  2005.

     In  2003,  Hydro-Quebec  exercised  option  A  and option B, and called for
delivery  to third parties at a net expense to the Company of approximately $4.5
million,  including  capacity  charges.

     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.

     We  believe that it is probable that Hydro-Quebec will call options A and B
for  2004, and the Company has purchased replacement power at a net cost of $3.2
million.  The  Company has also covered 54 percent of expected calls during 2005
at  a  net  cost  of  $1.1  million.

VERMONT  YANKEE  NUCLEAR  POWER  CORPORATION
     On  July  31,  2002, Vermont Yankee completed the sale of its nuclear power
plant  to  ENVY.  As part of the sale transaction, Vermont Yankee entered into a
Power  Purchase  Agreement ("PPA") with ENVY pursuant to which ENVY is obligated
to  provide  20  percent  of the plant output to the Company through 2012, which
represents  approximately  35  percent of our energy requirements.  Prices under
the  PPA  range  from  $39 to $45 per MWh for the period beginning January 2003,
substantially  lower than our forecasted cost if Vermont Yankee had continued to
own  and operate the plant facilities.  In 2002, contract prices ranged from $49
to  $55  under  the PPA, higher than the forecasted cost of continued ownership.
The PPA contains a provision known as the "low market adjuster," which calls for
a  downward  adjustment  in  the  price if market prices for electricity fall by
defined amounts beginning in November 2005.  If market prices rise, however, PPA
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  ENVY  plant.

     The  Company  received $8.2 million in October 2003, representing its share
of the Vermont Yankee power plant sale proceeds, and used the proceeds to retire
debt.

     The Vermont Yankee sale required various regulatory approvals, all of which
were  granted  on  terms  acceptable to the parties to the transaction.  Certain
intervenor parties to the VPSB approval proceeding appealed the VPSB approval to
the  Vermont Supreme Court.  The Court rejected the appeal and affirmed the VPSB
approval  during  2003.

OTHER  OPERATING  EXPENSES - Other operating expenses increased $3.5 million, or
24.5  percent,  in  2003  compared with 2002 primarily due to increased employee
benefit  expenses  and  expenses  related  to  corporate  governance.  A  cap on
post-retirement  healthcare  benefits,  improved market returns and benefit plan
funding  should  reduce  growth  in administrative and general expenses in 2004.

     Other  operating  expenses decreased $1.7 million, or 10.9 percent, in 2002
compared  with  2001.  The  decrease  was  primarily  due  to reduced consulting
expenses of approximately $1.0 million and reduced distribution expenses of $0.6
million.

TRANSMISSION  EXPENSES  -  Transmission  expenses  decreased  $438,000,  or  2.9
percent, in 2003 compared with 2002, due to decreased congestion costs allocated
by  ISO New England to Vermont utilities in conjunction with transition to a new
standard  market  design  ("SMD").  See  discussion  below.

     Transmission  expenses  increased  $1.1  million,  or  7.7 percent, in 2002
compared  with  2001.  The  Company's  relative  share  of transmission expenses
varies  with  the  peak  demand  recorded on Vermont's transmission system.  The
Company's  share  of  those expenses increased due to its increased load growth,
relative  to other Vermont utilities, and also because of increased transmission
investment  by  VELCO.
     The  Independent  System  Operator  of  New  England  ("ISO-NE" or "ISO New
England")  was  created  to  manage the operations of the New England Power Pool
("NEPOOL"), effective May 1, 1999.  ISO-NE operates a market for all New England
states  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.
     During  2002,  the  FERC  accepted  ISO-NE's  request  to  implement  a SMD
governing  wholesale  energy  sales  in New England.  ISO-NE 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.  ISO-NE and NEPOOL
have  committed  to facilitation of a stakeholder process to examine alternative
pricing  options,  including  alternatives  to  nodal pricing, and to file their
report  with FERC in July 2004.  We believe that nodal pricing could result in a
material  adverse  impact  on  our  power  supply  and/or transmission costs, if
adopted.

     On  October  31,  2003,  ISO-NE,  together  with  New  England's  principal
transmission  system  owners  including VELCO, filed a request for approval of a
regional  transmission  organization  for  New England ("RTO-NE").  The proposed
RTO-NE  would  become  the  provider  of  regional  transmission  service in New
England,  with  operational  control of the bulk power system and responsibility
for administering markets currently operated and administered by ISO-NE.  If the
RTO is approved by FERC, the current ISO-NE agreement with the New England Power
Pool  ("NEPOOL"),  the  Restated  NEPOOL  Agreement,  the  NEPOOL  Open  Access
Transmission  Tariff  and  individual  local tariffs currently maintained by New
England  transmission  owners  would  terminate  and be superseded by new RTO-NE
agreements.  Also  on  October  31,  2003,  certain  transmission  owners in New
England,  including  the  Company,  reached  an  agreement  to  submit a tariff,
agreements  and other documents to FERC to include costs associated with certain
transmission  facilities, known as the Highgate Facilities, of which the Company
is  a part owner, in region-wide rates as set forth in the RTO-NE proposal.  The
Company cannot predict whether or when FERC will approve the RTO-NE proposal, or
what  modifications  may  be  made  to  the  proposal while pending before FERC.

     VELCO,  the owner and operator of Vermont's principal electric transmission
system  assets,  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.  We  own
approximately  29  percent of VELCO.  The proposed Northwest Reliability Project
must  be  approved  by the VPSB.  Several Vermont municipalities, citizen groups
and  individuals  have  intervened  in the VPSB proceedings to oppose or request
modifications  to  the  project.  If  approved, the project is estimated to cost
approximately  $130 million through 2007.  VELCO intends to finance the costs of
constructing  the Northwest Reliability Project in part through increased equity
investment.  The  Company  plans to invest approximately $20 million in VELCO to
support this and other transmission projects through 2007.  Under current NEPOOL
and  ISO-NE  rules, which require qualifying large transmission project costs to
be  shared  among  all New England utilities, most of the costs of the Northwest
Reliability  Project  will  be allocated throughout the New England region, with
Vermont utilities responsible for approximately five percent of allocated costs.
     In  August  2003, a coalition of New England public utility commissions and
other  parties  challenged  the  NEPOOL  and ISO-NE transmission cost allocation
rules.  On  December  18,  2003,  FERC rejected this challenge.  FERC's order is
subject  to pending requests for rehearing and has been appealed to the US Court
of  Appeals  for  the D.C. Circuit.  If the current transmission cost allocation
rules  are  modified  or  eliminated,  Vermont utilities, including the Company,
could be required to bear a greater proportion, and potentially all, of the cost
of  the  Northwest  Reliability  Project.

MAINTENANCE  EXPENSES - Maintenance expenses increased $211,000, or 2.4 percent,
in  2003  compared  with  2002,  due  to  increased  expenditures  related  to
hydroelectric  generation  and  transmission  facilities.

     Maintenance  expenses  increased  $1.7  million,  or  24.6 percent, in 2002
compared  with  2001  due  to increased expenditures related to storm damage and
right-of-way  maintenance  programs.

DEPRECIATION  AND AMORTIZATION - Depreciation and amortization expense decreased
$348,000,  or  2.5  percent,  in  2003  compared  with 2002 due to reductions in
amortization  of  conservation  and  software  programs,  partially  offset  by
increased  depreciation  of  utility  plant  in  service.

     Depreciation  and  amortization expense decreased $143,000, 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.

TAXES  OTHER  THAN INCOME - Taxes other than income taxes decreased $201,000, or
2.6  percent,  in  2003  compared with 2002 due to reductions in property taxes.
     Taxes  other  than  income taxes increased $87,000, or 1.2 percent, in 2002
compared  with  2001  due  to  an  increase  in  property  taxes.

INCOME  TAXES  - Income tax expense decreased $923,000, or 15.2 percent, in 2003
compared  with  2002  due  to  a  decrease  in  the Company's taxable income, an
increase  in  non-taxable income and the use of tax credits.  Income tax expense
decreased $905,000 in 2002 compared with 2001 due to a decrease in the Company's
taxable  income.

OTHER  INCOME  -  Other  income  decreased  $406,000,  or  16.4 percent, in 2003
compared  with  2002  due primarily to reduced earnings on investment in Vermont
Yankee  as  a  result  of  the  sale  of  the  Vermont  Yankee  plant  in  2002.

     Other income increased $112,000, or 4.7 percent, in 2002 compared with 2001
due  primarily  to  Vermont Yankee recognition of deferred tax assets arising in
conjunction  with  the  sale  of  the  Vermont  Yankee  plant, offset in part by
payments  made  to Vermont Yankee owners located outside of Vermont necessary to
close  the  sale  of  the  Vermont  Yankee  plant.

INTEREST EXPENSE - Interest expense increased $887,000, or 14.4 percent, in 2003
compared  with  2002  primarily  due to a $42 million long-term debt issuance in
December  2002.

     Interest expense decreased $869,000, 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.

DIVIDENDS  ON  PREFERRED STOCK - Dividends on preferred stock decreased $93,000,
or  96.9  percent,  in  2003  compared  with  2002, due to the repurchase of all
outstanding preferred stock during 2003.  Dividends on preferred stock decreased
$837,000, 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.

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.

PINE  STREET  BARGE  CANAL  SUPERFUND SITE - In 1999, the Company entered into a
United States District Court Consent Decree constituting a final settlement with
the  United States Environmental Protection Agency ("EPA"), the State of Vermont
and  numerous  other  parties  of claims relating to a federal Superfund site in
Burlington, Vermont, known as the "Pine Street Barge Canal."  The consent decree
resolves  claims  by the EPA for past site costs, natural resource damage claims
and  claims  for  past  and  future  remediation costs.  The consent decree also
provides  for the design and implementation of response actions at the site.  In
2003,  the  Company  expended  $2.6  million  to cover its obligations under the
consent  decree and we have estimated total future costs of the Company's future
obligations  under  the  consent  decree  to  be  $8.5  million.  The  estimated
liability  is  not  discounted,  and  it is possible that our estimate of future
costs could change by a material amount.  We have recorded a regulatory asset of
$13.0  million  to  reflect  unrecovered  past  and  future  Pine  Street costs.
Pursuant  to  the Company's 2003 Rate Plan, as approved by the VPSB, the Company
will  begin  to  amortize  past  unrecovered  costs  in  2005.  The Company will
amortize  the full amount of incurred costs over 20 years without a return.  The
amortization  will  be  allowed  in  future  rates,  without  disallowance  or
adjustment,  until  fully  amortized.

RATES
-----
RETAIL  RATE CASES - On December 22, 2003, the VPSB approved our 2003 Rate Plan,
jointly  proposed  earlier in the year by the Company and the Vermont Department
of  Public Service.  The 2003 Rate Plan covers the period from 2003 through 2006
and  includes  the  following  principal  elements:
     The Company's rates will remain unchanged through 2004.  The 2003 Rate Plan
     allows  the  Company to raise rates 1.9 percent, effective January 1, 2005,
and  an  additional 0.9 percent, effective January 1, 2006, if the increases are
supported  by cost of service schedules submitted 60 days prior to the effective
dates.  If  the Company's cost of service filings in 2005 or 2006 establish that
a  lesser  rate  increase  is  required  for  the  Company  to  meet its revenue
requirements,  the  Company  will  implement  the  lesser  rate  increase.
     The  Company  may  seek  additional  rate  increases  in  extraordinary
circumstances,  such  as  severe storm repair costs, natural disasters, extended
unanticipated  unit  outages,  or  significant  losses  of  customer  load.
     The  Company's  allowed  return  on equity is reduced from 11.25 percent to
10.5  percent, for the period January 1, 2003 through December 31, 2006.  During
the same period, the Company's earnings on core utility operations are capped at
10.5  percent.  Any excess earnings in 2004 will be applied to reduce regulatory
assets.  Excess  earnings  in  2005  or  2006 will be refunded to customers as a
credit  on  customer  bills  or  applied  to  reduce  regulatory  assets, as the
Department  directs.
     The  Company  will carry forward into 2004 $3.0 million in deferred revenue
remaining  at  December  31,  2003,  from  the  Company's  2001 Settlement Order
(summarized  below).  These revenues will be applied in 2004 to offset increased
costs  or,  if  applicable,  reduce  regulatory assets as determined by the DPS.
     The  Company  will  amortize (recover) certain regulatory assets, including
Pine Street Barge Canal environmental site costs and past demand-side management
program costs, beginning in January 2005, with those amortizations to be allowed
in  future rates.  Pine Street costs will be recovered over a twenty-year period
without  a  return.
     The  Company  will  file  with the VPSB in early 2004 a new fully-allocated
cost  of  service  study  and  rate re-design, which will allocate the Company's
revenue  requirement  among  all customer classes on the basis of current costs.
The  new  rate  design  will  be subject to VPSB approval and is not expected to
adversely  affect  operating  results.
     The Company and the Department have agreed to work cooperatively to develop
and  propose an alternative regulation plan as authorized by legislation enacted
in  Vermont in 2003.  If the Company and Department agree on such a plan, and it
is  approved  by  the  VPSB, the alternative regulation plan would supersede the
2003  Rate  Plan.

In  January  2001, the VPSB issued the 2001 Settlement Order, which included the
following:
     The  Company  received a rate increase of 3.42 percent above existing rates
and  prior  temporary  rate  increases  became  permanent;
     Rates  were  set  at  levels that recover the Company's VJO Contract costs,
effectively  ending the regulatory disallowances experienced by the Company from
1998  through  2000;
     Seasonal rates were eliminated in April 2001, which generated approximately
$8.5  million  in additional cash flow in 2001, which was deferred and available
to  be  used  to  offset  increased  costs  during  2002  and  2003;  and
     The  Company  agreed to an earnings cap on core utility operations of 11.25
percent return on equity, with amounts earned over the limit being used to write
off  regulatory  assets.

     The  2001  Settlement  Order  also  imposed  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
until  new  rates  go  into  effect,  which  will  occur  in  January  2005.

LIQUIDITY  AND  CAPITAL  RESOURCES
----------------------------------
CONSTRUCTION  AND INVESTMENTS - Our capital requirements result from the need to
construct  facilities  or  to  invest  in  programs to meet anticipated customer
demand  for  electric service.  The Company plans to invest up to $20 million in
VELCO  through 2007, subject to regulatory approval of the Northwest Reliability
Project.  See  detailed  discussion  under  "Transmission  Expenses."

     The  Company  offers  utility  services,  primarily  line  construction and
electrical  services, principally to municipal and business customers.  Sales of
these  services  have grown from approximately $700,000 in 2001 to approximately
$2.5 million in 2003.  Sales of these services have allowed the Company to serve
its  customers  more  efficiently  and  have  improved  cash  flow.
Future  capital  expenditures  are expected to approximate $20 million annually.
Expected  reductions  in  Pine  Street  remediation  costs  should  be offset by
increased  generation  expenditures.  Capital  expenditures,  net  of  customer
advances for construction, over the past three years and forecasted for 2004 are
as  follows:
<TABLE>
<CAPTION>


                Generation   Transmission   Distribution   Other*    Total
                -----------  -------------  -------------  -------  -------
                                          (In thousands)
Actual:
--------------
<S>             <C>          <C>            <C>            <C>      <C>
2001 . . . . .  $     2,323  $       1,219  $       8,567  $ 3,529  $15,638
2002 . . . . .        3,258          1,827          9,173    7,267  $21,525
2003 . . . . .        2,629          1,496          7,760  $ 7,064  $18,949
Forecast:
--------------
2004 . . . . .  $     4,122  $       4,280  $       6,036  $ 7,162  $21,600
</TABLE>
*  Other  includes Pine Street Barge Canal expenditures of $1.5 million in 2001,
$1.8  million  in  2002,  $2.5  million in 2003 and an estimated $1.1 million in
2004.

DIVIDEND  POLICY  -  The  annual dividend was $0.60 per share for the year ended
December  31,  2002.  The  annual  dividend  rate was increased by the Company's
Board  of  Directors  from $0.55 per share to $0.76 per share beginning with the
$0.19  quarterly  dividend  declared in December 2002.  On February 9, 2004, the
annual  dividend  rate  was increased from $0.76 per share to $0.88 per share, a
payout  ratio  of  approximately 44 percent based on 2003 earnings.  The Company
expects  to  increase  the  dividend in the first quarter of each year until the
payout  ratio  falls  between 50 percent and 70 percent of anticipated earnings.
We  believe  this  payout  ratio  to  be  consistent with that of other electric
utilities  having  similar  risk  profiles.

FINANCING  AND  CAPITALIZATION
     At  December  31,  2003,  our  capitalization consisted of approximately 51
percent  common  equity  and 49 percent debt, inclusive of the Company's capital
lease  obligations.

     During  June  2003,  the  Company  negotiated  a  364-day  revolving credit
agreement  (the  "Fleet-Sovereign  Agreement")  with  Fleet  Financial  Services
("Fleet")  joined by Sovereign Bank.  The Fleet-Sovereign Agreement is for $20.0
million,  unsecured,  and  allows  the  Company  to  choose any blend of a daily
variable  prime  rate  and  a  fixed  term LIBOR-based rate.  There was $500,000
outstanding  with  a weighted average rate of 4.0 percent on the Fleet-Sovereign
Agreement  at  December  31,  2003.  There  was  no  non-utility short-term debt
outstanding  at December 31, 2003 or 2002.  The Company anticipates that it will
secure  financing  that  replaces  some or all of its expiring facilities during
2004.

          During  2002,  we redeemed $5.1 million of 10.0 percent first mortgage
bonds  and  $12.5  million  of  outstanding  preferred  stock.          We  also
completed a "Dutch Auction" self-tender offer and repurchased 811,783 shares, or
approximately  14  percent,  of  the  Company's  common  stock  outstanding  for
approximately  $16.3  million  in  November  2002.

     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.

     The  credit  ratings  of the Company's first mortgage bonds at December 31,
2003  were:
<TABLE>
<CAPTION>


                      Fitch  Moody's  Standard & Poor's
                      -----  -------  -----------------
<S>                   <C>    <C>      <C>
First mortgage bonds  BBB+   Baa1     BBB
</TABLE>
During  August  2003,  our  rating  agencies  reviewed  the  Company's financial
position  and  concluded  the  following:
     Moody's  affirmed  the  Company' senior secured debt rating at Baa1, with a
stable  outlook;
     Fitch Ratings affirmed the ratings of the Company's first mortgage bonds at
BBB+  with  a  stable  outlook;  and
     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 Morgan
Stanley 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,  2003.


<TABLE>
<CAPTION>

                                                           Payments Due by Period
                                                          ----------------------
                                                                 2005 and   2007 and   After
                                          TOTAL         2004      2006      2008       2008
                                     ---------------  --------  --------  --------  --------
                                     (In thousands)
<S>                                  <C>              <C>       <C>       <C>       <C>
Long-term debt. . . . . . . . . . .  $        93,000  $      -  $ 14,000  $      -  $ 79,000
Interest on long-term debt. . . . .           76,055     6,534    13,068    11,068    45,385
Capital lease obligations . . . . .            4,963       519       958       774     2,712
Hydro-Quebec power supply contracts          623,463    49,419   101,239   101,847   370,958
Morgan Stanley Contract . . . . . .           38,664    13,602    25,062         -         -
Stony Brook contract. . . . . . . .           46,081     3,509     5,754     6,328    30,490
Vermont Yankee PPA. . . . . . . . .          288,410    35,808    67,672    67,767   117,163
                                     ---------------  --------  --------  --------  --------
    Total . . . . . . . . . . . . .  $     1,170,636  $109,391  $227,753  $187,784  $645,708
                                     ===============  ========  ========  ========  ========
</TABLE>
OFF-BALANCE  SHEET  ARRANGEMENTS  -  The  Company does not use off-balance sheet
financing  arrangements,  such  as  securitization  of  receivables or obtaining
access  to  assets  through  special  purpose  entities.  We 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, including its debt
service  costs.

OTHER  RISKS  -  In  March  2002,  voters  in  the  Town  of Rockingham, Vermont
("Rockingham")  approved an article authorizing Rockingham to create a municipal
utility  and  to acquire the electric distribution systems of the Company and/or
Central Vermont Public Service Corporation located within the town.  In November
2003,  Rockingham  notified  the  Company  that  the  town  intended to initiate
proceedings  before  the  town selectboard to condemn the Company's distribution
and  associated  property  located  within  the  town.  The  Company  sought and
obtained in December 2003 a preliminary injunction from the State Superior Court
prohibiting  the  town from proceeding with condemnation before the selectboard.
The  Company  successfully argued that Vermont law required Rockingham to pursue
any  such  municipalization effort by petition to the VPSB, which is required to
determine  both the fair value of any assets subject to municipalization and the
amount  of damages to the utility caused by severance of the property subject to
municipalization.  The  preliminary  injunction remains in effect and Rockingham
has  not  filed  any petition with the VPSB seeking to municipalize assets.  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  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
hydroelectric generating facility, filed an inquiry with the VPSB seeking review
of  certain  dam  improvements  made  by  the Company in 1995, alleging 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
in  connection  with  this  proceeding.

GOVERNANCE  - During 2003, the Securities and Exchange Commission ("SEC") issued
a  number  of  rules  amending disclosure requirements for public company annual
reports.  In  order  to  comply with such rules, the Company makes the following
disclosures:

     The  Company's  Board  of  Directors  has determined that David Coates, who
serves  on  the Company's Audit Committee, qualifies as an independent financial
expert  under  SEC  rules.

     The  Company  has  adopted a Code of Ethics and Conduct that applies to all
Company  directors  and  employees,  including the Company's principal executive
officer,  principal  financial officer, principal accounting officer and persons
performing similar functions.  The Company's code of ethics is maintained on its
website  at  "www.greenmountainpower.biz",  Who  We  Are,  Investors,  Corporate
Governance.  Upon request, the Company will provide a copy of its code of ethics
to  any  person  without  charge.  Please  send  your  inquiries to attention of
investor  relations  for the Company, 163 Acorn Lane, Colchester, Vermont 05446.

     Management believes the Company to be in compliance with all governance and
disclosure  requirements of the New York Stock Exchange, the SEC, and applicable
federal  and  state  laws,  including  the  "Sarbanes-Oxley"  Act.

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 does 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.


<PAGE>



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                 42
    Income  For  the  Years  Ended  December  31,  2003,  2002,  and  2001

Consolidated  Statements  of  Cash  Flows For the                             43
    Years  Ended  December  31,  2003,  2002,  and  2001

Consolidated  Balance  Sheets  as  of                                         44
    December  31,  2003  and  2002
Consolidated  Statements  of  Capitalization  as of                           46
    December  31,  2003  and  2002
Consolidated  Statements  of  Changes  In Shareholders Equity                 47
     For  the  Years  Ended  December  31,  2003,  2002  and  2001

Notes  to  Consolidated  Financial  Statements                                48

Quarterly  Financial  Information                                           73

Reports  of  Independent  Public  Accountants                                 74

Schedules

For  the  Years  Ended  December  31,  2003,  2002,  and  2001:

    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
      Deloitte  and  Touche  LLP                                             77
     Arthur  Andersen  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
                                                                                                     2003       2002       2001
                                                                                                   ---------  ---------  ---------
(In thousands, except per share data)
<S>                                                                    <C>                         <C>        <C>        <C>
Retail revenues                                                                                    $201,569   $203,962   $199,660
Wholesale revenues                                                                                   78,901     70,646     83,804
                                                                                                   ---------  ---------  ---------
TOTAL OPERATING REVENUES                                                                            280,470    274,608    283,464
Operating expenses-Power Supply:
  Purchases from others                                                                             189,450    188,381    196,323
  Company-owned generation                                                                            7,856      5,067      4,742
Other operating                                                                                      17,665     14,188     15,924
Transmission                                                                                         14,783     15,221     14,130
Maintenance                                                                                           9,065      8,854      7,108
Depreciation and amortization                                                                        13,803     14,151     14,294
Taxes other than income                                                                               7,422      7,623      7,536
Income taxes                                                                                          5,120      6,043      6,948
                                                                                                   ---------  ---------  ---------
    Total operating expenses                                                                        265,164    259,528    267,005
                                                                                                   ---------  ---------  ---------
OPERATING INCOME                                                                                     15,306     15,080     16,459
                                                                                                   ---------  ---------  ---------

OTHER INCOME
Equity in earnings of affiliates and non-utility operations                                           1,493      2,777      2,253
Allowance for equity funds used during construction                                                     387        233        210
                                                                                                   ---------
Other income (deductions), net                                                                          199       (525)       (90)
                                                                                                   ---------  ---------  ---------
    Total other income                                                                                2,079      2,485      2,373
                                                                                                   ---------  ---------  ---------

INTEREST CHARGES
Long-term debt                                                                                        7,021      5,214      6,073
Other                                                                                                   303      1,059      1,154
Allowance for borrowed funds used during construction                                                  (267)      (103)      (188)
                                                                                                   ---------  ---------  ---------
    Total interest charges                                                                            7,057      6,170      7,039
                                                                                                   ---------  ---------  ---------
INCOME BEFORE PREFERRED DIVIDENDS AND
DISCONTINUED OPERATIONS                                                                              10,328     11,395     11,793
Dividends on preferred stock                                                                              3         96        933
                                                                                                   ---------  ---------  ---------
INCOME FROM CONTINUING OPERATIONS                                                                    10,325     11,299     10,860

Income (Loss) from discontinued operations, net                                                          79         99       (182)
                                                                                                   ---------  ---------  ---------
NET INCOME APPLICABLE TO COMMON STOCK                                                              $ 10,404   $ 11,398   $ 10,678
                                                                                                   =========  =========  =========
EARNINGS PER SHARE
Basic earnings per share from continuing operations                                                $   2.08   $   2.02   $   1.93
Basic earnings per share from discontinued operations                                                  0.01       0.02      (0.03)
                                                                                                   ---------  ---------  ---------
Basic earnings per share                                                                           $   2.09   $   2.04   $   1.90
                                                                                                   =========  =========  =========
Diluted earnings per share from continuing operations                                              $   2.01   $   1.96   $   1.88
Diluted earnings per share from discontinued operations                                                0.01       0.02      (0.03)
                                                                                                   ---------  ---------  ---------
Diluted earnings per share                                                                         $   2.02   $   1.98   $   1.85
                                                                                                   =========  =========  =========

Weighted average shares outstanding-basic                                                             4,980      5,592      5,630
Weighted average equivalent shares outstanding-diluted                                                5,140      5,756      5,789
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME                                                        2003       2002       2001
                                                                                                   ---------  ---------  ---------
Net income                                                                                         $ 10,404   $ 11,398   $ 10,678
Minimum pension liability adjustment, net of applicable income taxes                                    587     (2,374)         -
of $400,000 expense and $1.6 million benefit, respectively                                                           -
                                                                                                              ---------
                                                                       Other comprehensive income  $ 10,991   $  9,024   $ 10,678
                                                                                                   =========  =========  =========
</TABLE>


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


<TABLE>
<CAPTION>


                             GREEN  MOUNTAIN  POWER  CORPORATION          FOR THE YEARS ENDED
                                CONSOLIDATED STATEMENTS OF CASH FLOWS          DECEMBER 31

                                                                                            2003       2002       2001
                                                                                          ---------  ---------  ---------
OPERATING ACTIVITIES:
<S>                                                                                       <C>        <C>        <C>
Income from continuing operations before preferred dividends . . . . . . . . . . . . . .  $ 10,328   $ 11,395   $ 11,793
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    13,803     14,151     14,294
Dividends from associated companies less equity income . . . . . . . . . . . . . . . . .       884         45        (19)
Allowance for funds used during construction . . . . . . . . . . . . . . . . . . . . . .      (654)      (335)      (398)
Amortization of deferred purchased power costs . . . . . . . . . . . . . . . . . . . . .       318      3,236      3,767
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     1,479      3,577        345
Benefit plan contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    (3,500)    (1,000)         -
Deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      (570)    (2,003)     1,126
Accrued purchase power contract option call. . . . . . . . . . . . . . . . . . . . . . .         -          -     (8,276)
Arbitration costs recovered (deferred) . . . . . . . . . . . . . . . . . . . . . . . . .         -          -      3,229
Rate levelization liability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    (1,121)    (4,483)     8,527
Environmental and conservation deferrals, net. . . . . . . . . . . . . . . . . . . . . .    (1,890)    (2,194)    (3,380)
Changes in:
Accounts receivable and accrued utility revenues . . . . . . . . . . . . . . . . . . . .      (189)      (896)     6,483
Prepayments, fuel and other current assets . . . . . . . . . . . . . . . . . . . . . . .    (1,188)       850        300
Accounts payable and other current liabilities . . . . . . . . . . . . . . . . . . . . .      (676)       (55)       128
Accrued income taxes payable and receivable. . . . . . . . . . . . . . . . . . . . . . .    (3,950)     5,010      1,187
Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     5,776     (1,147)    (2,512)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     2,141      2,458     (3,218)
                                                                                          ---------  ---------  ---------
Net cash provided by continuing operations . . . . . . . . . . . . . . . . . . . . . . .    20,991     28,609     33,376
Net change in discontinued segment . . . . . . . . . . . . . . . . . . . . . . . . . . .        79         99       (182)
                                                                                          ---------  ---------  ---------
Net cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . . . .    21,070     28,708     33,194

INVESTING ACTIVITIES:
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   (16,617)   (19,543)   (12,963)
Investment in associated companies . . . . . . . . . . . . . . . . . . . . . . . . . . .      (108)      (392)         -
Return of Capital from associated companies. . . . . . . . . . . . . . . . . . . . . . .     7,615        370        299
Investment in nonutility property. . . . . . . . . . . . . . . . . . . . . . . . . . . .      (198)      (206)      (212)
                                                                                          ---------  ---------  ---------
Net cash used in investing activities. . . . . . . . . . . . . . . . . . . . . . . . . .    (9,308)   (19,771)   (12,876)
                                                                                          ---------  ---------  ---------
FINANCING ACTIVITIES:
Proceeds from issuance of long term debt . . . . . . . . . . . . . . . . . . . . . . . .         -     42,000          -
Payments to acquire treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . .        (3)   (16,320)         -
(Reduction in) Proceeds from term loan . . . . . . . . . . . . . . . . . . . . . . . . .         -    (12,000)    12,000
Repurchase of preferred stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       (85)   (12,536)      (235)
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       995      1,037      1,655
Proceeds (purchases) of certificate of deposit . . . . . . . . . . . . . . . . . . . . .         -          -     16,173
Power supply option obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         -          -    (16,012)
Reduction in long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    (8,000)   (13,322)    (9,700)
Short-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    (2,000)     2,500    (15,500)
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    (3,792)    (3,393)    (4,034)
                                                                                          ---------  ---------  ---------

Net cash used in financing activities. . . . . . . . . . . . . . . . . . . . . . . . . .   (12,885)   (12,034)   (15,653)
                                                                                          ---------  ---------  ---------
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . .    (1,123)    (3,097)     4,665

Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . .     1,909      5,006        341
                                                                                          ---------  ---------  ---------

Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . .       786      1,909      5,006
                                                                                          =========  =========  =========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized). . . . . . . . . . . . . . . . . . . . . . . . . .     7,120      6,048      6,936
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     2,915      2,349      9,622
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Minimum pension liability adjustment, net. . . . . . . . . . . . . . . . . . . . . . . .      (587)     2,374          -
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>

GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                                DECEMBER 31

                                                                       2003          2002
                                                                  ---------------  --------
                                                                  (in thousands)
<S>                <C>                                            <C>              <C>
ASSETS
UTILITY PLANT
                   Utility plant, at original cost                $       324,900  $311,543
                   Less accumulated depreciation                          110,111   102,250
                                                                  ---------------  --------
                   Net utility plant                                      214,789   209,293
                   Property under capital lease                             5,047     5,287
                   Construction work in progress                            9,026     8,896
                                                                  ---------------  --------
                   Total utility plant, net                               228,862   223,476
                                                                  ---------------  --------
OTHER INVESTMENTS
                   Associated companies, at equity                          5,896    14,101
                   Other investments                                        7,810     7,451
                                                                  ---------------  --------
                   Total other investments                                 13,706    21,552
                                                                  ---------------  --------
CURRENT ASSETS
                   Cash and cash equivalents                                  786     1,909
                   Accounts receivable, less allowance for
                   doubtful accounts of $690 and $547                      17,331    17,253
                   Accrued utility revenues                                 6,729     6,618
                   Fuel, materials and supplies, at average cost            4,498     3,349
                   Prepayments                                              1,922     1,901
                   Other                                                      422       402
                                                                  ---------------  --------
                   Total current assets                                    31,688    31,432
                                                                  ---------------  --------
DEFERRED CHARGES
                   Demand side management programs                          6,713     6,434
                   Purchased power costs                                    2,574     2,323
                   Pine Street Barge Canal                                 12,954    13,019
                   Net power supply deferral                               19,734    18,405
                   Power supply derivative asset                            3,990     8,796
                   Other deferred charges                                   9,625    11,413
                                                                  ---------------  --------
                   Total deferred charges                                  55,590    60,390
                                                                  ---------------  --------
NON-UTILITY
                   Other current assets                                       217         8
                   Property and equipment                                     248       249
                   Other assets                                               640       738
                                                                  ---------------  --------
                   Total non-utility assets                                 1,105       995
                                                                  ---------------  --------

TOTAL ASSETS                                                      $       330,951  $337,845
                                                                  ===============  ========
</TABLE>


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

<TABLE>
<CAPTION>

GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                          DECEMBER 31

                                                        2003       2002
                                                      ---------  ---------
(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
5,860,854 and 5,782,496) . . . . . . . . . . . . . .  $ 19,536   $ 19,276
Additional paid-in capital . . . . . . . . . . . . .    76,081     75,347
Retained earnings. . . . . . . . . . . . . . . . . .    22,786     16,171
Accumulated other comprehensive income . . . . . . .    (1,787)    (2,374)
Treasury stock, at cost (827,639 and 827,639 shares)   (16,701)   (16,698)
                                                      ---------  ---------
Total common stock equity. . . . . . . . . . . . . .    99,915     91,722
Redeemable cumulative preferred stock. . . . . . . .         -         55
Long-term debt, less current maturities. . . . . . .    93,000     93,000
                                                      ---------  ---------
Total capitalization . . . . . . . . . . . . . . . .   192,915    184,777
                                                      ---------  ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . .     4,963      5,287
                                                      ---------  ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . . .         -         30
Current maturities of long-term debt . . . . . . . .         -      8,000
Short-term debt. . . . . . . . . . . . . . . . . . .       500      2,500
Accounts payable, trade and accrued liabilities. . .     8,493      7,431
Accounts payable to associated companies . . . . . .     6,821      8,940
Rate levelization liability. . . . . . . . . . . . .     2,970      4,091
Accrued income taxes . . . . . . . . . . . . . . . .       633      4,583
Customer deposits. . . . . . . . . . . . . . . . . .       968        898
Interest accrued . . . . . . . . . . . . . . . . . .     1,152      1,081
Other. . . . . . . . . . . . . . . . . . . . . . . .     1,178        937
                                                      ---------  ---------
Total current liabilities. . . . . . . . . . . . . .    22,715     38,491
                                                      ---------  ---------
DEFERRED CREDITS
Power supply derivative liability. . . . . . . . . .    23,724     27,201
Accumulated deferred income taxes. . . . . . . . . .    34,009     26,471
Unamortized investment tax credits . . . . . . . . .     2,848      3,130
Pine Street Barge Canal cleanup liability. . . . . .     7,356      8,833
Accumulated cost of removal. . . . . . . . . . . . .    21,238     19,947
Other deferred liabilities . . . . . . . . . . . . .    19,693     21,767
                                                      ---------  ---------
Total deferred credits . . . . . . . . . . . . . . .   108,868    107,349
                                                      ---------  ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Net liabilities of discontinued segment. . . . . . .     1,490      1,941
                                                      ---------  ---------
Total non-utility liabilities. . . . . . . . . . . .     1,490      1,941
                                                      ---------  ---------

TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . .  $330,951   $337,845
                                                      =========  =========

</TABLE>


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

<TABLE>
<CAPTION>

CONSOLIDATED  STATEMENTS  OF  CAPITALIZATION
GREEN  MOUNTAIN  POWER  CORPORATION  At  December  31,
                                                      SHARES
                                              ISSUED AND OUTSTANDING
                                              ----------------------

                                   AUTHORIZED    2003       2002          2003         2002
                                   ----------  ---------  ---------  ---------------  -------
                                                                     (In thousands)
<S>                                <C>         <C>        <C>        <C>              <C>
COMMON STOCK
Common Stock, $3.33 1/3 par value  10,000,000  5,033,215  4,954,857  $        19,536  $19,276
                                                                     ===============  =======
</TABLE>


<TABLE>
<CAPTION>
                                                     OUTSTANDING
                                                     -----------
                                         AUTHORIZED  ISSUED   2003  2002       2003        2002
                                         ----------  -------  ----  ----  ---------------  -----
                                                 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  $             -  $  85
7%, Class C . . . . . . . . . . . . . .      15,000   15,000     -     -                -      -
9.375%, Class D, Series 1,. . . . . . .      40,000   40,000     -     -                -      -
7.32%, Class E, Series 1. . . . . . . .     200,000  120,000     -     -                -      -
                                                                          ---------------  -----
TOTAL PREFERRED STOCK                                                     $             -  $  85
                                                                          ===============  =====
</TABLE>


<TABLE>
<CAPTION>
                                                                 2003          2002
                                                            ---------------  --------
                                                                (In thousands)
<S>                                                         <C>              <C>
LONG-TERM DEBT
FIRST MORTGAGE BONDS
6.41% Series due 2003. . . . . . . . . . . . . . . . . . .                -     8,000
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    42,000
                                                            ---------------  --------
Total Long-term Debt Outstanding . . . . . . . . . . . . .           93,000   101,000
Less Current Maturities (due within one year). . . . . . .                -     8,000
                                                            ---------------  --------
TOTAL LONG-TERM DEBT, LESS CURRENT MATURITIES. . . . . . .  $        93,000  $ 93,000
                                                            ===============  ========
</TABLE>


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

<TABLE>
<CAPTION>

         CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY                         ACCUMULATED               TOTAL
                                       COMMON STOCK     PAID-IN         RETAINED          COMPREHENSIVE    TREASURY   COMMON
                                       ------------
                                    SHARES    AMOUNT   CAPITAL          EARNINGS           OTHER INCOME     STOCK     EQUITY
                                  ----------  -------  --------  -----------------------  --------------  ---------  ---------
                                                                 (Dollars in thousands)
<S>                               <C>         <C>      <C>       <C>                      <C>             <C>        <C>
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. . . . . .     12,691        44        42                       -               -          -         86
Net Income before dividends. . .          -         -         -                  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. . . . . .     52,804       177       342                       -               -          -        519
Net Income before dividends. . .          -         -         -                  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
                                  ----------  -------  --------  -----------------------  --------------  ---------  ---------
Common Stock Issuance:
Compensation Programs. . . . . .     78,358       260       734                                                           994
Common stock repurchase                                                                                         (3)        (3)
Net Income before dividends. . .          -         -         -                  10,407               -          -     10,407
Other Comprehensive Income(Loss)          -         -         -                       -             587          -        587
Common Stock Dividends . . . . .          -         -         -                  (3,789)              -          -     (3,789)
Preferred Stock Dividends: . . .          -         -         -                      (3)              -          -         (3)
                                  ----------  -------  --------  -----------------------  --------------  ---------  ---------
BALANCE, DECEMBER 31, 2003 . . .  5,033,215   $19,536  $ 76,081  $               22,786   $      (1,787)  $(16,701)  $ 99,915
                                  ----------  -------  --------  -----------------------  --------------  ---------  ---------
</TABLE>


The  accompanying  notes  are  an  integral  part  of the 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  89,000  customer  accounts.  The  Company's  subsidiary,  Green
Mountain  Power  Investment  Company  ("GMPIC"), was created in December 2002 to
hold  the  Company's  investment  in  Vermont  Yankee  Nuclear Power Corporation
("Vermont  Yankee"  or  "VY").
     The  Company's  remaining  active  wholly-owned  subsidiary,  which  is not
regulated  by  the  Vermont Public Service Board ("VPSB" or the "Board"), is GMP
Real  Estate  Corporation.  The  results  of GMP Real Estate Corporation and the
Company's  unregulated  rental  water heater program are included in earnings of
affiliates  and  non-utility operations in the Other Income (Deductions) section
of  the Consolidated Statements of Income.  Summarized financial information for
these  wholly-owned  subsidiaries,  and  the  Company's unregulated water heater
program,  which  earned  approximately  $386,000  in  2003  is  as  follows:

<TABLE>
<CAPTION>


                               Years ended December 31,

                2003       2002    2001
            -------------  -----  ------
            In thousands
<S>         <C>            <C>    <C>
Revenue. .  $       1,087  $ 997  $1,012
Expense. .            704    744  $  749
            -------------  -----  ------
Net Income  $         383  $ 253  $  263
            =============  =====  ======
</TABLE>
The  Company accounts for its investments in VY, Vermont Electric Power Company,
Inc.  ("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 of America 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 as summarized in the following
table:
<TABLE>
<CAPTION>

SFAS  71  DEFERRED  CHARGES
                                        At December 31,
                                    2003         2002
                               ---------------  -------
                               (in thousands)
<S>                            <C>              <C>
Regulatory commission costs .  $         2,181  $ 1,774
Restructuring costs . . . . .              943    2,216
Preliminary survey. . . . . .            1,423    1,202
Storm damages . . . . . . . .            1,129    1,905
Tree trimming . . . . . . . .              799      905
Other . . . . . . . . . . . .            3,150    3,411
                               ---------------  -------
Other deferred charges. . . .            9,625   11,413
                               ---------------  -------
Power supply. . . . . . . . .            2,574    2,323
Net power supply deferral . .           19,734   18,405
Pine Street barge canal . . .           12,954   13,019
Power supply derivative asset            3,990    8,796
Demand-side management. . . .            6,713    6,434
                               ---------------  -------
Total Deferred Charges. . . .  $        55,590  $60,390
                               ===============  =======
</TABLE>

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 $9.6 million and $11.4 million at December
31,  2003  and  2002,  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.

     In  addition,  the  Company has regulatory liabilities of $25.1 million and
$24.0  million  at  December  31,  2003  and  2002,  respectively, consisting of
accumulated  removal  costs, deferred revenue and insurance proceeds relating to
VY.


     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 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, 2003,
based  upon management's analysis of 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  capitalizing  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  are  charged to accumulated depreciation.  The
following  table  summarizes  the  Company's  investments  in  utility  plant.
<TABLE>
<CAPTION>

Property  Summary  at  December  31,

                                                2003          2002
                                           --------------  ----------
                                            In thousands
<S>                                        <C>             <C>
 Property Plant and Equipment:
Intangible. . . . . . . . . . . . . . . .  $      14,091   $  12,580
Generation. . . . . . . . . . . . . . . .         68,532      66,913
Transmission. . . . . . . . . . . . . . .         37,093      36,846
Distribution. . . . . . . . . . . . . . .        178,292     170,655
General, including transportation . . . .         26,892      24,549
                                           --------------  ----------
  Total Plant in Service. . . . . . . . .        324,900     311,543
Accumulated Depreciation and Amortization       (110,111)   (102,250)
                                           --------------  ----------
Net Plant in Service. . . . . . . . . . .        214,789     209,293
Capital Lease . . . . . . . . . . . . . .          5,047       5,287
Construction Work in Progress . . . . . .          9,026       8,896
                                           --------------  ----------
Total Net Utility Plant . . . . . . . . .  $     228,862   $ 223,476
                                           ==============  ==========
</TABLE>

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.  Other accumulated removal costs related to
utility  plant,  estimated  at approximately $21.2 million and $19.9 million for
2003  and  2002,  respectively,  are  included  in  Deferred  Credits.

     The  annual  depreciation  provision  was  approximately 3.3 percent during
2003,  3.2  percent  during  2002, and 3.5 percent of total depreciable property
during  2001.

     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 retail
sales of electricity 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.  Wholesale revenues represent sales
of  electricity to other utilities, typically for resale, and to the Independent
System  Operator  of  New  England  ("ISO New England") for amounts by which our
power  supply  resources  exceed  customer  loads.  The  Company also recognizes
deferred  revenues, when required to achieve its allowed rate of return, under a
VPSB  order  issued  in  2001, and extended through 2004 under a subsequent VPSB
order.  The  Company  recognized  $1.1  million  and  $4.4  million  in deferred
revenues  during  2003  and  2002,  respectively.  No  deferred  revenues  were
recognized  in  2001.  See  Note  I(4)  for  additional  information.



     8.  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 2003, 2002 and
2001,  the  Company  granted  additional  options  of  4,000, 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  Company  adopted  the  prospective  method  of  accounting  for stock-based
compensation  under  SFAS  148  beginning  January  1,  2003.  The  information
presented  below  has  been  determined as if the Company accounted for all past
employee  and  director  stock  options  under  the  fair  value  method of that
statement.
<TABLE>
<CAPTION>

Pro-forma  net  income        For  the  years  ended  December  31,
                                         2003     2002     2001
                                        -------  -------  -------
In thousands, except per share amounts
<S>                                     <C>      <C>      <C>
Net income reported. . . . . . . . . .  $10,404  $11,398  $10,678
Pro-forma net income . . . . . . . . .  $10,242  $11,114  $10,376
Net income per share
  As reported-basic. . . . . . . . . .  $  2.09  $  2.04  $  1.90
  Pro-forma basic. . . . . . . . . . .  $  2.06  $  1.99  $  1.84
  As reported-diluted. . . . . . . . .  $  2.02  $  1.98  $  1.85
  Pro-forma diluted. . . . . . . . . .  $  1.99  $  1.93  $  1.79
</TABLE>
9.  Major  Customers.  The  Company had one major retail customer, International
Business  Machines  Corporation  ("IBM"),  that accounted for 24.1 percent, 25.7
percent,  and  26.6 percent of retail MWh sales, and 16.6 percent, 17.3 percent,
and  19.2  percent  of the Company's retail operating revenues in 2003, 2002 and
2001,  respectively.

     10. Fair Value of Financial Instruments.  The carrying value and fair value
of  the Company's first mortgage bonds and derivative contracts is summarized in
the  following  table:
<TABLE>
<CAPTION>

Fair  Value  of  Financial  Instruments
                                  As of December 31,
                               2003                         2002
                               ----                         ----
                     Fair Value   Carrying Value   Fair Value   Carrying Value
In thousands
<S>                  <C>          <C>              <C>          <C>
Long-Term Debt, net  $    91,725  $        92,113  $    96,215  $        99,942
Derivatives . . . .       19,773           19,773       18,405           18,405
</TABLE>

The  book  value  of  accounts  receivable,  accrued  utility  revenues,  other
investments,  cash  surrender value of life insurance, short-term debt, accounts
payable,  customer  deposits  and accrued interest approximate fair value due to
their  short-term,  highly  liquid  nature.

     11.  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.

     12. Purchased Power.  The Company records the annual cost of power obtained
under  long-term  contracts  as  operating  expenses.

     13.  Derivative  Instruments.  SFAS 133, as amended, 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,  was  effective  for  the  Company  beginning  2001.

     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 the application of SFAS 133 to
power  supply  arrangements  that  qualify as derivatives.  We currently have an
arrangement  (the "9701 arrangement") that grants Hydro-Quebec an option to call
power  at  prices  below  current  and  estimated  future  market  rates.  This
arrangement  is  effective  through  2015.  From  time  to  time, we use forward
contracts  to hedge the 9701 call option.  At December 31, 2003, the Company had
a  liability of $23.7 million reflecting the fair value of 9701 arrangement, and
an  asset  of  $4.0 million, reflecting the fair value of a contract with Morgan
Stanley  Capital  Group,  Inc. (the "Morgan Stanley Contract").  A corresponding
net  regulatory  asset of $19.7 million is also recorded.  At December 31, 2002,
the  Company had a liability of $27.2 million reflecting the fair value of 9701,
and  an  asset  of $8.8 million, reflecting the fair value of the Morgan Stanley
Contract.  A  corresponding  net  regulatory  asset  of  $18.4  million was also
recorded.  The  Company  believes  that  the net regulatory asset is probable of
recovery  in  future  rates.  The  net  regulatory  asset  is  based  on current
estimates of future market prices that are likely to change by material amounts.

     The  Morgan  Stanley  Contract is 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.


     14.  Use  of  Estimates.  The  preparation  of  financial  statements  in
conformity with accounting principles generally accepted in the United States of
America  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.

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

     16.  Other Comprehensive Income.  Other comprehensive loss of $2.4 million,
net of a $1.6 million income tax benefit, was recognized during 2002 as a result
of  a minimum pension funding liability.  During 2003, an increase in the market
value  of  pension  plan  assets  allowed  a  reduction  in  the minimum pension
liability  of  approximately  $587,000,  net  of  $400,000  income  tax expense.

     17. New Accounting Standards.  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 Company has
recognized, as a liability, an asset retirement obligation for accumulated costs
of  removal,  which  totaled  approximately  $21.2  million and $19.9 million at
December  31,  2003  and  2002,  respectively, and increased plant and equipment
balances  by  the  same  amount  as  a  result of this accounting pronouncement.

     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, did not 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
Company  adopted  the  prospective  method  of  accounting  for  stock-based
compensation  under SFAS 148 beginning January 1, 2003.  The application of this
accounting  standard  did not materially impact the Company's financial position
or  results  of  operations  during  2003.

     In  May  2003,  the FASB issued Statement of Financial Accounting Standards
No.  150,  "Accounting for Certain Financial Instruments with Characteristics of
both  Liabilities  and  Equity"("SFAS 150").  SFAS 150 establishes standards for
classifying  and  measuring  financial  instruments with characteristics of both
liabilities  and  equity.  The  guidance  is effective for financial instruments
entered  into  or  modified after May 31, 2003.  This statement had no effect on
our  financial  position  or  results  of  operations  during  2003.

     In  December  2003,  the  FASB  issued  Statement  of  Financial Accounting
Standards  No.  132  (revised  2003), "Employers" Disclosures about Pensions and
Other  Postretirement Benefits ("SFAS 132").  In an effort to provide the public
with  better and more complete information, the standard requires that companies
provide  more  details about their plan assets, benefit obligations, cash flows,
benefit  costs  and  other  relevant information.  The guidance is effective for
fiscal  years ending December 15, 2003 and for quarters beginning after December
15,  2003.  We  have  adopted  all  of the disclosures required by the standard.
     In  January  2003,  the  FASB  issued FASB Interpretation No. ("FIN") 46, "
Consolidation  of  Variable  Interest  Entities."  FIN  46 requires a company to
consolidate  a  variable  interest  entity  if  it  is designated as the primary
beneficiary  of  that  entity  even  if  the company does not have a majority of
voting  interests.  The  adoption  of  FIN  46  did  not  require the Company to
consolidate  any  variable  interest  entities.
     In  January  2003,  the  FASB  issued  FIN  45,"Guarantor's  Accounting and
Disclosure  Requirements  for  Guarantees,  Including  Indirect  Guarantees  of
Indebtedness of Others."  FIN 45 requires a company to recognize a liability for
the  obligations it has undertaken in issuing a guarantee.  This liability would
be recorded at the inception of a guarantee and would be measured at fair value.
The  Company  adopted  the measurement provisions of this statement in the first
quarter of 2003 and it did not have an effect on the financial statements during
2003.
     The  Company  provides  health  care, life insurance, prescription drug and
other  benefits,  to retired employees who meet certain age and years of service
requirements.  Under  certain  circumstances,  eligible retirees are required to
make  contributions  for  postretirement  benefits.
     In December 2003, the FASB issued Staff Position ("FSP") 106-1, "Accounting
and  Disclosure  Requirements  related  to  the  Medicare  Prescription  Drug,
Improvement  and  Modernization  Act of 2003" (the "Act").  The Act provides for
drug  benefits  for  certain  retirees under a new Medicare Part D program.  For
employers  like  the Company there are subsidies available which are inherent in
the  Act.  The FASB allowed, and the Company elected, a one-time deferral of the
recognition  of  the impact of the Act in the employer's accounting until formal
guidance is issued.  As a result, the provisions of the Act are not reflected in
the  other  postretirement  benefits  disclosure  (See Note H).  The issuance of
formal  accounting  guidance  may  require  a  change  to  previously  reported
information.

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,
                                           2003    2002        2003         2002
                                          ------  ------  ---------------  -------
                                                          (IN THOUSANDS)
<S>                                       <C>     <C>     <C>              <C>
VELCO-common . . . . . . . . . . . . . .  28.41%  28.41%  $         2,469  $ 2,309
VELCO-preferred. . . . . . . . . . . . .  30.00%  30.00%              246      305
                                                          ---------------  -------
Total VELCO                                                         2,715    2,614

Vermont Yankee- Common . . . . . . . . .  33.60%  18.99%            1,605    9,721
New England Hydro Transmission-Common. .   3.18%   3.18%              592      660
New England Hydro Transmission Electric-
    Common . . . . . . . . . . . . . . .   3.18%   3.18%              984    1,106
                                                          ---------------  -------
Total investment in associated companies                  $         5,896  $14,101
                                                          ===============  =======
</TABLE>

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 $12.0 million,
$12.7  million,  and  $11.5  million  for  the  years  2003,  2002  and  2001,
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.  The
Company  plans to make capital investments of up to $20 million in VELCO through
2007  in  support  of  various  transmission  projects.

<TABLE>
<CAPTION>

Summarized  unaudited  financial  information  for  VELCO  is  as  follows:

At  and  for  the  years  ended  December  31,

                                     2003          2002     2001
                                ---------------  --------  -------
                                 (In thousands)
<S>                             <C>              <C>       <C>
Net income . . . . . . . . . .  $         1,270  $  1,094  $ 1,118
Company's equity in net income  $           418  $    319  $   308
                                ===============  ========  =======
Total assets . . . . . . . . .  $       126,793  $106,613  $89,322
Less:
Liabilities and long-term debt          117,393    97,417   81,335
                                ---------------  --------  -------
Net assets . . . . . . . . . .  $         9,400  $  9,196  $ 7,987
                                ===============  ========  =======

Company's equity in net assets  $         2,715  $  2,614  $ 2,352
                                ===============  ========  =======
</TABLE>

VERMONT  YANKEE.  On  July  31,  2002,  Vermont Yankee Nuclear Power Corporation
("VY" or "Vermont Yankee") announced that the sale of its nuclear power plant to
Entergy  Nuclear  Vermont  Yankee  ("ENVY")  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 ENVY, 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 received a credit from VY
and  has  requested  permission  from the VPSB to apply the credit to reduce the
$2.0  million  regulatory  asset.

     The  Company's  ownership share of VY has increased from approximately 19.0
percent in 2002 to approximately 33.6 percent currently, due to VY's purchase of
certain  minority  shareholders' interests.  The Company's entitlement to energy
produced  by the ENVY nuclear plant remains at approximately 20 percent of plant
production.
     The  2003  decrease  in  equity  in  net  assets  of  VY  resulted  from  a
distribution  of  proceeds, in the form of dividends to VY owners, from the sale
of  the  VY  nuclear  power  plant.

Summarized  unaudited  financial  information  for Vermont Yankee is as follows:
<TABLE>
<CAPTION>

At  and  for  the  years  ended  December  31,

                                           2003         2002          2001
                                         --------  ---------------  --------
                                                   (In thousands)
<S>                                      <C>       <C>              <C>
Earnings:
  Operating revenues. . . . . . . . . .  $187,123  $       175,722  $178,840
  Net income applicable to common stock     2,536            9,454     6,119
  Company's equity in net income. . . .  $    498  $         1,745  $  1,131
                                         ========  ===============  ========
Total assets. . . . . . . . . . . . . .  $150,720  $       201,426  $723,815
Less:
  Liabilities and long-term debt. . . .   145,946          150,413   669,640
                                         --------  ---------------  --------
Net Assets. . . . . . . . . . . . . . .  $  4,774  $        51,203  $ 54,175
                                         ========  ===============  ========
Company's equity in net assets. . . . .  $  1,605  $         9,721  $  9,725
                                         ========  ===============  ========
</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,
2003.  The  Company also funds an Employee Savings and Investment Plan ("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,
or  its subsidiaries.  Outstanding options become exercisable at between one and
four  years  after the grant date and remain exercisable until 10 years from the
grant  date.

     Prior  to 2003, as permitted by Statement of Financial Accounting Standards
No.  123, "Accounting for Stock-Based Compensation ("SFAS 123"), the Company had
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 issued through 2002.  Under APB 25,
because  the  exercise  price equals the market price of the underlying stock on
the  date  of grant, no compensation expense was recorded.  Effective January 1,
2003,  the  Company  elected to expense the fair value of options granted beyond
that  date.  The amount of expense recorded during 2003 was immaterial.  Options
have  been  issued  only  to  employees  and  directors.

     The  fair  values of the options granted in 2003, 2002, and 2001 are $1.33,
$2.27, and $4.16 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,  2003:
<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>
2000.  $ 7.90  192,200      6.6         6.05%      5        30.58       4.5%
2001.  $16.72   35,150      7.6         5.25%      6        32.69       4.0%
2002.  $17.84   69,500      8.6         4.50%      6.5      16.89       4.5%
2003.  $20.55    4,000      9.3         2.48%      6        13.68       4.5%
Total  $11.39  300,850
       ======  =======
</TABLE>
Options  granted  are  not  exercisable  until one year after the date of grant.

     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,

                                                   2003         2002     2001
                                              ---------------  -------  -------
                                              (in thousands)
<S>                                           <C>              <C>      <C>
Net income (loss) before preferred dividends  $        10,407  $11,494  $11,611
Preferred stock dividend requirement . . . .                3       96      933
                                              ---------------  -------  -------
Net income (loss) applicable to common
   stock . . . . . . . . . . . . . . . . . .  $        10,404  $11,398  $10,678
                                              ===============  =======  =======

Average number of common shares-basic. . . .            4,980    5,592    5,630
Dilutive effect of stock options . . . . . .              160      164      159
                                              ---------------  -------  -------
Average number of common shares-diluted. . .            5,140    5,756    5,789
                                              ===============  =======  =======
</TABLE>
<TABLE>
<CAPTION>
                                        Weighted     Range of
                               Total     Average     Exercise     Options
                                  Options  Price      Prices      Exercisable
                                  -------  ------  -------------  -----------
<S>                               <C>      <C>     <C>            <C>
Outstanding at December 31, 2000  331,900  $ 7.90  $  7.90-$7.90            0
Granted. . . . . . . . . . . . .   55,450   16.67  $14.50-$16.78
Granted. . . . . . . . . . . . .    1,000   12.28  $12.28-$12.28
Exercised. . . . . . . . . . . .   17,400    7.90  $  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-$18.67
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
                                  -------  ------  -------------  -----------
Granted. . . . . . . . . . . . .    4,000   20.55  $20.22-$22.62
Exercised. . . . . . . . . . . .   64,550   10.63  $ 7.90-$18.67
Forfeited. . . . . . . . . . . .    4,400   17.36  $16.78-$18.12
Outstanding at December 31, 2003  300,850  $11.39  $ 7.90-$22.62      193,700
                                  =======  ======  =============  ===========
</TABLE>

As  part of our long-term stock incentive program, 13,300 shares of unrestricted
common  stock  were  granted  to  employees  other than the Company's executives
during  December  2003,  resulting  in  compensation  expense  of  approximately
$300,000.  Directors  were  granted  8,800  deferred  stock  units  during 2003,
resulting  in  compensation expense of approximately $196,000.  The Company also
granted  35,200  deferred  stock units to senior management on February 9, 2004.
Each  deferred  stock  unit  is convertible into one share of common stock.  The
total  market value of the shares will be charged to compensation expense over a
two-year  vesting  period.
     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 $19.9 million of retained earnings
were  free  of  restrictions  at  December  31,  2003.


D.  PREFERRED  STOCK
     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  repurchased the remaining $0.2 million of the 9.375 percent
Class  D  preferred  stock  outstanding.  All  remaining  preferred  stock  was
repurchased  during  2003.

E.  SHORT-TERM  DEBT
     The  Company  has  a  $20.0 million 364-day revolving credit agreement with
Fleet  Financial  Services  ("Fleet")  joined  by  Sovereign Bank ("Sovereign"),
expiring  June  2004  (the  "Fleet-Sovereign  Agreement").  The  Fleet-Sovereign
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 $500,000
outstanding  at  a  weighted average rate of 4 percent under the Fleet-Sovereign
Agreement  at  December  31,  2003.  There  was  no  non-utility short-term debt
outstanding  at  December  31,  2003  or  2002.

            The  Fleet-Sovereign  Agreement requires the Company to certify on a
quarterly  basis  that  it  has  not  suffered a "material adverse change".  The
agreement  also  requires  the  Company  to  comply with certain covenants.  The
Company  was  in  compliance  with  all  covenants  at  December  31,  2003.

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
for  both  December  31,  2003  and  2002.  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, 2003, are:

<TABLE>
<CAPTION>
                        Sinking
                        Fund and
                      Maturities
                      -----------
<S>                   <C>

2004 . . . . . . . .  $         -
2005 . . . . . . . .            -
2006 . . . . . . . .       14,000
2007 . . . . . . . .            -
2008 . . . . . . . .            -
Thereafter . . . . .       79,000
Total Long-term debt  $    93,000
                      ===========
</TABLE>
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,  2003  and  2002,  the  net  regulatory  assets  were $924,000 and
$1,042,000,  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,  2003  and  December  31,  2002,  were  as  follows:

<TABLE>
<CAPTION>

                                                                                           AT  DECEMBER  31,
                                                                                           2003         2002
                                                                                      ---------------  -------
                                                                                      (In thousands)
<S>                                   <C>                              <C>            <C>              <C>
DEFERRED TAX ASSETS
Contributions in aid of construction                                                  $        11,841  $11,130
Deferred compensation and
     postretirement benefits                                                                    5,205    4,570
Self insurance and other reserves                                                                 365    1,369
Other                                                                                           1,277    3,032
                                                                                      ---------------  -------
                                                                                      $        18,689  $20,101
                                                                                      ---------------  -------

DEFERRED TAX LIABILITIES
Property related                                                                      $        43,924  $41,967
Demand side management                                                                          1,746    1,870
Deferred purchased power costs                                                                    809      943
Pine Street reserve                                                                             2,425    1,792
Other                                                                                           3,794        -
                                                                                      ---------------  -------
                                                                                      $        52,698  $46,572
                                                                                      ---------------  -------
                                      Net accumulated deferred income  tax liability  $        34,009  $26,471
                                                                                      ===============  =======
</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,
                                                                               2003          2002      2001
                                                                          ---------------  --------  --------
                                                                                    (In thousands)
<S>                                    <C>                                <C>              <C>       <C>
Net change in deferred income tax                                         $        7,539   $ 2,712   $(1,885)
                                       liability
Change in income tax related
                                       regulatory assets and liabilities          (6,175)    2,759    (1,149)
Change in tax effect of accumulated
                                       other comprehensive income                    398    (1,612)        -
                                                                          ---------------  --------  --------
Deferred income tax expense (benefit)                                     $        1,761   $ 3,859   $(3,034)
                                                                          ===============  ========  ========
</TABLE>
The  components  of  the  provision  for  income  taxes  are  as  follows:
<TABLE>
<CAPTION>

                                      YEARS  ENDED  DECEMBER  31,
                                    2003         2002      2001
                               ---------------  -------  --------
                                               (In thousands)
<S>                            <C>              <C>      <C>
Current federal income taxes.  $        2,434   $1,873   $ 7,846
Current state income taxes. .           1,207      593     2,418
                               ---------------  -------  --------
Total current income taxes. .           3,641    2,466    10,264
Deferred federal income taxes           1,307    2,920    (2,296)
Deferred state income taxes .             454      939      (738)
                               ---------------  -------  --------
Total deferred income taxes .           1,761    3,859    (3,034)
Investment tax credits-net. .            (282)    (282)     (282)
                               ---------------  -------  --------
Income tax expense. . . . . .  $        5,120   $6,043   $ 6,948
                               ===============  =======  ========
</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,

                                                   2003          2002      2001
                                              ---------------  --------  --------
                                                           (In thousands)
<S>                                           <C>              <C>       <C>
Income before income taxes and
  preferred dividends. . . . . . . . . . . .  $       15,527   $17,537   $18,559
Federal statutory rate . . . . . . . . . . .            34.0%     34.0%     35.0%
Computed "expected" federal income
  taxes. . . . . . . . . . . . . . . . . . .           5,279     5,963     6,496
Increase (decrease) in taxes resulting from:
Tax versus book depreciation . . . . . . . .              41        41        45
Dividends received and paid credit . . . . .            (465)     (575)     (440)
AFUDC-equity funds . . . . . . . . . . . . .            (129)      (80)      (72)
Amortization of ITC. . . . . . . . . . . . .            (282)     (282)     (282)
State tax. . . . . . . . . . . . . . . . . .             797     1,011     1,705
Excess deferred taxes. . . . . . . . . . . .             (60)      (60)      (60)
Tax attributable to subsidiaries . . . . . .             (25)      (31)       63
Other. . . . . . . . . . . . . . . . . . . .             (36)       56      (507)
                                              ---------------  --------  --------
Total federal and state income tax . . . . .  $        5,120   $ 6,043   $ 6,948
                                              ===============  ========  ========
Effective combined federal and state
  income tax rate. . . . . . . . . . . . . .            33.0%     34.5%     37.4%
</TABLE>

NON-UTILITY.  The  Company's  non-utility subsidiaries, excluding Northern Water
Resources,  Inc. ("NWR"), had accumulated deferred income taxes of approximately
$2,000  on  their  balance  sheets  at  December  31,  2003,  attributable  to
depreciation  timing  differences.

     The  components  of  the provision for the income tax expense (benefit) for
the  non-utility  operations  were  not  significant.

     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, 2003, 2002 and 2001.  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  equity
securities,  fixed  income  securities,  hedge  funds and cash equivalent funds.

     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  to  meet  or exceed the minimum funding requirements of
ERISA  or  Pension  Benefit  Guaranty  Corporation, 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 during 2002 and made voluntary
contributions totaling $3.5 million during 2003.  The Company currently plans to
contribute  between  $2.0 and $3.0 million of additional funds during 2004.  The
Company's  pension  costs and cash funding requirements could increase in future
years  in  the  absence  of  further  recovery  in  the  equity  markets.

     During 2002, the Company's retirement plan asset return experience required
the Company to recognize a minimum pension liability of $4.0 million, and a $1.6
million  tax benefit, as prescribed by generally accepted accounting principles.
Common  equity  was  reduced  in  the amount of $2.4 million through a charge to
other  comprehensive  income.
     During 2003, market value appreciation of pension plan investments resulted
in  the reduction of the previously recognized minimum pension liability to $3.0
million.  Common  equity  increased  approximately  $587,000,  net of applicable
income  tax,  through  a  credit  to  other  comprehensive  income.

     Accrued  postretirement  health  care  expenses are recovered in rates.  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,  2003  and  2002.
<TABLE>
<CAPTION>

                                                         At and for the years ended December 31,
                                                       Pension Benefits   Other Postretirement Benefits
                                                   ----------------   -----------------------------
                                                         2003          2002      2003       2002
                                                    ---------------  --------  ---------  ---------
                                                                      (In thousands)
Change in projected benefit obligation:
<S>                                                 <C>              <C>       <C>        <C>
Projected benefit obligation as of prior year end.  $       29,937   $25,895   $ 20,707   $ 16,491
Service cost . . . . . . . . . . . . . . . . . . .             755       668        496        296
Interest cost. . . . . . . . . . . . . . . . . . .           1,900     1,849      1,316      1,119
Participant contributions. . . . . . . . . . . . .               -         -        136        147
Plan change. . . . . . . . . . . . . . . . . . . .               -         -     (1,812)         -
Change in actuarial assumptions. . . . . . . . . .             292         -      2,095          -
Actuarial (gain) loss. . . . . . . . . . . . . . .           2,789     3,230        (25)     3,619
Benefits paid. . . . . . . . . . . . . . . . . . .          (1,629)   (1,650)    (1,007)      (965)
Administrative expense . . . . . . . . . . . . . .             (64)      (55)         -          -
                                                    ---------------  --------  ---------  ---------
Projected benefit obligation as of year end. . . .  $       33,980   $29,937   $ 21,906   $ 20,707
                                                    ===============  ========  =========  =========

Change in plan assets:
Fair value of plan assets as of prior year end . .  $       21,104   $24,341   $  8,760   $ 10,016
Administrative expenses paid . . . . . . . . . . .             (64)      (55)         -          -
Participant contributions. . . . . . . . . . . . .               -         -        136        147
Employer contributions . . . . . . . . . . . . . .           3,500     1,000        782        819
Actual return on plan assets . . . . . . . . . . .           4,956    (2,532)     1,558     (1,257)
Benefits paid. . . . . . . . . . . . . . . . . . .          (1,629)   (1,650)    (1,007)      (965)
                                                    ---------------  --------  ---------  ---------
Fair value of plan assets as of year end . . . . .  $       27,867   $21,104   $ 10,229   $  8,760
                                                    ===============  ========  =========  =========

Funded status as of year end . . . . . . . . . . .  $       (6,113)  $(8,833)  $(11,677)  $(11,948)
Unrecognized transition obligation (asset) . . . .               -       (77)     2,952      3,280
Unrecognized prior service cost. . . . . . . . . .             984       839     (2,216)      (462)
Unrecognized net actuarial loss. . . . . . . . . .           6,372     6,982      9,250      8,379
                                                    ---------------  --------  ---------  ---------
Prepaid (accrued) benefits at year end . . . . . .  $        1,243   $(1,089)  $ (1,691)  $   (751)
                                                    ===============  ========  =========  =========
</TABLE>

     The  Company  also  has  a supplemental pension plan for certain employees.
Pension  costs  for  the  years  ended  December  31,  2003, 2002, and 2001 were
$392,000,  $408,000,  and $340,000, 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
                                                 2003          2002      2001     2003     2002     2001
                                            ---------------  --------  --------  -------  -------  -------
                                                                          (In thousands)
<S>                                         <C>              <C>       <C>       <C>      <C>      <C>
Service cost . . . . . . . . . . . . . . .  $          755   $   668   $   537   $  496   $  296   $  241
Interest cost. . . . . . . . . . . . . . .           1,900     1,849     1,737    1,316    1,119    1,043
Expected return on plan assets . . . . . .          (1,851)   (2,112)   (2,379)    (740)    (851)    (892)
Amortization of transition asset . . . . .             (77)     (164)     (164)                -        -
Amortization of prior service cost . . . .             147       147       147      (58)     (58)     (58)
Amortization of the transition obligation.               -         -         -      328      328      328
Recognized net actuarial gain. . . . . . .             294         -      (237)     381       60        -
                                            ---------------  --------  --------  -------  -------  -------
    Net periodic benefit cost (income) . .  $        1,168   $   388   $  (359)  $1,723   $  894   $  662
                                            ===============  ========  ========  =======  =======  =======
</TABLE>

Assumptions  used  to determine pension and postretirement benefit costs and the
related  benefit  obligations  were:
<TABLE>
<CAPTION>

  Assumptions used in benefit obligation measurement
                                          For the years ended December 31,
                                          Pension benefits Other Postretirement Benefits
                                          ---------------- -----------------------------
                                              2003   2002   2003    2002
                                              -----  -----  -----  ------
<S>                                           <C>    <C>    <C>    <C>
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . .  6.00%  6.50%  6.00%   6.50%
Expected return on plan assets . . . . . . .  8.50%  9.00%  8.50%   8.50%
Rate of compensation increase. . . . . . . .  4.25%  4.25%  4.25%   4.25%
Medical inflation. . . . . . . . . . . . . .     -      -   9.25%  10.00%
</TABLE>

<TABLE>
<CAPTION>

  Assumptions used in periodic cost measurement
                                          For the years ended December 31,
                                         Pension benefits  Other Postretirement Benefits
                                        ----------------   -----------------------------
                                              2003   2002    2003   2002
                                              -----  -----  ------  -----
<S>                                           <C>    <C>    <C>     <C>
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . .  6.50%  7.00%   6.50%  7.00%
Expected return on plan assets . . . . . . .  8.50%  9.00%   8.50%  8.50%
Rate of compensation increase. . . . . . . .  4.25%  4.25%   4.25%  4.25%
Medical inflation. . . . . . . . . . . . . .     -      -   10.00%  7.50%
</TABLE>

For  measurement  purposes,  a  9.25  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, 2003 by $4.8 million and the total of the service
and  interest  cost  components of net periodic postretirement cost for the year
ended  December  31,  2003  by  $434,000.  Decreasing  the  trend  rate  by  one
percentage  point  for  all  future  years  would  decrease  the  accumulated
postretirement  benefit obligation at December 31, 2003 by $3.8 million, and the
total of the service and interest cost components of net periodic postretirement
cost  for  2003  by  $339,000.
     The  Company's  defined  benefit  plan  investment  policy seeks to achieve
sufficient  growth to enable the pension plan to meet its future obligations and
to  maintain  certain  funded  ratios  and  minimize  near-term cost volatility.
Current  guidelines specify generally that 65 percent of plan assets be invested
in  equity  securities, 30 percent of plan assets be invested in debt securities
and  the  remainder  be  invested  in  alternative  investments.
     The Company expects an annual long-term return for the defined benefit plan
asset  portfolios  of  8.25 percent, based on a representative allocation within
the  target  asset allocation described above.  In formulating this assumed rate
of  return,  the  Company  considered  historical  returns by asset category and
expectations  for  future  returns by asset category based, in part, on expected
capital  market  performance  of  the  next  ten  years.
<TABLE>
<CAPTION>
                                    Pension Assets
Weighted Average Asset Allocation      For the years ended December 31,
                         2004 TARGET    2003     2002
                         ------------  -------  -------
Asset Category
<S>                      <C>           <C>      <C>
Equity Securities . . .        65.00%   63.10%   59.61%
Debt Securities . . . .        30.00%   24.92%   31.65%
Real Estate . . . . . .         0.00%    0.00%    0.00%
Other . . . . . . . . .         0.00%    6.60%    8.74%
Alternative investments         5.00%    5.38%    0.00%
                         ------------  -------  -------
total . . . . . . . . .       100.00%  100.00%  100.00%
                         ============  =======  =======
</TABLE>


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  deregulation  in  Vermont.  Legislation  has been
introduced  in  the  Vermont legislature that would permit (but not require) the
Company  to  negotiate  with  individual  customers  to permit such customers to
procure  their own electric power supply requirements, subject to VPSB approval.
We  cannot  predict  whether  this legislation will be enacted.  If enacted, the
Company  would  not  negotiate  any  such  arrangement  unless  in the Company's
estimation,  the  arrangement  assured  the  Company  of  full  recovery  of any
resulting  stranded  costs  and that the Company's financial condition would not
otherwise  be  adversely  affected.  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.  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.

PINE  STREET  BARGE  CANAL  SUPERFUND  SITE - In 1999 the Company entered into a
United States District Court Consent Decree constituting a final settlement with
the  United States Environmental Protection Agency ("EPA"), the State of Vermont
and  numerous  other  parties  of claims relating to a federal superfund site in
Burlington,  Vermont,  known as the Pine Street Barge Canal.  The consent decree
resolves  claims  by the EPA for past site costs, natural resource damage claims
and  claims  for  past  and  future  remediation costs.  The consent decree also
provides  for the design and implementation of response actions at the site.  In
2003,  the  Company  expended  $2.6  million  to cover its obligations under the
consent  decree  and  we  have estimated total future costs of the Company's net
future  obligations  through  2033  under the consent decree to be $8.5 million.
The  estimated liability is not discounted, and it is possible that our estimate
of  future  costs  could  change  by a material amount.  We have also recorded a
regulatory  asset of $13.0 million to reflect future recovery of these costs, as
well  as  past  unrecovered costs.  Pursuant to the Company's 2003 Rate Plan, as
approved  by the VPSB, the Company will begin to amortize past unrecovered costs
in  2005.  The Company will amortize the full amount of these costs, as they are
incurred,  over  20 years without a return.  The amortization will be allowed in
future  rates,  without  disallowance  or  adjustment,  until  fully  amortized.


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,  2003,  as  follows:
<TABLE>
<CAPTION>
                                                      Share of     Share of
                          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  $       4,926
McNeil . . . . . . . . .       11.0        5.9            8,989          5,379
Stony Brook (No. 1). . .        8.8         31           10,377          8,965
Wyman (No. 4). . . . . .        1.1        6.8            1,980          1,380
Metallic Neutral Return.       59.4          -            1,563            806
</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  - On December 22, 2003, the VPSB approved a three-year rate
plan  (the "2003 Rate Plan") jointly proposed earlier in the year by the Company
and  the Department.  The 2003 Rate Plan, as approved, covers the period through
2006  and  includes  the  following  principal  elements.
     The Company's rates will remain unchanged through 2004.  The 2003 Rate Plan
allows the Company to raise rates 1.9 percent, effective January 1, 2005, and an
additional  0.9  percent,  effective  January  1,  2006,  if  the  increases are
supported  by cost of service schedules submitted 60 days prior to the effective
dates.  If  the Company's cost of service filings in 2005 or 2006 establish that
a  lesser  rate  increase  in  required  for  the  Company  to  meet its revenue
requirements,  the  Company  will  implement  the  lesser  rate  increase.
     The  Company  may  seek  additional  rate  increases  in  extraordinary
circumstances,  such  as  severe storm repair costs, natural disasters, extended
unanticipated  unit  outages,  or  significant  losses  of  customer  load.
     The  Company's  allowed  return  on equity is reduced from 11.25 percent to
10.5  percent, for the period January 1, 2003 through December 31, 2006.  During
the same period, the Company's earnings on core utility operations are capped at
     10.5  percent.  If  excess earnings result in 2004, they will be applied to
reduce  regulatory  assets.  Excess earnings in 2005 or 2006 will be refunded to
customers  as a credit on customer bills or applied to reduce regulatory assets,
as  the  Department  directs.
     The  Company  will carry forward into 2004 $3.0 million in deferred revenue
remaining  at  December  31,  2003  from the Company's 2001 rate case settlement
summarized  below.  The  Company  will  amortize  (recover)  certain  regulatory
assets,  including  Pine  Street  Barge  Canal environmental site costs and past
demand-side  management  program  costs,  beginning  in January 2005, with those
amortizations  to  be  allowed  in  future  rates.  Pine  Street  costs  will be
recovered  over  a  twenty-year  period  without  a  return.
     The  Company  will  file  with the VPSB in early 2004 a new fully allocated
cost  of  service  study  and  rate re-design, which will allocate the Company's
revenue  requirement  among  all customer classes on the basis of current costs.
The  new  rate  design  will  be  subject  to  VPSB  approval.
     The Company and the Department have agreed to work cooperatively to develop
and  propose an alternative regulation plan as authorized by legislation enacted
in  Vermont  in  2003.  The target for filing such a plan is April 2004.  If the
Company and Department agree on such a plan, and it is approved by the VPSB, the
alternative  regulation  plan  would  supersede  the  2003  Rate  Plan.

     In  January  2001,  the  VPSB  approved  a rate case settlement between the
Company and the Department (the "2001 Settlement Order").  The final settlement,
as  approved,  included  the  following:


*     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 $30,000 in excess of its allowed rate of
return  during  2001  before  writing  off regulatory assets in the same amount.
     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.

5.  DEFERRED  CHARGES  NOT  INCLUDED  IN  RATE  BASE.
     The  Company has incurred and deferred approximately $11.1 million in costs
for  Pine Street, tree trimming, storm damage, and regulatory commission work of
which  approximately $408,000 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 amounts deferred.  Management expects to recover these costs
over  periods  ranging  from  five  to  twenty  years beginning January 1, 2005,
pursuant  to  the  2003  Rate  Plan.  The  2001  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 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.

     In November 2003, Rockingham notified the Company that the town intended to
initiate  proceedings  before  the  town  selectboard  to  condemn the Company's
distribution  and  associated  property  located  within  the town.  The Company
sought  and  obtained  in  December 2003 a preliminary injunction from the State
Superior Court prohibiting the town from proceeding with condemnation before the
selectboard.  The  Company  successfully  argued  that  Vermont  law  required
Rockingham  to  pursue any such municipalization effort by petition to the VPSB,
which  is  required  to  determine  both the fair value of any assets subject to
municipalization and the amount of damages to the utility caused by severance of
the property subject to municipalization.  The preliminary injunction remains in
effect  and  Rockingham  has  not  filed  any  petition with the VPSB seeking to
municipalize assets.  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.
7.  OTHER  LEGAL  MATTERS.
     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
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
in  connection  with  this  proceeding.

     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,  2003,  the  present  value  of  the  Company's
obligation  is  approximately  $4.6  million.

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

Year ending
                       December 31
                     ---------------
                     (In thousands)
<S>                  <C>
2004. . . . . . . .  $           387
2005. . . . . . . .              387
2006. . . . . . . .              387
2007. . . . . . . .              387
2008. . . . . . . .              387
Total for 2009-2015            2,712
    Total . . . . .  $         4,647
                     ===============
</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
National  Grid  USA.  Certain of the Phase II participating utilities, including
the  Company,  own  equity  interests  in  such  companies.  The  Company  holds
approximately  3.2 percent of the equity of the corporations owning the Phase II
facilities and accounts for its ownership under the equity method of accounting.

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  2003  follows:
<TABLE>
<CAPTION>

                                                                STONY
                                                                BROOK
                                                       -----------------------
                                                       (Dollars in thousands)
<S>                                <C>                 <C>
Plant capacity                                                       352.0 MW
Company's share of output                                                4.40%
Contract period expires:                                                 2006
Company's annual share of:
                                   Interest            $                  128
                                   Other debt service                     444
                                   Other capacity                         535
Total annual capacity                                  $                1,107
                                                       =======================

Company's share of long-term debt                      $                1,817
</TABLE>

2.  VERMONT  YANKEE
     The Company has a long-term power purchase contract with VY, which sold its
nuclear power plant to ENVY on July 31, 2002.  The Company is no longer required
to  pay  its  proportionate share of fixed costs associated with the ENVY 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 ENVY also calls for ENVY, 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.

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

                                                        Vermont Yankee
                                                              Contract
                                                             ----------
<S>                                    <C>        <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                                   2003  $  37,288
                                       estimated  2004-2015  $  32,377
Average cost per KWh                                   2003  $   0.042
                                       estimated  2004-2015  $   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 ENVY to finalize the VY sale.

     The  Company  received  its  share  of  the  VY  power plant sale proceeds,
approximately $8.2 million, during October 2003, and used the proceeds to retire
debt.

3.  HYDRO-QUEBEC
       Under  various  contracts,  summarized  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  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
increased  power  supply  expense  during  2003  by  approximately $1.2 million.

     During  2003,  Hydro-Quebec  exercised its second option to reduce the load
factor for 2004, and we expect Hydro-Quebec to exercise its third option in 2004
for deliveries occurring principally during 2005.  Hydro-Quebec also 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.
Under  the  1987 Contract, Vermont joint owners, including the Company, have two
remaining  options  to  adjust  deliveries by a five percent load factor.  These
cannot be used to offset Hydro-Quebec's reductions through 2005, but may be used
after  2005  to  manage  power  supply  costs.

     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, 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>            <C>
Capacity acquired                                                               68 MW                46 MW
Contract period                                                             1995-2015            1995-2015
Minimum energy purchase                                                        65%-75%              65%-75%
(annual load factor)
Annual energy charge                      2003  $                              10,565         $      7,219
                          estimated  2004-2015                                 13,756    (1)         9,400    (1)
Annual capacity charge                    2003  $                              16,857         $     11,519
                          estimated  2004-2015  $                              17,122    (1)  $     11,699    (1)
Average cost per KWh                      2003  $                               0.071         $      0.071
                          estimated  2004-2015  $                               0.064    (2)  $      0.064    (2)
</TABLE>
(1)Estimated  average  includes  load  factor  reduction  to  65 percent in 2004
(2)Estimated  average  in  nominal  dollars  levelized over the period indicated
   includes  amortization  of  payments  to  Hydro-Quebec

     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 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, 2003, Hydro-Quebec had
purchased  or  called  to  purchase  513,000  MWh  under  option  B.

     In  2003,  Hydro-Quebec  exercised  option  A  and option B, and called for
delivery  to third parties at a net expense to the Company of approximately $4.5
million,  including  capacity  charges.

     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.

     The  Company  believes  that  it  is  probable  that Hydro-Quebec will call
options  A and B for 2004, and has purchased replacement power at an incremental
cost of $3.2 million.  The Company has also covered 54 percent of expected calls
during  2005  at  an  incremental  cost  of  $1.1  million.

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.

     Beginning  January 1, 2004, the Company will reduce the power that it sells
to  MS.  The  reduction  in  sales  is  expected to reduce wholesale revenues by
approximately  $65 million, and power supply expense by a similar
amount.  The  Company  does  not  expect  the  change  to  adversely  affect its
opportunity  to  earn  its  allowed  rate  of  return  during  2004.

     The  Company  and MS have agreed to the protocols that are used to schedule
power sales and purchases and to secure necessary transmission.  The MS contract
is  a  derivative  that  includes  a risk premium above expected future costs of
electricity.

L.  DISCONTINUED  OPERATIONS.
     The  Company has 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 net reserve for loss
from  discontinued  operations  reflects  management's  current  estimate.  The
residual  operations earned $0.01 per share in 2003 and $0.02 per share in 2002,
primarily  as  a  result  of  adjustments  to a reserve for warranty claims.  At
December 31, 2003, 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  against  NWR.  The  ultimate loss remains subject to the
disposition  of  remaining  assets and liabilities, and could exceed the amounts
recorded.  The  following illustrates the results and financial statement impact
of  discontinued  operations  during  and  at  the  periods  shown:
<TABLE>
<CAPTION>


                                                  2003                 2002    2001
                                    --------------------------------  ------  -------
                                    (In thousands except per share)
<S>                                 <C>                               <C>     <C>
Revenues . . . . . . . . . . . . .  $                              -  $   88  $  156
                                    --------------------------------  ------  -------
Gain (loss) on disposal. . . . . .                                79      99    (182)
Net income (loss). . . . . . . . .  $                             79  $   99  $ (182)
                                    ================================  ======  =======
Net income (loss) per share-basic.  $                           0.01  $ 0.02  $(0.03)
Proceeds from asset sales. . . . .  $                              -  $    -  $    -
Total assets . . . . . . . . . . .  $                          1,488  $1,622  $2,700
State income taxes . . . . . . . .  $                             12  $   19  $ (175)
Federal income taxes . . . . . . .                                39      52    (550)
Investment tax credits . . . . . .                                 -       -       -
                                    --------------------------------  ------  -------
Income tax expense (benefit) . . .  $                             51  $   71  $ (725)
                                    ================================  ======  =======
</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>

                                           2003  Quarter  ended
                                                 MARCH      JUNE    SEPTEMBER   DECEMBER    TOTAL
                                                --------  --------  ----------  ---------  --------
(Amounts in thousands except per share data)
<S>                                             <C>       <C>       <C>         <C>        <C>
Operating revenues . . . . . . . . . . . . . .  $72,945   $64,455   $   71,975  $  71,095  $280,470
Operating income . . . . . . . . . . . . . . .    5,231     2,425        4,302      3,348    15,306
Net income-continuing operations . . . . . . .  $ 4,084   $ 1,120   $    3,034  $   2,087  $ 10,325
Net income-discontinued operations . . . . . .      (13)       (8)           6         94        79
Net Income applicable to common stock. . . . .  $ 4,071   $ 1,112   $    3,040  $   2,181  $ 10,404
                                                ========  ========  ==========  =========  ========
Basic earnings per share from:
Continuing operations. . . . . . . . . . . . .  $  0.82   $  0.22   $     0.61       0.43  $   2.08
Discontinued operations. . . . . . . . . . . .        -         -            -       0.01      0.01
Basic earnings per share . . . . . . . . . . .  $  0.82   $  0.22   $     0.61  $    0.44  $   2.09
                                                ========  ========  ==========  =========  ========
Weighted average common shares outstanding . .    4,959     4,969        4,982      5,009     4,980
Diluted earnings per share from:
Continuing operations. . . . . . . . . . . . .  $  0.80   $  0.22   $     0.59       0.40  $   2.01
Discontinued operations. . . . . . . . . . . .        -         -            -       0.01      0.01
Diluted earnings per share . . . . . . . . . .  $  0.80   $  0.22   $     0.59  $    0.41  $   2.02
                                                ========  ========  ==========  =========  ========
Weighted average common and common equivalent.    5,118     5,129        5,141      5,165     5,140
shares outstanding
</TABLE>


<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     5,756
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>

Independent  Auditors'  Report
 To  the  Board  of  Directors  of
 Green  Mountain  Power  Corporation:

We  have  audited  the accompanying consolidated balance sheets and consolidated
statements  of  capitalization  of  Green  Mountain  Power  Corporation  and
subsidiaries  (the  Company)  as of December 31, 2003, and 2002, and the related
consolidated statements of income, comprehensive income, changes in stockholders
equity and cash flows for each of the two years in the period ended December 31,
2003.  The  financial  statements  of  Green  Mountain  Power  Corporation  and
subsidiaries as of December 31, 2001 and for the year 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 audits in accordance with auditing standards generally accepted
in  the  United  States  of  America.  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 financial statements referred to above present fairly, in
all  material  respects,  the  financial  position  of  Green  Mountain  Power
Corporation  and  subsidiaries as of December 31, 2003 and 2002, and the results
of their operations and their cash flows for each of the two years then ended in
conformity  with  accounting principles generally accepted in the United States.




Deloitte  &  Touche,  LLP
/s/Deloitte  &  Touche,  LLP
Boston,  Massachusetts
February  25,  2004










<PAGE>


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,  2003,  2002,  and  2001
                                                  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)
----------------------------------------------
2003 . . . . . . . . . . . . . . . . . . . . .  $10,489,506         (521,493)               -   1,522,330  $ 8,445,683
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


Allowance for Doubtful Accounts
----------------------------------------------
2003 . . . . . . . . . . . . . . . . . . . . .      547,316          143,214                -           -      690,530
2002 . . . . . . . . . . . . . . . . . . . . .      575,890                -           37,270      65,844      547,316
2001 . . . . . . . . . . . . . . . . . . . . .      425,890          150,000                                   575,890

(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, 2003 and 2002 and for each of the two years in the period ended
December  31,  2003, and have issued our report thereon dated February 25, 2004;
such  report  is  included elsewhere in this Form 10-K.  Our audit also included
the  2003  and  2002 information included in the financial statement schedule 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 audits.  In our opinion,
such  2003  and  2002  information included in the 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.  The
financial  statement  schedule  of  Green  Mountain  Power  Corporation  and
subsidiaries  as  of  December  31,  2001 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.

/s/DELOITTE  &  TOUCHE  LLP
Boston,  MA
February  25,  2004















<PAGE>
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.






















<PAGE>


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 year ended December 31, 2001 did not contain
any  qualification,  modification,  or  disclaimers.

ITEM  9A.  CONTROLS  AND  PROCEDURES
     Pursuant  to  Rule 13a-15(b) under the Securities and Exchange Act of 1934,
we  carried  out  an  evaluation,  with  the  participation  of  our management,
including  Christopher  L.  Dutton,  President  and  Chief Executive Officer and
Robert  J.  Griffin,  Chief  Financial  Officer,  Vice  President  and Treasurer
(principal  financial  officer), of the effectiveness of our disclosure controls
and  procedures  (as  defined under Rule 13a-15(e) under the Securities Exchange
Act  of  1934)  as  of the end of the period covered by this report.  Based upon
that  evaluation,  our  President  and  Chief  Executive  Officer, and our Chief
Financial  Officer,  Vice  President and Treasurer (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  has  been no change in our internal control over financial reporting
during  the  quarter ended December 31, 2003 that has materially affected, or is
reasonably  likely  to  materially  affect,  our internal control over financial
reporting.


                                    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 20,
2004.  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  2004.

ITEM  14.  PRINCIPAL  ACCOUNTANT  FEES  AND  SERVICES
Fees  Paid  to  Deloitte  &  Touche
During  the  fiscal year ended December 31, 2003, Deloitte & Touche was employed
principally to perform the annual audit and to render other services.  Fees paid
to  Deloitte  &  Touche  for services rendered in fiscal years 2002 and 2003 are
listed  in  the  following  table.
<TABLE>
<CAPTION>

     Years  ended  December  31,

                                  2003      2002
                                --------  --------
<S>                             <C>       <C>
Audit Fees . . . . . . . . . .  $160,471  $162,484
Audit-Related Fees . . . . . .     7,000         -
Tax Services Fees. . . . . . .    36,577    54,147
All other fees . . . . . . . .         -         -
Total Deloitte and Touche fees  $204,048  $216,631
                                ========  ========
</TABLE>



Fees  paid  during 2002 include audit fees of $9,000 and tax fees of $6,050 paid
to  Arthur  Andersen  for  services  rendered  during  2002.
Audit Fees include fees for services performed to comply with Generally Accepted
Auditing  Standards  (GAAS),  including  the  recurring  audit  of the Company's
financial  statements.  This  category also includes fees for audits provided in
connection  with statutory filings or services that generally only the principal
auditor  reasonably can provide to a client, such as procedures related to audit
of  income tax provisions and related reserves, consents and assistance with and
review  of  documents  filed  with  the  Securities  and  Exchange  Commission.
Audit-Related  Fees  include fees associated with assurance and related services
that  are  reasonably  related  to the performance of the audit or review of the
Company's  financial  statements.  This  category  includes  fees  related  to
assistance with implementation of the new Securities and Exchange Commission and
Sarbanes-Oxley Act of 2002 requirements.  Audit-related fees also include audits
of  employee  benefit  plans.
Tax  Fees primarily include fees associated with tax audits, tax compliance, tax
consulting,  as  well  as  tax  planning.
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:

On  December  23,  2003,  a  Form  8-K  filing  announced the VPSB approval of a
Memorandum  of  Understanding  with  the  DPS  regarding  rate  stability,  rate
increases,  and  the  amortization  of  the  Pine  Street  Barge  Canal  costs.

On  December  10,  2003, a Form 8-K filing announced that the Board of Directors
had  approved  changes  to  the  Company's  Bylaws.

On  December  3, 2003, a Form 8-K filing announced a presentation by Christopher
L.  Dutton,  the  President  and CEO, and Robert J. Griffin, CFO, at an electric
industry  conference  entitled  "Investing  in the Electric Utilities Industry".

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

<TABLE>
<CAPTION>

          ITEM  15(A)3  AND  ITEM  15C.  EXHIBITS          SEC  DOCKET
               ,     INCORPORATED  BY
     EXHIBIT               REFERENCE  OR

  NUMBER    DESCRIPTION                                                      EXHIBIT      PAGE FILED HEREWITH
----------  --------------------------------------------------------------  ----------  -----------------------
<C>         <S>                                                             <C>         <C>
       3-A  RESTATED ARTICLES OF ASSOCIATION, AS CERTIFIED . . . . . . . .         3-A  FORM 10-K 1993
            JUNE 6, 1991.                                                                              (1-8291)
     3-A-1  AMENDMENT TO 3-A ABOVE, DATED AS OF MAY 20, 1993.. . . . . . .       3-A-1  FORM 10-K 1993
                                                                                                       (1-8291)
     3-A-2  AMENDMENT TO 3-A ABOVE, DATED AS OF OCTOBER 11, 1996.. . . . .       3-A-2  FORM 10-Q SEPT.
                                                                                                  1996 (1-8291)
       3-B  BY-LAWS OF THE COMPANY, AS AMENDED . . . . . . . . . . . . . .         3-B  FORM 10-K 1996
            FEBRUARY 10, 1997.                                                                         (1-8291)
       3-C  BY-LAWS OF THE COMPANY, AS AMENDED . . . . . . . . . . . . . .         3-C  FORM 8-K DEC. 12, 2004
            DECEMBER 8, 2004                                                                           (1-8291)
     4-B-1  INDENTURE OF FIRST MORTGAGE AND DEED OF TRUST. . . . . . . . .         4-B                 2-27300
            DATED AS OF FEBRUARY 1, 1955.
     4-B-2  FIRST SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . .       4-B-2                 2-75293
            APRIL 1, 1961.
     4-B-3  SECOND SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . . .       4-B-3                 2-75293
            JANUARY 1, 1966.
     4-B-4  THIRD SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . .       4-B-4                 2-75293
            JULY 1, 1968.
     4-B-5  FOURTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . . .       4-B-5                 2-75293
            OCTOBER 1, 1969.
     4-B-6  FIFTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . .       4-B-6                 2-75293
            DECEMBER 1, 1973.
     4-B-7  SEVENTH SUPPLEMENTAL INDENTURE DATED AS. . . . . . . . . . . .       4-A-7                 2-99643
            AUGUST 1, 1976.
     4-B-8  EIGHTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . . .       4-A-8                 2-99643
            DECEMBER 1, 1979.
     4-B-9  NINTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . .       4-B-9                 2-99643
            JULY 15, 1985.
    4-B-10  TENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . .      4-B-10  FORM 10-K 1989
            JUNE 15, 1989.                                                                             (1-8291)
    4-B-11  ELEVENTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . .      4-B-11  FORM 10-Q SEPT.
            SEPTEMBER 1, 1990.                                                                    1990 (1-8291)
    4-B-12  TWELFTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . .      4-B-12  FORM 10-K 1991
            MARCH 1, 1992.                                                                             (1-8291)
    4-B-13  THIRTEENTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . .      4-B-13  FORM 10-K 1991
            MARCH 1, 1992.                                                                             (1-8291)
    4-B-14  FOURTEENTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . .      4-B-14  FORM 10-K 1993
            NOVEMBER 1, 1993.                                                                          (1-8291)
    4-B-15  FIFTEENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . .      4-B-15  FORM 10-K 1993
            NOVEMBER 1, 1993.                                                                          (1-8291)
    4-B-16  SIXTEENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . .      4-B-16  FORM 10-K 1995
            DECEMBER 1, 1995.                                                                          (1-8291)
    4-B-17  REVISED FORM OF INDENTURE AS FILED AS AN EXHIBIT . . . . . . .      4-B-17  FORM 10-Q SEPT.
            TO REGISTRATION STATEMENT NO. 33-59383.                                               1995 (1-8291)
    4-B-18  CREDIT AGREEMENT BY AND AMONG GREEN MOUNTAIN POWER . . . . . .      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)  AMENDMENT TO EXHIBIT 4-B-18. . . . . . . . . . . . . . . . . .   4-B-18(A)  FORM 10-Q SEPT.
                                                                                                  1998 (1-8291)
    4-B-19  SEVENTEENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . .      4-B-19  FORM 10-K 2002
            DECEMBER 1, 2002                                                                           (1-8291)
      10-A  FORM OF INSURANCE POLICY ISSUED BY PACIFIC . . . . . . . . . .        10-A                 33-8146
            INSURANCE COMPANY, WITH RESPECT TO
            INDEMNIFICATION OF DIRECTORS AND OFFICERS.
    10-B-1  FIRM POWER CONTRACT DATED SEPTEMBER 16, 1958,. . . . . . . . .        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  POWER CONTRACT, DATED FEBRUARY 1, 1968, BETWEEN THE COMPANY. .        13-D                 2-34346
            AND VERMONT YANKEE NUCLEAR POWER CORPORATION.
    10-B-3  AMENDMENT, DATED JUNE 1, 1972, TO POWER CONTRACT . . . . . . .      13-F-1                 2-49697
            BETWEEN THE COMPANY AND VERMONT YANKEE NUCLEAR
            POWER CORPORATION.
 10-B-3(A)  AMENDMENT, DATED APRIL 15, 1983, TO POWER. . . . . . . . . . .   10-B-3(A)                 33-8164
            CONTRACT BETWEEN THE COMPANY AND VERMONT
            YANKEE NUCLEAR POWER CORPORATION.
 10-B-3(B)  ADDITIONAL POWER CONTRACT, DATED . . . . . . . . . . . . . . .   10-B-3(B)                 33-8164
            FEBRUARY 1, 1984,BETWEEN THE COMPANY AND
            VERMONT YANKEE NUCLEAR POWER CORPORATION.
    10-B-4  CAPITAL FUNDS AGREEMENT, DATED FEBRUARY 1, . . . . . . . . . .        13-E                 2-34346
            1968, BETWEEN THE COMPANY AND VERMONT
            YANKEE NUCLEAR POWER CORPORATION.
    10-B-5  AMENDMENT, DATED MARCH 12, 1968, TO CAPITAL. . . . . . . . . .        13-F                 2-34346
            FUNDS AGREEMENT BETWEEN THE COMPANY AND
            VERMONT YANKEE NUCLEAR POWER CORPORATION.
    10-B-6  GUARANTEE AGREEMENT, DATED NOVEMBER 5, 1981, OF THE. . . . . .      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  THREE-PARTY POWER AGREEMENT AMONG THE COMPANY, . . . . . . . .        13-I                 2-49697
            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-8                 2-75293
    10-B-9  THREE-PARTY TRANSMISSION AGREEMENT AMONG THE . . . . . . . . .        13-J                 2-49697
            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-10                 2-75293
   10-B-14  AGREEMENT WITH CENTRAL MAINE POWER COMPANY ET. . . . . . . . .        5.16                 2-52900
            AL, TO ENTER INTO JOINT OWNERSHIP OF WYMAN
            PLANT, DATED NOVEMBER 1, 1974.
   10-B-15  NEW ENGLAND POWER POOL AGREEMENT AS AMENDED TO . . . . . . . .         4.8                 2-55385
            NOVEMBER 1, 1975.
   10-B-16  BULK POWER TRANSMISSION CONTRACT BETWEEN THE . . . . . . . . .        13-V                 2-49697
            COMPANY AND VELCO DATED JUNE 1, 1968.
   10-B-17  AMENDMENT TO EXHIBIT 10-B-16, DATED JUNE 1, 1970.. . . . . . .      13-V-I                 2-49697
   10-B-20  POWER SALES AGREEMENT, DATED AUGUST 2, 1976, AS. . . . . . . .     10-B-20                 33-8164
            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,. . . . .     10-B-21                 33-8164
            CONSTRUCTION AND OPERATION OF THE MMWEC PHASE I
            INTERMEDIATE UNITS, DATED OCTOBER 1, 1977
   10-B-28  CONTRACT DATED FEBRUARY 1, 1980, PROVIDING FOR . . . . . . . .     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  BULK POWER PURCHASE CONTRACT DATED APRIL 7,. . . . . . . . . .     10-B-32                 2-75293
            1976, BETWEEN VELCO AND THE COMPANY.
   10-B-33  AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT. . . . . .     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  PHASE I TRANSMISSION LINE SUPPORT AGREEMENT. . . . . . . . . .     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  PHASE I TERMINAL FACILITY SUPPORT AGREEMENT. . . . . . . . . .     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  AGREEMENT WITH RESPECT TO USE OF QUEBEC. . . . . . . . . . . .     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  VERMONT PARTICIPATION AGREEMENT FOR QUEBEC . . . . . . . . . .     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  VERMONT ELECTRIC TRANSMISSION COMPANY, INC.. . . . . . . . . .     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  VETCO CAPITAL FUNDS SUPPORT AGREEMENT DATED AS . . . . . . . .     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  ENERGY BANKING AGREEMENT DATED MARCH 21, 1983, . . . . . . . .     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  INTERCONNECTION AGREEMENT DATED MARCH 21, 1983,. . . . . . . .     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  ENERGY CONTRACT DATED MARCH 21, 1983, BETWEEN. . . . . . . . .     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  AGREEMENT FOR JOINT OWNERSHIP, CONSTRUCTION AND. . . . . . . .     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  HIGHGATE OPERATING AND MANAGEMENT AGREEMENT, . . . . . . . . .     10-B-51                 33-8164
            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. . . . . . . .     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  HIGHGATE TRANSMISSION AGREEMENT DATED AS OF. . . . . . . . . .     10-B-53                 33-8164
            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 . . . . . . . .     10-B-61                 33-8164
            OF THE NEPOOL/HYDRO-QUEBEC + 450 KV HVDC
            TRANSMISSION INTERCONNECTION.
   10-B-62  AGREEMENT BETWEEN UNITIL POWER CORP. AND THE . . . . . . . . .     10-B-62                 33-8164
            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, . . . . . . .     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  FIRM POWER AGREEMENT DATED AS OF OCTOBER 26, 1987, . . . . . .     10-B-69  FORM 10-K 1992
            BETWEEN ONTARIO HYDRO AND VERMONT DEPARTMENT OF                                            (1-8291)
            PUBLIC SERVICE.
   10-B-70  FIRM POWER AND ENERGY CONTRACT DATED AS OF . . . . . . . . . .     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)  AMENDMENT TO 10-B-70.. . . . . . . . . . . . . . . . . . . . .  10-B-70(A)  FORM 10-K 1992
                                                                                                       (1-8291)
   10-B-71  INTERCONNECTION AGREEMENT DATED AS OF. . . . . . . . . . . . .     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  PARTICIPATION AGREEMENT DATED AS OF APRIL 1, 1988, . . . . . .     10-B-72  FORM 10-Q
            BETWEEN HYDRO-QUEBEC AND PARTICIPATING VERMONT                              JUNE 1988
            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)  RESTATEMENT OF THE PARTICIPATION AGREEMENT FILED . . . . . . .  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  FIRM POWER AND ENERGY CONTRACT DATED DECEMBER 29,. . . . . . .     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  TRANSMISSION AGREEMENT DATED DECEMBER 23, 1988,. . . . . . . .     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  SALES AGREEMENT DATED MAY 24, 1989, BETWEEN. . . . . . . . . .     10-B-81  FORM 10-Q
            THE TOWN OF HARDWICK, HARDWICK ELECTRIC DEPARTMENT                          JUNE 1989
            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  SALES AGREEMENT DATED JULY 14, 1989, BETWEEN . . . . . . . . .     10-B-82  FORM 10-Q
            NORTHFIELD ELECTRIC DEPARTMENT AND THE COMPANY                              JUNE 1989
            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  POWER PURCHASE AND SALE AGREEMENT BETWEEN. . . . . . . . . . .     10-B-85  FORM 10-K 1998
            MORGAN STANLEY CAPITAL GROUP INC. AND THE                                                  (1-8291)
            COMPANY
   10-B-86  REVOLVING CREDIT AGREEMENT WITH KEYBANK. . . . . . . . . . . .     10-B-86  FORM 10-Q SEPT.
                                                                                                  2000 (1-8291)
   10-B-87  AMENDMENT TO FLEET REVOLVING CREDIT AGREEMENT. . . . . . . . .     10-B-87  FORM 10-Q SEPT.
                                                                                                  2000 (1-8291)
   10-B-88  ENERGY EAST POWER PURCHASE OPTION AGREEMENT. . . . . . . . . .     10-B-88  FORM 10-Q SEPT.
                                                                                                  2000 (1-8291)
   10-B-89  SECOND AMENDED AND RESTATED CREDIT AGREEMENT BETWEEN . . . . .     10-B-89  FORM 10-K 2001
            KEYBANK NATIONAL ASSOCIATION, FLEET NATIONAL BANK, AND
            THE COMPANY DATED JUNE 20, 2001
   10-B-90  PURCHASE POWER AGREEMENT BETWEEN ENTERGY NUCLEAR VERMONT . . .     10-B-90  FORM 10-Q JUNE 2002
            YANKEE LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION                                    (1-8291)
   10-B-91  FIRST AMENDMENT TO PURCHASE POWER AGREEMENT LISTED AS. . . . .     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  AMENDMENT TO POWER PURCHASE AND SALE AGREEMENT . . . . . . . .     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>       <C>
10-D-1B.  GREEN MOUNTAIN POWER CORPORATION SECOND AMENDED          10-D-1B  FORM 10-K 1993
          AND RESTATED DEFERRED COMPENSATION PLAN FOR DIRECTORS.
10-D-1C.  GREEN MOUNTAIN POWER CORPORATION SECOND AMENDED          10-D-1C  FORM 10-K 1993
          AND RESTATED DEFERRED COMPENSATION PLAN FOR
          OFFICERS.
10-D-1D.  AMENDMENT NO. 93-1 TO THE AMENDED AND RESTATED           10-D-1D  FORM 10-K 1993
          DEFERRED COMPENSATION PLAN FOR OFFICERS.
10-D-1E.  AMENDMENT NO. 94-1 TO THE AMENDED AND RESTATED           10-D-1E  FORM 10-Q
          DEFERRED COMPENSATION PLAN FOR OFFICERS.                          JUNE 1994
10-D-2 .  GREEN MOUNTAIN POWER CORPORATION MEDICAL EXPENSE          10-D-2  FORM 10-K 1991
          REIMBURSEMENT PLAN.
10-D-4 .  GREEN MOUNTAIN POWER CORPORATION OFFICER                  10-D-4  FORM 10-K 1991
          INSURANCE PLAN.
10-D-4A.  GREEN MOUNTAIN POWER CORPORATION OFFICERS'               10-D-4A  FORM 10-K 1990
          INSURANCE PLAN AS AMENDED.
10-D-8 .  GREEN MOUNTAIN POWER CORPORATION OFFICERS'                10-D-8  FORM 10-K 1990
          SUPPLEMENTAL RETIREMENT PLAN.
10-D-15B  GREEN MOUNTAIN POWER CORPORATION COMPENSATION PROGRAM   10-D-15B  FORM 10-K 1997
          FOR OFFICERS AND KEY MANAGEMENT PERSONNEL AS AMENDED
          AUGUST 4, 1997
10-D-15C  GREEN MOUNTAIN POWER 2000 STOCK INCENTIVE PLAN          10-D-15C  FORM 10-K 2001
10-D-40.  SEVERANCE AGREEMENT WITH C. L. DUTTON                    10-D-40  FORM 10-K 2003
10-D-41.  SEVERANCE AGREEMENT WITH D.J. RENDALL                    10-D-41  FORM 10-K 2003
10-D-42.  SEVERANCE AGREEMENT WITH R. J. GRIFFIN                   10-D-42  FORM 10-K 2003
10-D-43.  SEVERANCE AGREEMENT WITH W. S. OAKES                     10-D-43  FORM 10-K 2003
10-D-44.  SEVERANCE AGREEMENT WITH M. G. POWELL                    10-D-44  FORM 10-K 2003
10-D-45.  SEVERANCE AGREEMENT WITH S. C. TERRY                     10-D-45  FORM 10-K 2003
10-D-46.  DEFERRED STOCK UNIT AGREEMENT WITH D.J. RENDALL          10-D-46  FORM 10-K 2003
10-D-47.  DEFERRED STOCK UNIT AGREEMENT WITH C. L. DUTTON          10-D-47  FORM 10-K 2003
10-D-48.  DEFERRED STOCK UNIT AGREEMENT WITH S. C. TERRY           10-D-48  FORM 10-K 2003
10-D-49.  DEFERRED STOCK UNIT AGREEMENT WITH R. J. GRIFFIN         10-D-49  FORM 10-K 2003
10-D-50.  DEFERRED STOCK UNIT AGREEMENT WITH W. S. OAKES           10-D-50  FORM 10-K 2003
10-D-51.  DEFERRED STOCK UNIT AGREEMENT WITH M. G. POWELL          10-D-51  FORM 10-K 2003
10-D-52.  DEFERRED STOCK UNIT AGREEMENT WITH E. A. BANKOWSKI       10-D-52  FORM 10-K 2004
10-D-53.  DEFERRED STOCK UNIT AGREEMENT WITH N. L. BRUE            10-D-53  FORM 10-K 2003
10-D-54.  DEFERRED STOCK UNIT AGREEMENT WITH W. H. BRUETT          10-D-54  FORM 10-K 2003
10-D-55.  DEFERRED STOCK UNIT AGREEMENT WITH M. O. BURNS           10-D-55  FORM 10-K 2003
10-D-56.  DEFERRED STOCK UNIT AGREEMENT WITH L. E. CHICKERING      10-D-56  FORM 10-K 2003
10-D-57.  DEFERRED STOCK UNIT AGREEMENT WITH J. V. CLEARY          10-D-57  FORM 10-K 2003
10-D-58.  DEFERRED STOCK UNIT AGREEMENT WITH D.R. COATES           10-D-58  FORM 10-K 2003
10-D-59.  DEFERRED STOCK UNIT AGREEMENT WITH E. A. IRVING          10-D-59  FORM 10-K 2003
10-D-60.  DIRECTOR DEFERRAL AGREEMENT WITH E. A. BANKOWSKI         10-D-60  FORM 10-K 2003
10-D-61.  DIRECTOR DEFERRAL AGREEMENT WITH M. O. BURNS             10-D-61  FORM 10-K 2003
10-D-62.  DIRECTOR DEFERRAL AGREEMENT WITH D. R. COATES            10-D-62  FORM 10-K 2003
10-D-63.  DIRECTOR DEFERRAL AGREEMENT WITH E. A. IRVING            10-D-63  FORM 10-K 2003
*23-A-1.  CONSENT OF ARTHUR ANDERSEN LLP                            23-A-1
23-A-2 .  CONSENT OF DELOITTE AND TOUCHE LLP                        23-A-2
24 . . .  LIMITED POWER OF ATTORNEY                                     24


</TABLE>





                                                                      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, 2003, 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     February  25,  2004
--------------------------
Christopher  L.  Dutton      (Principal  Executive
                            Officer)

/s/Nordahl  L.  Brue                              March  4,  2004
--------------------
Nordahl  L.  Brue            Chairman  of  the  Board

/s/Elizabeth  A.  Bankowski                         March  1,  2004
---------------------------
Elizabeth  A.  Bankowski      Director

/s/William  H.  Bruett                         March  3,  2004
----------------------
William  H.  Bruett           Director

/s/Merrill  O.  Burns                         March  1,  2004
---------------------
Merrill  O.  Burns            Director

/s/Lorraine  E.  Chickering                              March  2,  2004
---------------------------
Lorraine  E.  Chickering      Director

/s/John  V.  Cleary                         March  4,  2004
-------------------
John  V.  Cleary              Director

/s/David  R.  Coates                         March  4,  2004
--------------------
David  R.  Coates             Director

/s/Euclid  A.  Irving                         March  1,  2004
---------------------
Euclid  A.  Irving            Director



















                                   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:  February  25, 2004                 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      February 25, 2004
------------------------------
Christopher  L.  Dutton         Officer,  and  Director


 /s/  Mary  G.  Powell_______   Chief  Operating  Officer,        March 10, 2004
-----------------------------
   Mary  G.  Powell             Senior  Vice  President

 /s/  Robert  J.  Griffin Chief  Financial  Officer,  Vice   February  25, 2004
-------------------------
   Robert  J.  Griffin          President  and  Treasurer

     *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                              February 25, 2004
      ---------------------------
     Christopher  L.  Dutton
     (Attorney  -  in  -  Fact)