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, 2004
                         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 JUNE 30, 2004, WAS APPROXIMATELY $132,535,487 BASED ON THE
CLOSING  PRICE  OF $26.10 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 17, 2005, WAS
5,164,205.
                       DOCUMENTS INCORPORATED BY REFERENCE
     Portions of the Company's Definitive Proxy Statement relating to its Annual
Meeting  of  Stockholders  to  be  held  on  May  23, 2005, to be filed with the
Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934,
are  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,  2004

Table  of  contents                                   Page

Part  I
Item  1,  Business                                         3

Item  2,  Properties                                   18

Item  3,  Legal  Proceedings                              19

Item  4,  Submission  of  Matters  To  a  Vote  of               19
          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          43

Item  9,  Changes  In  and  Disagreements  with  Accountants          83
          On  Accounting  and  Financial  Disclosure

Item  9A,  Controls  and  Procedures                         83

Item  10  Certain  Officer  Information                         85

Items  11,  12,  13  and  14  Executive  Compensation,  Security     85
          Ownership  of  Certain  Beneficial  Owners  and
          Management,  Certain  Relationships  and  Related
          Transactions  and  Principal  Accounting  Fees
          and  Services

Item  15,  Exhibits  and  Financial  Statement  Schedules,          86



<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 2004 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 that transmits, distributes and sells electricity and
utility  construction services in the State of Vermont ("State" or "Vermont") in
a  service territory with approximately one quarter of Vermont's population.  We
serve  approximately  90,000  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, 2004 were as
follows:
*     33.4  percent  from  residential  customers;
*     33.2  percent  from  small  commercial  and  industrial  customers;
*     21.7  percent  from  large  commercial  and  industrial  customers;
*     9.9  percent  from  sales  to  other  utilities;  and
*     1.8  percent  from  other  sources.

     Approximately  98  percent  of  our  revenue  has resulted from the sale of
electricity  over  the  period  2002  -  2004.

     See  the  Company's  Annual  Report and MD and A, Item 7 below, for further
information  about  revenues.

     During  2004,  our  energy  resources  for retail sales of electricity were
obtained  as  follows:

*     37.5  percent  from  hydroelectric sources (29.2 percent Hydro Quebec, 4.9
percent  Company-owned,  and  3.4  percent  independent  power  producers);
*     36.9 percent from a nuclear generating source (the Entergy Nuclear Vermont
Yankee,  LLC  ("ENVY")  nuclear  plant  described  below);
*     3.9  percent  from  wood;
*     2.5  percent  from  natural  gas  or  oil;  and
*     0.5  percent  from  wind.

     The  remaining  18.7  percent  was  purchased  on  a  short-term basis from
generators  through  the  wholesale  market  operated  by  ISO New England, Inc.
formerly  the  New  England  Power  Pool  ("NEPOOL").

     In  2004,  we  estimate  that  we  purchased  under  existing  contracts or
generated approximately 90 percent of our energy resources to satisfy our retail
and  wholesale  sales of electricity under long-term arrangements, including our
contract with Morgan Stanley Capital Group, Inc. (the "Morgan Stanley Contract")
described  below.  Remaining  retail  and  wholesale  sales  were  met  through
short-term  market  purchases  and  represent  primarily  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  Entergy  Vermont  Yankee  Nuclear  LLC ("ENVY") (the "Vermont
Yankee"  or  "VY"  plant).  We  have  a  33.6 percent equity interest in Vermont
Yankee  Nuclear  Power Corporation ("VYNPC"), which has a long-term power supply
contract with ENVY that entitles us to 20 percent of Vermont Yankee plant output
through  2012.  For  further  information  concerning  Vermont Yankee, see Power
Resources  -  Vermont  Yankee,  below.

     The  Company  owns  approximately  29.2  percent  of  common stock and 30.0
percent  of  the  preferred  stock  of  Vermont  Electric  Power  Company,  Inc.
("VELCO").  VELCO owns the high-voltage transmission system in Vermont.  VELCO's
wholly-owned  subsidiary, Vermont Electric Transmission Company, Inc. ("VETCO"),
was  formed  to finance, construct and operate the Vermont portion of the 450 kV
DC  transmission  line  connecting  the  Province of Quebec with Vermont and New
England.  For  further  information  concerning  VELCO,  see  VELCO  below.

     The  Company  participates  in  the New England regional wholesale electric
power  markets  operated  by  ISO New England, Inc. ("ISO-NE") the regional bulk
power  transmission  organization  established to assure reliable and economical
power  supply in New England.  The Federal Energy Regulatory Commission ("FERC")
has  granted  approval  to ISO-NE to become a regional transmission organization
("RTO")  for  New  England.  On February 1, 2005, ISO-NE commenced operations as
the  RTO,  providing  regional  transmission  service  in  New  England,  with
operational  control  of  the  bulk  power  system  and  responsibility  for
administering  wholesale  markets.  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 agreement 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 VELCO and others.
Included  in these areas are the communities of Vernon (where the Vermont Yankee
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 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,
                                                      2004         2003         2002         2001         2000
                                                   -----------  -----------  -----------  -----------  -----------
<S>                                                <C>          <C>          <C>          <C>          <C>
Net system peak (MW*) . . . . . . . . . . . . . .       326.7        330.2        342.0        341.2        323.5
                                                   -----------  -----------  -----------  -----------  -----------
Production and purchases (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . .     777,292      838,855      901,998      951,146    1,053,223
Wind. . . . . . . . . . . . . . . . . . . . . . .      11,023       10,828       11,458       12,135       12,246
Nuclear . . . . . . . . . . . . . . . . . . . . .     764,010      884,585      771,781      736,420      803,303
Conventional steam. . . . . . . . . . . . . . . .      89,622      100,402       85,910       33,194       53,066
Internal combustion . . . . . . . . . . . . . . .      13,026       12,603        4,090       18,291       35,699
Combined cycle. . . . . . . . . . . . . . . . . .      32,224       68,488       81,362       72,653       73,433
Bilateral and system purchases. . . . . . . . . .     793,939    2,423,831    2,345,205    2,637,055    2,651,361
                                                   -----------  -----------  -----------  -----------  -----------
                    Total production. . . . . . .   2,481,136    4,339,592    4,201,804    4,460,894    4,682,331
Less non-firm sales to other utilities. . . . . .     408,601    2,284,003    2,104,172    2,365,809    2,573,576
                                                   -----------  -----------  -----------  -----------  -----------
Production for firm sales . . . . . . . . . . . .   2,072,535    2,055,589    2,097,632    2,095,085    2,108,755
Less firm sales and  lease transmissions. . . . .   1,973,093    1,937,376    1,951,959    1,956,232    1,954,898
                                                   -----------  -----------  -----------  -----------  -----------
Losses and company use (MWH). . . . . . . . . . .      99,442      118,213      145,673      138,853      153,857
                                                   ===========  ===========  ===========  ===========  ===========
Losses as a % of total production . . . . . . . .        4.01%        2.72%        3.47%        3.11%        3.29%
System load factor (***). . . . . . . . . . . . .        72.4%        71.1%        70.0%        70.1%        74.2%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . .        31.3%        19.3%        21.5%        21.3%        22.5%
Wind. . . . . . . . . . . . . . . . . . . . . . .         0.4%         0.2%         0.3%         0.3%         0.3%
Nuclear . . . . . . . . . . . . . . . . . . . . .        30.8%        20.4%        18.3%        16.5%        17.1%
Conventional steam. . . . . . . . . . . . . . . .         3.6%         2.3%         2.0%         0.7%         1.1%
Internal combustion . . . . . . . . . . . . . . .         0.5%         0.3%         0.1%         0.4%         0.8%
Combined cycle. . . . . . . . . . . . . . . . . .         1.3%         1.6%         1.9%         1.6%         1.6%
Bilateral and system purchases. . . . . . . . . .        32.1%        55.9%        55.8%        59.1%        56.6%
                                                   -----------  -----------  -----------  -----------  -----------
                  Total . . . . . . . . . . . . .       100.0%       100.0%       100.0%       100.0%       100.0%
                                                   ===========  ===========  ===========  ===========  ===========

Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . .     580,710      581,047      553,294      549,151      558,682
Commercial & industrial - small . . . . . . . . .     715,602      703,036      695,504      691,029      704,126
Commercial & industrial - large . . . . . . . . .     666,503      645,271      689,618      710,944      683,296
Other . . . . . . . . . . . . . . . . . . . . . .       7,112        4,986        9,773        2,030        6,713
                                                   -----------  -----------  -----------  -----------  -----------
Total retail sales and lease transmissions. . . .   1,969,927    1,934,340    1,948,189    1,953,154    1,952,817
Sales to Municipals & Cooperatives (Rate W) . . .       3,166        3,036        3,770        3,078        2,081
                                                   -----------  -----------  -----------  -----------  -----------
Total Requirements Sales. . . . . . . . . . . . .   1,973,093    1,937,376    1,951,959    1,956,232    1,954,898
Other Sales for Resale. . . . . . . . . . . . . .     408,601    2,284,003    2,104,172    2,365,809    2,573,576
                                                   -----------  -----------  -----------  -----------  -----------
Total sales and  lease transmissions(MWH) . . . .   2,381,694    4,221,379    4,056,131    4,322,041    4,528,474
                                                   ===========  ===========  ===========  ===========  ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . .      75,507       74,693       73,861       73,249       72,424
Commercial and industrial small . . . . . . . . .      13,515       13,344       13,165       12,976       12,746
Commercial and industrial large . . . . . . . . .          24           25           29           30           23
Other . . . . . . . . . . . . . . . . . . . . . .          62           65           65           65           65
                                                   -----------  -----------  -----------  -----------  -----------
             Total. . . . . . . . . . . . . . . .      89,108       88,127       87,120       86,320       85,258
                                                   ===========  ===========  ===========  ===========  ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . .       13.15        12.98        12.96        13.33        12.50
Commercial & industrial - small . . . . . . . . .       10.63        10.40        10.44        10.90        10.00
Commercial & industrial - large . . . . . . . . .        7.44         7.41         7.31         7.70         6.51
Total retail. . . . . . . . . . . . . . . . . . .       10.32        10.22        10.09        10.44         9.52
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . .       7,691        7,779        7,491        7,497        7,717
Revenues including lease revenues . . . . . . . .  $    1,012   $    1,010   $      971   $      999   $      965
</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  ("DPS" or the "Department"),
created  by statute in 1981, acts as the public advocate in rate and other state
regulatory proceedings and 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.

     Certain  components  of  the businesses of the Company and VELCO, including
certain  rates,  are  subject  to  the jurisdiction of the FERC as follows:  the
Company  as a licensee of hydroelectric developments under Part I of the Federal
Power  Act, and the Company and VELCO as interstate public utilities under Parts
II and III of the Federal Power Act, as amended and supplemented by the National
Energy  Act.

     Our  transmission  assets  and the wholesale rate on sales to two wholesale
customers  are  regulated  by  the FERC.  Revenues from sales to these customers
were  less  than  1.0  percent  of  our  operating  revenues  for  2004.

     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  2004.

     On  July  17,  1997, the FERC approved our Open Access Transmission Tariff.
On  November  26, 2004, we received from FERC an exemption from the standards of
conduct  requirements  of  FERC Order 2004, governing separation of transmission
operations.  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 VYNPC, VELCO and VETCO.  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 . .  July 30, 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  2005.  When repairs and
re-licensing  proceedings  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.  On January 19,
2005, the Department adopted a new 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.

      On  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.  The
Company  filed  a cost of service schedule pursuant to the plan in November 2004
and  received  approval  from  the VPSB to implement the plan's 2005 1.9 percent
rate  increase,  effective  January  1,  2005.
     Allows  the  Company  the opportunity to file for rate increases during the
period  from  January  1,  2003  to December 31, 2006 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.

     For  further  discussion  of  the  Company's  2003  Rate Plan, see Item 7a.
Quantitative  and  Qualitative  Disclosures  About  Market  Risk, and Other Risk
Factors  -  Rates.

SINGLE  CUSTOMER  DEPENDENCE
     The  Company  had  one major retail customer, IBM, metered at two locations
that  accounted for 16.4 percent, 16.6 percent and 17.3 percent of the Company's
retail operating revenues in 2004, 2003 and 2002, 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 approximately five percent,
inclusive  of  projected  declines  in sales to other residential and commercial
customers.  See  Item  7a. Quantitative and Qualitative Disclosures About Market
Risk, and Other Risk Factors - Customer Concentration Risk, and Note A of Notes.

COMPETITION  AND  RESTRUCTURING
     Competition  currently  takes  several  forms.  At  the wholesale level New
England  has  implemented its version of FERC's "standard market design ("SMD"),
which  is a detailed competitive market framework that has resulted in bid-based
competition  of  power  suppliers  rather  than prices set under cost of service
regulation.  At the retail level, customers have long had energy options such as
propane,  natural  gas  or  oil  for  heating,  cooling  and  water heating, and
self-generation.  Another  competitive  threat is the potential for customers to
form  municipally  owned  utilities  in  the  Company's  service  territory.

     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.  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 $56 million and $96 million over the life of the
Company's  current  contracts.

     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.  There are
currently  no  regulatory  proceedings,  court  actions  or  pending legislative
proposals  to  adopt  electric  industry  restructuring in Vermont.  For further
information  regarding  Competition and Restructuring, See Item 7a. Quantitative
and  Qualitative  Disclosures  About  Market  Risk,  and  Other  Risk  Factors -
Regulatory  Risk.

     The Town of Rockingham, Vermont, located in the southeastern portion of our
service territory, has exercised an option to purchase a hydro-electric facility
partially  located in the town (the "Bellows Falls facility").  If Rockingham or
its  assignee  is  successful  in  arranging  for  purchase of the Bellows Falls
facility,  we  expect  to  conclude  an  agreement  to  permit  Rockingham to be
responsible  for  its  own  power  supply  needs,  with  the  Company  providing
distribution  and other services to the town.  In any such agreement the Company
would  continue  to  own  its distribution plant located in the town and receive
distribution  services  revenues  sufficient  to  cover  all  costs of providing
services and all stranded costs associated with the Company's present obligation
to  provide  integrated  electric  service  to customers in Rockingham.  Such an
arrangement  would  require VPSB approval.  The Company receives annual revenues
of  approximately  $3  million  from  its  customers  in  Rockingham.

CONSTRUCTION  AND  CAPITAL  REQUIREMENTS
     Our  capital  expenditures for 2002 through 2004 and projected for 2005 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
     We  generated,  purchased or transmitted 2,072,535 MWh of energy for retail
and  requirements  wholesale  customers for the twelve months ended December 31,
2004.  The  corresponding  maximum one-hour integrated demand during that period
was  326.7 MW on December 21, 2004.  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 12/31/2004          of annual peak
                                     MWH     percent     KW     percent
                                 ---------  --------  -------  --------
<S>                              <C>        <C>       <C>      <C>
Wholly-owned plants:
Hydro . . . . . . . . . . . . .    101,517      4.9%   23,370      6.3%
Diesel and Gas Turbine. . . . .     13,026      0.6%   58,550     15.8%
Wind. . . . . . . . . . . . . .     11,023      0.5%      960      0.3%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . .      5,830      0.3%    6,470      1.7%
Stony Brook I . . . . . . . . .     22,117      1.1%   30,936      8.3%
McNeil. . . . . . . . . . . . .     24,171      1.2%    5,770      1.6%
Long Term Purchases:
Vermont Yankee/ENVY . . . . . .    764,010     36.9%   97,451     26.3%

Hydro Quebec. . . . . . . . . .    605,718     29.2%  107,391     29.0%
Stony Brook I . . . . . . . . .     10,107      0.5%   14,124      3.8%
Other:
Independent Power Producers . .    124,617      6.0%   25,610      6.9%
Morgan Stanley. . . . . . . . .    193,158      9.3%        -        -
ISO-NE and Short-term purchases    197,241      9.5%        -        -
                                 ---------  --------  -------  --------
Net Own Load. . . . . . . . . .  2,072,535    100.0%  370,632    100.0%
                                 =========  ========  =======  ========
</TABLE>


VERMONT  YANKEE.
     On  July  31,  2002, VYNPC 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 VYNPC, 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 VYNPC 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 Vermont Yankee plant.

     Our  ownership  share of VYNPC increased from approximately 19.0 percent in
2003  to approximately 33.6 percent currently, due to VYNPC's purchase last year
of  certain  minority shareholders' interests.  VYNPC's primary role consists of
administering its power supply contract with ENVY and its contracts with VYNPC's
present  sponsors.  Our  entitlement  to  energy  produced by the Vermont Yankee
nuclear  plant  has  remained  at  20  percent  of  plant  production.

     During  periods  when  Vermont  Yankee  power  is unavailable, the costs of
replacement  power  occasionally  exceed those costs that we would have incurred
for  power  purchased  pursuant  to  our  power  supply  agreement  with  VYNPC.
Replacement  power  is  available  to  us  from the wholesale market 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.

     Vermont  Yankee's  current operating license expires March 2012.  Since the
Company  no  longer  owns an interest in the Vermont Yankee nuclear plant, we no
longer  bear  the  operating  costs  and  risks  associated  with  running  and
decommissioning  the  plant.

     During  the  year  ended  December 31, 2004, we used 764,010 MWh of Vermont
Yankee  energy  (supplied  by  ENVY)  representing  36.9  percent  of  the  net
electricity  generated  and  purchased  ("net  power  supply")  by  the Company.

     See  Item  7a.  Quantitative and Qualitative Disclosures About Market Risk,
and  Other  Risk  Factors - Other Power Supply Risks, and Notes B and 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.  Commencing with implementation of New
England's  RTO,  the  Highgate  facilities  are  now  controlled and operated by
ISO-NE.  We  do  not expect ISO-NE's operation or control of these facilities to
affect  the  Company's  deliveries  of power from Hydro Quebec under our current
power  contract  commitments.

     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
National  Grid,  successor  to  New  England  Electric  System.

     Phase II.  Phase II provides 2,000 MW of capacity for transmission of Hydro
Quebec  power  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, 2004, the
present  value  of the Company's obligation was approximately $4.2 million.  The
Company's  projected  future  minimum  payments  under  the  Phase  II  support
agreements  are  approximately  $383,000  for each of the years 2005-2009 and an
aggregate  of  $2,299,000  for  the  years  2010-2015.

     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  National Grid, successor to New England Electric
System,  in which certain of the Phase II participating utilities, including the
Company,  own  equity  interests.  The Company owns approximately 3.2 percent of
the equity of the corporations owning the Phase II facilities.    See Note B and
Note  J  of  Notes.

     Hydro  Quebec Power Supply Contracts.  The bulk of our purchases from Hydro
Quebec  are  pursuant  to  two  schedules,  B  and  C3, of 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 agreement (the
"9701  agreement") with Hydro Quebec under which Hydro Quebec paid $8,000,000 to
the  Company  in  exchange  for  certain  power  purchase options.  See Item 7a.
Quantitative  and  Qualitative  Disclosures  About  Market  Risk, and Other Risk
Factors  -  Power  Contract  Commitments,  and  Note  K  of  Notes.

     During  2004,  we  used 363,849 MWh under Schedule B, and 241,869 MWh under
Schedule  C3  of  the  VJO  Contract, representing 29.2 percent of our net power
supply.

MORGAN  STANLEY  CONTRACT  -  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  7a.  Quantitative and Qualitative Disclosures About Market Risk,
and  Other  Risk  Factors  -  Power  Contract  Commitments  and Note K of Notes.

ISO-NE  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  to  recover  all  of the forecasted fuel or production costs and to recover
some, if not all, associated capacity costs.  During 2004, the Company purchased
197,241  MWh  representing  9.5  percent  of  the  Company's  net  power supply.

     During  2002,  the  FERC  accepted ISO-NE's request to implement a Standard
Market  Design  ("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.  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 2004, we used 32,224 MWh from this plant representing 1.6 percent of
our  net  power  supply.  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.  Florida Power &
Light  is  the  principal  owner  and  operator  of  the  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  2004,  we used 5,830 MWh from this unit representing 0.3 percent of
our  net  power  supply.  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  2004, we used 24,171 MWh from this unit representing 1.2 percent of
our  net power supply.  See Note I of Notes.  The Burlington Electric Department
is  the  principal  owner  and  operator  of  the  McNeil  plant.

     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 2004 was approximately 34.3
percent  or  51.5  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  currently  under  development.

     In  2004,  through our direct contracts and VEPPI, we purchased 124,617 MWh
of  qualifying  facilities  production representing 6.0 percent of our net power
supply.

     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  2004,  Company  owned  hydroelectric  plants  produced  101,517  MWh,
representing  4.9  percent  of  our  net  power  supply.  See  State and Federal
Regulation  -  Licensing.

     VELCO.  The  Company  and  fifteen  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 matters.  See Note B
of  Notes.

     FUEL.  During  2004,  our  retail  and  requirements  wholesale  sales were
provided  by  the  following  fuel  sources:

*     37.5  percent  from  hydroelectric sources (29.2 percent Hydro Quebec, 4.9
percent  Company-owned,  and  3.4  percent  independent  power  producers;
*     36.9  percent from a nuclear generating source (the Vermont Yankee nuclear
plant);
*     3.9  percent  from  wood;
*     2.5  percent  from  natural  gas  and  oil;
*     0.5  percent  from  wind;  and
*     18.7  percent purchased on a short-term basis from other utilities through
the  ISO-NE  and  Morgan  Stanley.

     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  2004.  None of the
utilities  from  which  we expect to purchase oil- or gas-fired capacity in 2005
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  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.

     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  2004,  the  project  produced  11,023 MWh, representing 0.5
percent  of  the  Company's  net  power  supply.

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  A  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,  2004,  the  Company  had 192 employees, exclusive of
temporary  employees.  The  Company considers its relations with employees to be
excellent.  The  current  labor  contract  expires  December  31,  2007.

ENERGY  EFFICIENCY
     In  2004,  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  1,715  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 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,  2004, approximately 1,587 of the Company's largest customers,
comprising  approximately  51  percent  of  retail revenues, received service on
mandatory time-of-use rates.  Pursuant to the Company's 2003 Rate Plan, in March
2004,  the  Company  filed  with  the VPSB a new fully-allocated cost of service
study  and  rate re-design, which re-allocates the Company's revenue requirement
among  all  customer  classes  on the basis of current costs.  The Company's new
proposed rate design is subject to VPSB approval.  We do not expect the proposed
rate  design  to  adversely  affect  operating  results.

DISPATCHABLE  AND  INTERRUPTIBLE  SERVICE  CONTRACTS
     In  2004,  we  had  26  dispatchable  power  contracts:  22  contracts were
year-round, and 4 customers had seasonal contracts.  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
     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
non-performing  note  from  a  hydroelectric  facility  in  New Hampshire, and a
wastewater  business  in the process of completing dissolution.  For information
regarding  our  unregulated  businesses,  see  Note  A  of  the  Notes.

EXECUTIVE  OFFICERS
     The  names,  ages, and positions of our Executive Officers, in alphabetical
order,  as  of  March  15,  2005  are:

Christopher  L.  Dutton    56
     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        48
    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          58
     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           44
     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        49
     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         62
     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 April 12, 2005,
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.
We  also  make  available  on  the  website  the  Company's Corporate Governance
Guidelines,  Code  of Ethics and Conduct, Bylaws, and the Charters of the Audit,
Compensation  and  Governance Committees of the Company.  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  35.3 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 58.5 MW.  We have two diesel
generating  stations  with  an  aggregate  nameplate  rating  of  8.0  MW and an
estimated  aggregate  claimed  capability  of  6.3  MW.  We  also  have  a  wind
generating  facility  with a nameplate rating of 6.1 MW and a claimed capability
of  5.9  MW.

     We  also  own:
*     33.6  percent  of  the  outstanding common stock of Vermont Yankee Nuclear
Power  Corporation  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 Vermont Yankee
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, 2004, approximately 2 miles of 115 kV
transmission  lines,  10  miles  of  69  kV transmission lines, 5 miles of 44 kV
transmission lines, 196 miles of 34.5 kV transmission lines, and 2 miles of 13.8
kV  transmission  lines.  Our  distribution  system included approximately 2,657
miles  of overhead lines of 2.4 to 34.5 kV and 433 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 949,000 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.
The  Company  also  owns  59.4 percent of the metallic neutral return, a neutral
conductor  for  the  NEPOOL/Hydro  Quebec  interconnection.

     We  also  own  29.2  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.

     VELCO's  properties  consist  of  about  573 miles of high voltage overhead
transmission  lines  and  associated substations.  The lines connect on the west
with the lines of Niagara Mohawk Power Corporation at the Vermont-New York state
line  near  Whitehall, New York, and Bennington, Vermont, and with the submarine
cable  of  NYPA near Plattsburgh, New York; on the south and east with the lines
of  New  England  Power  Company  and  PSNH; on the south with the facilities of
Vermont  Yankee; and on the north with lines of Hydro Quebec through a converter
station  and  tie  line  jointly  owned by the Company and several other Vermont
utilities.

     VELCO's  wholly-owned subsidiary, VETCO, has about 52 miles of high voltage
DC  transmission  line  connecting with the transmission line of Hydro Quebec at
the  Quebec-Vermont  border  in the Town of Norton, Vermont; and connecting with
the  transmission  line  of  New  England  Electric  Transmission Corporation, a
subsidiary  of  National  Grid USA, at the Vermont-New Hampshire border near New
England  Power  Company's  Moore  hydro-electric  generating  station.

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 claimed
                                                                      capability
                            Location            Name           Fuel     MW
                         ---------------  -----------------  --------  ----
<S>                      <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 (1)  Hydro      5.0
Hydro . . . . . . . . .  Bolton, VT       DeForge #1         Hydro      7.8
Diesel. . . . . . . . .  Vergennes, VT    Vergennes #9       Oil        4.1
Diesel. . . . . . . . .  Essex Jct., VT   Essex #19          Oil        2.2
Gas Turbine . . . . . .  Berlin, VT       Berlin #5          Oil       45.0
Turbine . . . . . . . .  Colchester, VT   Gorge #16          Oil       13.5
Wind. . . . . . . . . .  Searsburg, VT    Searsburg          Wind       5.9
Jointly Owned
Steam . . . . . . . . .  Yarmouth, ME     Wyman #4           Oil        6.9
Steam . . . . . . . . .  Burlington, VT   McNeil (2)         Wood/Gas   6.6
Combined. . . . . . . .  Ludlow, MA       Stony Brook #1     Oil/Gas   31.0
Total Winter Capability                                               150.5
                                                                   ========
</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.



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  2004  and  2003:
<TABLE>
<CAPTION>


                 HIGH    LOW
                ------  ------
<S>             <C>     <C>
                  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
                  2004
First Quarter.  $26.29  $22.60
Second Quarter   26.10   24.40
Third Quarter.   26.82   25.08
Fourth Quarter   29.15   24.80
</TABLE>
The  number  of  common  stockholders  of  record  as  of  February 18, 2004 was
approximately  5,119,  $3.33333  par  value.
     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>
2003  $   0.19  $   0.19  $   0.19  $   0.19
2004  $   0.22  $   0.22  $   0.22  $   0.22
</TABLE>
 Dividend  Policy.  The  Company increased its dividend in February 2005 from an
annual  rate  of  $0.88  per  share  to $1.00 per share.  The Company's dividend
payout  ratio  remains  comparatively  low,  at approximately 48 percent of 2004
earnings  from  continuing  operations.  We  expect  to grow our dividend payout
ratio to the middle of a payout range of 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.

     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.
<TABLE>
<CAPTION>

ITEM  6.   SELECTED  FINANCIAL  DATA
RESULTS  OF  OPERATIONS  FOR  THE  YEARS  ENDED  DECEMBER  31,
--------------------------------------------------------------
                                                                   2004       2003       2002       2001       2000
                                                                 ---------  ---------  ---------  ---------  ---------
In thousands, except per share data
<S>                                                              <C>        <C>        <C>        <C>        <C>
Operating Revenues. . . . . . . . . . . . . . . . . . . . . . .  $228,816   $280,470   $274,608   $283,464   $277,326
Operating Expenses. . . . . . . . . . . . . . . . . . . . . . .   213,338    265,164    259,528    267,005    272,066
      Operating Income. . . . . . . . . . . . . . . . . . . . .    15,478     15,306     15,080     16,459      5,260
                                                                 ---------  ---------  ---------  ---------  ---------
Other Income
      AFUDC - equity. . . . . . . . . . . . . . . . . . . . . .       449        387        233        210        284
      Other . . . . . . . . . . . . . . . . . . . . . . . . . .     1,638      1,692      2,252      2,163      2,422
      Total other income. . . . . . . . . . . . . . . . . . . .     2,087      2,079      2,485      2,373      2,706
                                                                 ---------  ---------  ---------  ---------  ---------
Interest Charges
      AFUDC - borrowed. . . . . . . . . . . . . . . . . . . . .      (285)      (267)      (103)      (188)      (228)
      Other . . . . . . . . . . . . . . . . . . . . . . . . . .     6,791      7,324      6,273      7,227      7,485
          Total interest charges. . . . . . . . . . . . . . . .     6,506      7,057      6,170      7,039      7,257
                                                                 ---------  ---------  ---------  ---------  ---------
Net Income (Loss) from continuing operations before . . . . . .    11,059     10,328     11,395     11,793        709
   preferred dividends
Net Income (Loss) from discontinued operations, including
   provisions for loss on disposal. . . . . . . . . . . . . . .       525         79         99       (182)    (6,549)
Dividends on Preferred Stock. . . . . . . . . . . . . . . . . .         -          3         96        933      1,014
                                                                 ---------  ---------  ---------  ---------  ---------
Net Income (Loss)Applicable
      to Common Stock . . . . . . . . . . . . . . . . . . . . .  $ 11,584   $ 10,404   $ 11,398   $ 10,678   $ (6,854)
                                                                 =========  =========  =========  =========  =========
Common Stock Data
 Basic earnings per share-continuing operations . . . . . . . .  $   2.18   $   2.08   $   2.02   $   1.93   $  (0.06)
 Basic earnings per share-discontinued operations . . . . . . .  $   0.10   $   0.01   $   0.02   $  (0.03)  $  (1.19)
 Basic earnings per share . . . . . . . . . . . . . . . . . . .  $   2.28   $   2.09   $   2.04   $   1.90   $  (1.25)
                                                                 =========  =========  =========  =========  =========
 Diluted earnings (loss) per share from continuing operations .  $   2.10   $   2.01   $   1.96   $   1.88   $  (0.06)
 Diluted earnings (loss) per share from discontinued operations  $   0.10   $   0.01   $   0.02   $  (0.03)  $  (1.19)
 Diluted earnings (loss) per share. . . . . . . . . . . . . . .  $   2.20   $   2.02   $   1.98   $   1.85   $  (1.25)
                                                                 =========  =========  =========  =========  =========
Cash dividends declared per share . . . . . . . . . . . . . . .  $   0.88   $   0.76   $   0.60   $   0.55   $   0.55
 Weighted average shares outstanding-basic. . . . . . . . . . .     5,083      4,980      5,592      5,630      5,491
 Weighted average equivalent shares outstanding-diluted . . . .     5,254      5,140      5,756      5,789      5,491
</TABLE>
<TABLE>
<CAPTION>

FINANCIAL  CONDITION  AS  OF  DECEMBER  31
------------------------------------------
                                           2004      2003      2002      2001      2000
                                         --------  --------  --------  --------  --------
In thousands
<S>                                      <C>       <C>       <C>       <C>       <C>
ASSETS
Utility Plant, Net. . . . . . . . . . .  $232,712  $228,862  $223,476  $196,858  $194,672
Other Investments . . . . . . . . . . .    18,959    13,706    21,552    20,945    20,730
Current Assets. . . . . . . . . . . . .    35,462    31,688    31,432    36,183    53,652
Deferred Charges. . . . . . . . . . . .    53,731    55,590    60,390    72,468    46,036
Non-Utility Assets. . . . . . . . . . .       755     1,105       995     1,075     1,518
Total Assets. . . . . . . . . . . . . .  $341,619  $330,951  $337,845  $327,529  $316,608
                                         ========  ========  ========  ========  ========
CAPITALIZATION AND LIABILITIES
Common Stock Equity . . . . . . . . . .  $109,581  $ 99,915  $ 91,722  $101,277  $ 92,044
Redeemable Cumulative Preferred Stock .         -         -        55    12,560    12,795
Long-Term Debt, Less Current Maturities    93,000    93,000    93,000    74,400    72,100
Capital Lease Obligation. . . . . . . .     4,493     4,963     5,287     5,959     6,449
Current Liabilities . . . . . . . . . .    24,468    22,715    38,491    38,841    68,109
Deferred Credits and Other. . . . . . .   107,906   108,281   107,349    92,791    61,794
Non-Utility Liabilities . . . . . . . .     2,171     2,077     1,941     1,701     3,317
Total Capitalization and Liabilities. .  $341,619  $330,951  $337,845  $327,529  $316,608
                                         ========  ========  ========  ========  ========
</TABLE>
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF  OPERATIONS  ("MD  AND  A").
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  substantial,  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 2005 from an annual rate of
$0.88 per share to $1.00 per share.  The Company's dividend payout ratio remains
comparatively  low, at approximately 48 percent of 2004 earnings from continuing
operations.  We  expect  to  grow  our  dividend payout ratio to the middle of a
payout range of 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 order to attract capital.
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 costs, and to earn its
allowed  rate  of  return.  In accordance with the rate plan, the VPSB approved,
and  the  Company implemented, a 1.9 percent rate increase, effective January 1,
2005.

     Power  supply expenses were equivalent to approximately 63 percent of total
revenues  in 2004.  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 included 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 customer concentration 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.

     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
                                                                                2004     2003     2002
                                                                               -------  -------  -------
<S>                                                                            <C>      <C>      <C>
Consolidated diluted earnings per share of common stock . . . . . . . . . . .  $ 2.20   $ 2.02   $ 1.98
Consolidated diluted earnings per share of common stock-continuing operations  $ 2.10   $ 2.01   $ 1.96
Consolidated return on average common equity. . . . . . . . . . . . . . . . .   11.06%   10.76%   11.03%
</TABLE>

Earnings  from  continuing  operations improved in 2004 primarily as a result of
increased  recognition  of  revenues  previously  deferred  under  a  VPSB order
described  below,  and  from  growth in retail sales of electricity to large and
small  commercial  and  industrial  customers.  Higher  transmission  expenses
partially  offset  these  benefits.

     Earnings  from  discontinued  operations  totaled  $.10  per  share in 2004
compared  with  $.01 per share in the prior year, reflecting diminished exposure
to  outstanding  litigation  against  an  inactive  Northern  Water  Resources
subsidiary  that  led  to  reversal  of  previously  recorded  reserves.

     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 (generating approximately $4 million in
added  annual  revenues)  effective January 1, 2005, and 0.9 percent (generating
approximately  $2  million  in added annual revenues) effective January 1, 2006.
The  first  of  these  rate  increases has been implemented effective January 1,
2005.  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.  The  2003  Rate Plan
permitted  us  to  continue  to  defer and recognize these revenues in 2004.  We
recognized  approximately $3.0 million of these deferred revenues to achieve our
allowed  rate  of  return during 2004, compared with approximately $1.1 and $4.5
million  recognized  in  2003  and  2002,  respectively.

     Retail  operating revenues in 2004 increased by $4.5 million or 2.3 percent
compared  with  2003, reflecting an improving economy, including a modest growth
in  the  number  of  customers  served,  and  increased  recognition of revenues
deferred  under  the 2003 Rate Plan discussed above.  Total retail megawatt hour
sales  of  electricity  increased by 1.8 percent in 2004, compared with the same
period  in  2003.  Megawatt  hour  sales  of  electricity  to  large  and  small
commercial  and  industrial  customers increased by 3.3 percent and 2.0 percent,
respectively,  while sales to residential customers were flat when compared with
2003,  reflecting  milder  and  more  normal  weather  conditions  in  2004.

     Wholesale  revenues  in 2004 decreased by $56.2 million compared with 2003,
reflecting  reduced  sales of electricity to Morgan Stanley Capital Group, Inc.,
under  a contract designed to manage price risks associated with changing fossil
fuel  prices.  The  reduction  in  wholesale  revenues  did not adversely affect
Company  earnings  in  2004  and  is  not  expected  to  adversely affect future
operating  results.

     Power  supply  expenses  in 2004 decreased $53.3 million compared with 2003
due  to  decreased  wholesale sales of electricity, principally those associated
with  the  Morgan  Stanley contract.  Power supply expense also decreased due to
reduced expenses to supply an option contract with Hydro Quebec, and an increase
in credits resulting from monthly financial transmission rights ("FTR") auctions
conducted  by  ISO  New  England  designed  to  make  regions  with  inadequate
transmission  and  generation  pay  a  premium  for  energy  delivery.

     The  Company  accounts  for  its  wholly-owned  subsidiary,  Northern Water
Resources  ("NWR"),  as  a discontinued operation.  NWR's assets and liabilities
consist primarily of deferred tax assets and liabilities relating to a number of
investments  that  the  Company  has  discontinued, deactivated, sold in part or
retained  as  passive minority interests.  Remaining holdings include a minority
equity  investment in a wind project that usually, but not always, generates tax
losses;  minority  interest  in a manufacturer of waste treatment equipment; and
some non-performing loans.  The Company recognized income of $.10 per share from
Discontinued  Operations  during  2004,  compared with earnings of $.01 in 2003,
primarily  reflecting  diminished exposure to outstanding litigation that led to
reversal  of  previously  recorded reserves.  All of these investments have been
written  off  except  for  associated  deferred  tax  amounts, net of applicable
valuation  allowances.

     In  2003,  the Company reported consolidated earnings of $2.02 per share of
common  stock,  diluted,  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 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 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.

CRITICAL  ACCOUNTING  POLICIES
     Management  believes  our  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.

     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.  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.  Costs are
deferred  as  regulatory  assets  when the Company concludes that future revenue
will  be  provided  to  permit  recovery  of  the previously incurred cost.  The
Company analyzes evidence supporting deferral, including provisions for recovery
in regulatory orders, past regulatory precedent, other regulatory correspondence
and  legal  representations.  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 some other 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  its regulatory assets, net of
regulatory  liabilities  as  set  forth  in  the  table  below:
<TABLE>
<CAPTION>

REGULATORY  ASSETS  AND  LIABILITIES
                                                      At December 31,
                                                      2004         2003
                                                 ---------------  -------
Regulatory assets:                               (in thousands)
<S>                                              <C>              <C>
Demand-side management programs . . . . . . . .  $         7,293  $ 6,713
Purchased power costs . . . . . . . . . . . . .            2,322    2,574
Pine Street barge canal . . . . . . . . . . . .           13,250   12,954
Net power supply deferral . . . . . . . . . . .           12,085   19,734
Other regulatory assets . . . . . . . . . . . .            6,932    8,439
                                                 ---------------  -------
Total regulatory assets . . . . . . . . . . . .           41,882   50,414
                                                 ---------------  -------
   Regulatory liabilities:
Rate levelization liability . . . . . . . . . .                -    2,970
Accumulated cost of removal . . . . . . . . . .           19,806   21,238
Other regulatory liabilities. . . . . . . . . .            4,012    2,643
                                                 ---------------  -------
Total regulatory liabilities. . . . . . . . . .           23,818   26,851
                                                 ---------------  -------
Regulatory assets net of regulatory liabilities  $        18,064  $23,563
                                                 ===============  =======
</TABLE>

The  2003  Rate  Plan,  approved  by  the  VPSB  in  December 2003, provides for
amortization  and  recovery of nearly 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.

     The  net  power  supply  deferral represents the net value of certain power
supply  contracts that must be marked to fair value as derivatives under current
accounting rules.  The Company records contract specified prices for electricity
as expense in the period used, as opposed to fair market values reflected in the
above  table, in accordance with accounting required by a VPSB order.  The power
supply  contract  expenses  are  fully recovered in the rates we charge, and are
discussed  in  detail  under  Power  Supply  Derivatives.

     Regulatory  assets represent incurred costs that have been deferred because
the  Company has concluded that they are probable of future recovery in customer
rates.  Management's  conclusions  represent  a  critical  accounting  estimate.
Regulatory  liabilities  generally represent obligations to reduce future rates.

     Our  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 and net of estimates
of electricity lost during transmission, in order to match revenues with related
costs.

     The  Company's  defined  benefit  plan cost can vary significantly based on
plan  assumptions  and results including the following factors:  interest rates,
healthcare  cost  trends,  return  on  assets  and  compensation  cost  trends.

     Management  also  exercises  judgments  about  the  expected  outcome  of
litigation  for  contingencies.  If  the  Company determines that it is probable
that  it  will  sustain  a  loss  associated with pending litigation, regulatory
proceedings  or  tax  matters,  and if it can estimate the likely amount of such
loss,  it  will  record  a  liability  for  that  amount.

     Our critical accounting policies are discussed further 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,"  in Note H, "Pension and Retirement Plans" and in Note I,
"Commitments  and  Contingencies."

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,
benefit  plan  cost  sensitivity to interest rates and healthcare cost inflation
and  weather.  Discussion  of  these  and  other  risks,  as  well  as  factors
contributing  to  mitigation  of  these  risks,  follows.

POWER  SUPPLY  RISKS.
POWER  CONTRACT  COMMITMENTS  -  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 ("VYNPC") Contract
(the  "VYNPC  Contract"),  which together supply approximately 75 percent of our
retail  load.  The  Company has also entered into a contract with Morgan Stanley
Capital Group, Inc. (the "Morgan Stanley Contract") designed to manage wholesale
electricity price risks associated with changing fossil fuel prices.  The Morgan
Stanley  Contract  supplies  an  additional  16  percent of our load and expires
December  31, 2006.  The VJO and VYNPC contracts are summarized in the following
table.
<TABLE>
<CAPTION>
                          2004     2004     2003     2003 Contract
                           MWh    $/MWh     MWh    $/MWh   Expires
                         -------  ------  -------  ------  -------
<S>                      <C>      <C>     <C>      <C>     <C>
VJO Contract. . . . . .  605,718  $74.47  664,225  $69.81     2015
Vermont Yankee Contract  764,010  $43.63  884,585  $43.08     2012
</TABLE>
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.

     On  July  31,  2002, VYNPC completed the sale of its nuclear power plant to
Entergy  Nuclear  Vermont Yankee LLC ("ENVY").  As part of the sale transaction,
VYNPC entered into a Power Purchase Agreement ("PPA") with ENVY under 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 generally range from $39 to $45 per MWh.  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.  We  no longer bear the operating costs and risks
associated  with  running and decommissioning the plant.  If market prices rise,
however,  PPA  prices  are  not adjusted upward in excess of the contract price.
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.

     In  addition  to  the VJO and VYNPC contracts, the Company entered into the
Morgan  Stanley  Contract  in 1999.  In August 2002, the Morgan Stanley Contract
was  modified  and  extended  to December 31, 2006.  The Morgan Stanley Contract
price is substantially below current market prices.  The Morgan Stanley Contract
currently  supplies approximately 16 percent of the Company's estimated customer
demand  ("load").

     Under  the  Morgan  Stanley  Contract,  on  a  daily  basis,  and at Morgan
Stanley's discretion, we sell power to Morgan Stanley from part of our portfolio
of  power  resources  at  pre-defined  operating and pricing parameters.  Morgan
Stanley  sells to the Company, at a pre-defined price, power sufficient to serve
pre-established  load  requirements.  We  remain  responsible  for  resource
performance  and availability.  The Morgan Stanley Contract provides no coverage
against  major unscheduled power supply outages.  Beginning January 1, 2004, the
Company reduced the power that it sells pursuant to the Morgan Stanley Contract.
The  output  of some of our power-supply resources, including purchases pursuant
to  our  Hydro  Quebec  and  VYNPC  contracts, which were sold to Morgan Stanley
through  2003,  are  no  longer  included  in the Morgan Stanley Contract.  This
reduction in sales to Morgan Stanley reduced wholesale revenues by approximately
$56.2  million  during 2004 when compared with 2003, and correspondingly reduced
power  supply expense by a similar amount.  This change did not adversely affect
the  Company's  operating results or its opportunity to earn its allowed rate of
return  during  2004.

     In 1996, the Company entered into an agreement with Hydro Quebec ("the 9701
agreement")  under  which  Hydro Quebec paid $8.0 million to the Company in 1997
and  we  provided  Hydro  Quebec  options for the purchase of power in specified
maximum  amounts  through  2015,  as  discussed below under "Power Supply Risk."

POWER  SUPPLY  PRICE RISK - All of the Company's power supply contract costs are
currently  being  recovered  through  rates  approved  by the VPSB.  The Company
records the annual cost of power obtained under long-term contracts as operating
expenses.  The  Company  meets  the  majority  of  its customer demand through a
series  of long-term physical and financial contracts.  There are occasions when
the  available  supply  of  electricity is insufficient to meet customer demand.
During  those  periods,  electricity  is  purchased  at  market  prices.

     We  expect  approximately  90  percent  of  our estimated load requirements
through  2006  to  be met by our contracts and generation and other power supply
resources.  These  contracts  and  resources  significantly reduce the Company's
exposure  to  volatility  in  wholesale  energy  market  prices.

     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  from or sell the difference into a marketplace that has
experienced  volatile  energy prices.  Market price trends also may make it more
difficult  to  extend  or  enter  into new power supply contracts at prices that
avoid  the  need  for  rate  relief.  Vermont  does  not  have an automatic fuel
adjustment  clause  or similar mechanism to adjust rates for higher energy costs
without  prior  regulatory  approval.

     The  Company has established a risk management program designed to mitigate
some  of  the potential adverse cash flow and income statement effects caused by
power  supply  risks,  including  credit  risks  associated with counterparties.
Transactions  permitted  by the risk management program include futures, forward
contracts,  option  contracts,  swaps  and  the sale or purchase of 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,  ENVY  and Morgan Stanley, all
currently  have  investment  grade  credit  ratings.

POWER  SUPPLY  DERIVATIVES.
     The Morgan Stanley Contract is used to hedge our power supply costs against
increases  in  fossil  fuel prices.  The Morgan Stanley Contract is a derivative
under  Statement  of  Financial  Accounting  Standards  No.  133  ("SFAS  133").
Management  has  estimated  the  fair  value  of  the future net benefit of this
agreement  at  December  31,  2004  to  be  approximately  $10.7  million.

     The  Company  is unable to predict the price, contract duration or terms of
any  future power supply contract that could replace the Morgan Stanley Contract
after  it  expires  on  December  31,  2006.

     The  Company's  9701  agreement  with  Hydro  Quebec grants Hydro Quebec an
option  to  call  power  at  prices  that are now expected to be below estimated
future wholesale market prices.  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.
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, 2004, Hydro Quebec had purchased 566,000
MWh  under  option  B.  The  Company  expects Hydro Quebec to call its remaining
entitlements  of  approximately  34,000  MWh  under  option  B  during  2005.

     Hydro  Quebec exercised options A and B for 2004, and the Company 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.  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.  The 9701 agreement is a derivative and is effective
through  2015.  Management's  estimate  of the fair value of the future net cost
for  this  agreement  at  December  31, 2004 is approximately $22.8 million.  We
sometimes  use forward contracts to hedge forecasted calls by Hydro Quebec under
the  9701  agreement  and  treat  such  contracts as derivatives under SFAS 133.

     The table below presents assumptions used to estimate the fair value of the
Morgan  Stanley  Contract  and  the  9701  agreement.  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            2.0%      32%-29%  $           62     2006
9701 Arrangement. . . .  Black-Scholes            4.3%      46%-27%  $           66     2015
</TABLE>

The  table  below  presents  the  Company's  estimated 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 $1.5 million.  Actual results may differ materially
from  the  table  illustration.
<TABLE>
<CAPTION>

Commodity Price Risk               December 31, 2004
                         Fair Value(Cost)    Market Risk
                         -----------------  -------------
                          (in thousands)
<S>                      <C>                <C>
Morgan Stanley Contract  $         10,736   $      1,953
9701 agreement. . . . .           (22,821)        (3,487)
                         -----------------  -------------
                         $        (12,085)  $     (1,534)
</TABLE>
Under  an  accounting  order  issued  by  the VPSB, changes in the fair value of
derivatives  are  deferred.  If  a  derivative  instrument were terminated early
because  it  is  probable  that a transaction or forecasted transaction will not
occur,  any  gain  or  loss  would  be  recognized in earnings immediately.  For
derivatives held to maturity, the earnings impact is recorded in the period that
the  derivative  is  sold  or  matures.

OTHER  POWER  SUPPLY  RISK.
     Under  the  VJO  Contract,  Hydro  Quebec  has the right to reduce the load
factor from 75 percent to 65 percent a total of three times over the life of the
contract.  Hydro  Quebec  exercised  the  first of these load reduction options,
effective  for  the year 2003.  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  increased  power  supply  expense  in 2004 by approximately $1.8 million.
Hydro  Quebec  exercised its third and final option in 2004 to reduce deliveries
occurring principally during 2005, resulting in an estimated cost of replacement
power of $1.8 million, based on current wholesale market prices for 2005.  It is
possible  our estimate of future power supply costs could differ materially from
actual  results.  The  Vermont  Joint  Owners, including the Company, retain two
options  to  increase  the load factor to 80 percent from 75 percent after 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.

     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  energy  costs.

     Our  VJO contract contains 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.

     In  accordance  with  guidance  set  forth  in  FASB Interpretation No. 45,
Guarantor's  Accounting  and  Disclosure  Requirements for Guarantees, Including
Indirect  Guarantees  of  Indebtedness  of  Others  ("FIN  45"),  the Company is
required  to  disclose  the  "maximum  potential  amount  of  future  payments
(undiscounted)  the  guarantor  could  be required to make under the guarantee."
Such  disclosure  is required even if the likelihood of triggering the guarantee
is  remote.  In  regards  to  the  "step-up"  provision in the VJO Contract, the
Company  must assume that all members of the VJO simultaneously default in order
to  estimate  the  "maximum  potential"  amount of future payments.  The Company
believes  this  is  a  highly  unlikely  scenario given that the majority of VJO
members  are  regulated  utilities  with  regulated  cost  recovery.  Each  VJO
participant  has  received  regulatory  approval  to  recover  the  cost of this
purchased  power.  Despite the remote chance that such an event could occur, the
Company  estimates  that  its  undiscounted  purchase  obligation  would  be
approximately  $880 million for the remainder of the contract, assuming that all
members  of the VJO defaulted by January 1, 2005 and remained in default for the
duration  of  the  contract.  In such a scenario, the Company would then own the
power  and  could  seek  to  recover  its costs from the defaulting members, its
retail  customers, and/or resell the power in the wholesale power markets in New
England.  The range of outcomes (full cost recovery, potential loss or potential
profit)  would  be  highly  dependent on Vermont regulation and wholesale market
prices  at  the  time.

     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.  During 2003, another unscheduled outage resulted in
the  Company's  deferral  of approximately $500,000 of added power supply costs.
While  the  Vermont  Yankee  plant has had an excellent operating record, future
unscheduled outages could occur at times when replacement energy costs are above
VYNPC  Contract costs.  Historically, the VPSB has allowed the Company to defer,
rather  than  expense,  the higher costs resulting from extraordinary outages at
the  plant.  Since  the Company no longer owns an interest in the Vermont Yankee
nuclear  plant,  we  are  not  responsible for any fixed costs at the plant, the
costs of decommissioning the plant, nor are we responsible for any plant repairs
or  maintenance  costs  during  outages.

     On  June  18,  2004,  a  fire  in  the  electrical  conduits  leading  to a
transformer  outside  the  plant  resulted in a shutdown of the ENVY plant.  The
outage  ended  on  July 7, 2004.  In response to the Company's request, the VPSB
issued  a  final  accounting order allowing the Company to defer its incremental
replacement  power costs during the outage totaling approximately $500,000.  The
order  also  instructs  the  Company  to  apply  any  proceeds  received under a
Ratepayer  Protection Plan ("RPP") to reduce the balance of deferred replacement
power  costs.  ENVY  disputes that the fire was uprate-related.  The Company has
petitioned  the  VPSB  to  resolve  the  dispute.

     The  RPP  was  a part of ENVY's request to uprate or increase the output of
the  VY  nuclear  plant  that  was approved by the VPSB.  Under the RPP, we have
indemnification  rights  to  between  approximately $550,000 and $1.6 million to
recover  uprate-related reductions in output for the three-year period beginning
in  May  2004  and  ending after completion of the uprate (or a maximum of three
years),  depending  on  future  wholesale  energy  market  prices.

     ENVY  has  announced  that,  under  current  operating  parameters, it will
exhaust  the capacity of its existing nuclear waste storage pool in 2007 or 2008
and  will need to store nuclear waste in so-called "dry fuel storage" facilities
to  be  constructed on the site.  Current Vermont law appears to require ENVY to
obtain  approval of the Vermont State legislature, in addition to VPSB approval,
to  construct and use such dry fuel storage facilities.  If ENVY is unsuccessful
in  receiving  favorable legislative action and/or regulatory approval, ENVY has
announced  that  it could be required to shut down the VY plant between 2007 and
2008.  If  the  VY  plant is shut down in 2007 or 2008, we would have to acquire
substitute  baseload power resources, comprising approximately 35 percent of our
load.  At  currently projected market prices, we estimate the annual incremental
cost  (in excess of the projected costs of power under our power supply contract
for  output  from  the  VY facility) would be approximately $9 million per year.
Recovery  of  those  increased  costs  in rates would require a rate increase of
approximately  5  percent.

     In  April  2004,  ENVY reported that two short spent fuel rod segments were
not  in  what  ENVY  believed  to be their documented location in the spent fuel
pool.   After  initial review and visual inspection of the spent fuel pool, ENVY
did  not  locate  the  fuel  rod  segments.  By  letter  dated May 5, 2004, ENVY
notified  VYNPC that based on the terms of the Purchase and Sale Agreement dated
August 1, 2001, and facts at that time, it was ENVY's view that costs associated
with  the  spent  fuel  rod segment inspection effort were the responsibility of
VYNPC.  VYNPC responded that based on the information at that time, there was no
basis  for  ENVY  to  claim  the  inspection  was  VYNPC's  responsibility.
Subsequently,  ENVY discovered the fuel rod segments in a container in the spent
fuel  pool.  We  cannot  predict  the  outcome  of  this  matter  at  this time.

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.  "SFAS 71" 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.

     The  Company  has  recognized  revenues  deferred under previous regulatory
orders to help it earn its allowed rate of return (see "Earnings Summary").  The
Company's  ability  consistently to achieve its allowed rate of return is likely
to  be  more  uncertain  prospectively  due to the absence of available deferred
revenues, unless it secures appropriate and adequate rate increases to cover its
costs  of  operation.

     The  Company  invests in its utility infrastructure to serve its customers.
Obtaining  a  return  on  that  investment  is  a  component  in a rate increase
proceeding that typically lasts for a period of approximately eight and one-half
months.  Uncertainty  regarding  the  outcome of rate proceedings contributes to
the  risk that we will not achieve our allowed rate of return in any given year.

     Regulatory  risk  is  also  affected  by the amount of rate relief that the
Company  needs  to  achieve its allowed rate of return.  Since 2001, the Company
has  not  needed  any  substantial  rate relief.  In August 2002 we extended our
Morgan  Stanley  Contract  before wholesale market power supply prices increased
and we have been able to pass those benefits along to our customers.  Our retail
revenue  needs  through  2006  are  covered  by our 2003 Rate Plan.  The current
Morgan  Stanley Contract expires on December 31, 2006.  We estimate that we will
need  a rate increase of approximately 5 to 6 percent effective January 1, 2007,
driven  primarily by replacement power costs for our Morgan Stanley Contract (if
the  Morgan  Stanley Contract was replaced at current market prices), and higher
projected  transmission  expenses.

     Central Vermont Public Service Corporation ("CVPS") is currently subject to
a rate investigation by the VPSB.  In that case, the DPS has advocated positions
that,  if adopted by the VPSB and applied to the Company, could adversely affect
our  cash  flows  and  operating  results.  Areas  of  risk  include:

*     The  Department's  advocacy  for  an  earnings  cap calculation that would
potentially  subject  all  items  on the balance sheet and income statement to a
retroactive review in order to determine whether the Company has met or exceeded
the earnings cap.  Our 2003 Rate Plan provides that the Company operate under an
earnings cap through 2006.  The Company calculates its earnings under the cap in
a manner that differs from the methodology advocated by the DPS in the CVPS rate
proceeding.

*     DPS  advocacy for elimination or reduction of costs of future removal that
are  currently  embedded  in depreciation rates and reflected in our cash flows.
The  methodology  we currently employ is consistent with that used in most other
regulatory  jurisdictions.

*     DPS  advocacy  for  reduced  rates  of  return  on  equity  for  CVPS.

     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,  2004,  the  Company would write-off its regulatory assets, net of
regulatory  liabilities  (see  above discussion "Critical Accounting Policies").
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

<PAGE>
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.  The
largest  category  of costs that could be subject to the risk of non-recovery in
rates  in  the  event  of  electric  utility restructuring in Vermont ("stranded
costs")  are  those  relating to our 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 $56 million and $96 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  can  be  estimated.

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, 24.1 and 25.7
percent  of the Company's retail MWh sales in 2004, 2003 and 2002, respectively,
and  16.4,  16.6  and 17.3 percent of the Company's retail operating revenues in
2004,  2003 and 2002, 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.

     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  increased  by approximately $350,000 in 2004 compared with
2003.  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 necessitate a
retail  rate  increase  for  all  our  remaining customers of approximately five
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  approximately  $2.2  million  and $3.5 million to its
defined  benefit  plans  during  2004  and  2003, respectively, and we expect to
contribute  between  $2.0  and  $3.0  million  during  2005.

     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.  In 2004, a reduction in the pension plan's discount
rate  was  primarily  responsible  for increasing the OCI charge and related net
liability  by approximately $566,000.  The 2002 and 2004 OCI charge and the 2003
OCI  benefit  had  no  effect  on  net  income.

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  2005.  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, megawatt hour ("MWh")
sales  and  number  of customers for the years ended 2004, 2003 and 2002 were as
follows:
<TABLE>
<CAPTION>


                                              Years ended December 31,
                                      2004                2003        2002
                            -------------------------  ----------  ----------
(dollars in thousands)
<S>                         <C>                        <C>         <C>
 Operating Revenues
     Retail* . . . . . . .  $                 203,218  $  198,717  $  201,052
     Sales for Resale. . .                     22,652      78,901      70,646
     Other . . . . . . . .                      2,946       2,852       2,910
                            -------------------------  ----------  ----------
 Total Operating Revenues.  $                 228,816  $  280,470  $  274,608
                            =========================  ==========  ==========

 MWH Sales-Retail. . . . .                  1,969,925   1,934,340   1,948,190
 MWH Sales for Resale. . .                    411,769   2,287,039   2,107,941
                            -------------------------  ----------  ----------
 Total MWH Sales . . . . .                  2,381,694   4,221,379   4,056,131
                            =========================  ==========  ==========
</TABLE>
*Retail revenues include $3.0 million, $1.1 million and $4.5 million of deferred
revenue  recognized  for  2004,  2003,  and  2002,  respectively.
 Comparative  changes  in  operating  revenues  are  summarized  below:


<TABLE>
<CAPTION>

 Average  Number  of  Customers
                             Years ended December 31,
                                2004    2003    2002
                               ------  ------  ------
<S>                            <C>     <C>     <C>
    Residential . . . . . . .  75,507  74,693  73,861
    Commercial and Industrial  13,539  13,369  13,194
    Other . . . . . . . . . .      62      65      65
                               ------  ------  ------
 Total Number of Customers. .  89,108  88,127  87,120
                               ======  ======  ======
</TABLE>
<TABLE>
<CAPTION>

       Change in Operating Revenues      2003 to      2002 to      2001 to

                                                 2004          2003      2002
                                            ---------------  --------  ---------
                                             (In thousands)
<S>                                         <C>              <C>       <C>
 Retail Rates. . . . . . . . . . . . . . .  $          830   $  (912)  $  6,471
 Retail Sales Volume . . . . . . . . . . .           3,671    (1,423)      (512)
 Resales and Other Revenues. . . . . . . .         (56,155)    8,197    (14,815)
                                            ---------------  --------  ---------
 Increase (Decrease) in Operating Revenues  $      (51,654)  $ 5,862   $ (8,856)
                                            ===============  ========  =========
</TABLE>




 Nearly  all  of the Company's earnings from continuing operations are typically
generated  by  retail  sales of electricity.  In 2004, retail revenues increased
$4.5  million  or  2.3  percent  compared  with  2003,  due  to

     An  increase  of $1.9 million in recognition of revenues deferred under the
2003  Rate  Plan;
     A  3.3  percent  increase  in  megawatt  hour sales to large commercial and
industrial  customers  resulting  in  a  $1.4  million  increase in revenue; and
     A  2.0  percent  increase  in  megawatt  hour sales to small commercial and
industrial  customers  resulting  in  a  $1.0  million  increase  in  revenue.

     Residential  retail revenues and megawatt hour sales of electricity were up
only  0.1  percent  in  2004,  compared  with  2003.  We experienced residential
customer  growth  in  2004,  but 2004 weather conditions were less favorable for
electricity  sales  than  2003.

     Wholesale  revenues  decreased  in  2004 by $56.2 million, or 71.3 percent,
compared  with  2003,  reflecting  reduced sales of electricity under the Morgan
Stanley  Contract.  The reduction in sales under the Morgan Stanley Contract did
not  adversely  affect  the  Company's  earnings  in 2004 and is not expected to
adversely  affect  the  Company's  earnings  in  future  years.

     In  2003, total electricity sales increased 4.1 percent compared with 2002,
due  to  increased wholesale sales and sales to residential and small commercial
and  industrial  customers,  partially  offset  by  decreased  sales  to  large
commercial  and  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  agreement;
     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  $4.5  million  recognized  in  2002;  and
     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.

POWER  SUPPLY  EXPENSES  - Power supply expenses constituted 67.5, 74.4 and 74.5
percent  of  total  operating  expenses  for  the  years  2004,  2003  and 2002,
respectively.  The  decreased  2004  percentage  reflects  reduced purchases and
sales  of  electricity  under  the  Morgan  Stanley  Contract.

     Power  supply  expenses  decreased by $53.3 million or 27.0 percent in 2004
when  compared  with  2003,  and  resulted  from  the  following:

     An  estimated  $56.2  million  decrease  in the cost of power purchased for
resale resulting primarily from the restructuring of the Morgan Stanley Contract
described  above;
     A  $1.8  million  increase  in  credits from the ISO New England ("ISO-NE")
resulting from FTR auctions designed to make congested regions pay a premium for
energy  delivery,  and  credits  for  certain  Company  generation;  and
     A  $1.3  million  decrease in the net cost of our 9701 agreement with Hydro
Quebec.
     These  decreases  were  partially offset by increased power supply expenses
from  the  following:
     A  $1.9  million  increase  in  purchases to supply increased retail sales;
     An estimated $1.5 million in purchases to replace reduced energy deliveries
under  the  VJO  Contract  as  a  result  of  problems  with  the  transmission
interconnection  facilities  over  which  we  schedule  deliveries;  and
     An $851,000 increase in the contract price per megawatt hour of electricity
purchased  under  the  Morgan  Stanley  Contract.

     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.

OTHER  OPERATING  EXPENSES  -  Other operating expenses in 2004 were essentially
unchanged  from  the  prior  year.

     Other  operating  expenses increased $3.7 million, or 26.6 percent, in 2003
compared  with  2002  primarily  due  to increased employee benefit expenses and
expenses  related  to  corporate  governance.

TRANSMISSION  EXPENSES  -  Transmission  expenses  increased  $873,000,  or  5.9
percent,  in  2004  compared  with  2003,  due to increased charges allocated by
ISO-NE  for  system  support in the greater Boston area and expensed engineering
studies  related  to  substation  and  transmission  design  evaluations.  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.

     In  2004,  we  experienced  an  increase  of  approximately  $750,000  in
transmission  expense  resulting from system-wide allocation of costs associated
with  voltage control and reactive power ("VAR") in the greater Boston area.  We
expect this increased transmission expense to continue in 2005.  The Company and
other  affected  load  serving  entities  have  requested  ISO-NE  to modify the
applicable market rules to allocate VAR-related costs to the reliability regions
responsible  for  the  applicable  VAR-related  costs.

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

     ISO-NE  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.

     ISO-NE  implemented  its  Standard  Market  Design  ("SMD")  plan governing
wholesale  energy  sales in New England 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  could  eventually be determined on a more localized ("nodal")
basis.  In  December  2004,  FERC  reaffirmed  the  zone  pricing system for New
England's SMD, subject to FERC's periodic re-analysis of alternative load zones,
based  on  changes  in  system  conditions.  We believe that nodal pricing could
result  in  a  material  adverse  impact on our power supply and/or transmission
costs,  if  adopted.

     FERC  has  granted  approval  to  ISO-NE  to become a regional transmission
organization  ("RTO")  for  New  England.  On February 1, 2005, ISO-NE commenced
operations  as  the RTO, providing regional transmission service in New England,
with  operational  control  of  the  bulk  power  system  and responsibility for
administering  wholesale  markets.  Commencing  with  implementation of the RTO,
costs  associated  with  certain  transmission facilities, known as the Highgate
Facilities,  of  which  the  Company  is  a  part  owner,  will  be  phased into
region-wide  rates over a 5-year period.  When fully phased in, we estimate that
this  "roll-in"  of  the  Highgate  facilities  will  achieve approximately $1.4
million  in  annual  transmission  costs  savings  for  the  Company.

     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.  In  January  2005,  the project received
regulatory  approval  from  the  VPSB.  The  project  is  estimated  to  cost
approximately  $150 million through 2007.  VELCO intends to finance the costs of
constructing  the Northwest Reliability Project in part through increased equity
investment.  In  October  2004,  the  Company  invested $4.6 million in VELCO to
support  this  project  and  other  transmission projects.  The Company plans to
invest  at  least  $15  million  additionally in VELCO through 2007 for the same
purpose.  Under  current NEPOOL and ISO-NE rules, which require qualifying large
transmission  project  costs  to  be  shared  among  all  New England utilities,
approximately  95  percent  of  the  pool  transmission  facility  costs  of the
Northwest  Reliability  Project  will  be  allocated  throughout the New England
region,  with  Vermont  utilities  responsible  for  approximately  5 percent of
allocated  costs.  Vermont  utilities  are  required  to  pay  5 percent of pool
transmission  facility  upgrades  in  other  New  England  states.

MAINTENANCE  EXPENSES  - Maintenance expenses increased $25,000, or 0.2 percent,
in  2004  compared  with  2003  due  to  increased  expenditures on right-of-way
maintenance  programs  offset  by  decreased expenditures related to gas turbine
maintenance.

     Maintenance  expenses  decreased $151,000, or 1.5 percent, in 2003 compared
with 2002, due to decreased expenditures related to maintenance of our Searsburg
wind  generation  facility.

DEPRECIATION  AND AMORTIZATION - Depreciation and amortization expense increased
$129,000,  or  0.9  percent,  in  2004  compared  with  2003 due to increases in
depreciation  of  utility  plant  in  service  partially  offset  by  decreased
amortization  of  software  costs.

     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.

TAXES  OTHER  THAN INCOME - Taxes other than income taxes decreased $210,000, or
3.0  percent,  in 2004 compared with 2003 due to decreased property tax expense.

     Taxes  other  than  income taxes decreased $45,000, or 0.6 percent, in 2003
compared  with  2002  for  the  same  reason.

INCOME TAXES - Income tax expense increased $642,000, or 12.5 percent, primarily
due  to  an  increase  in  pre-tax  income  in  2004  compared  with  2003.

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

OTHER  INCOME  AND  DEDUCTIONS - Other income and deductions increased $8,000 in
2004 compared with 2003 due primarily to sales of non-utility property offset by
reduced  earnings  on  investment  in  Vermont  Yankee.

     Other  income  decreased  $406,000,  or 16.3 percent, in 2003 compared with
2002  due  primarily  to  VYNPC  recognition  of  deferred tax assets arising in
conjunction  with  the  sale of the Vermont Yankee plant and reduced earnings on
investment in VYNPC as a result of the sale of the Vermont Yankee plant in 2002.

INTEREST  EXPENSE - Interest expense decreased $551,000, or 7.8 percent, in 2004
compared  with  2003 primarily due to scheduled redemptions of long-term debt in
December  2003.

     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.

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.

     The  Company joined the Chicago Climate Exchange ("CCX"), a self-regulatory
exchange  that  administers  a  market  for  reducing and trading greenhouse gas
emission  credits.  We  are  the first utility in the northeast to join the CCX,
and  have  committed  voluntarily to reduce our emissions by 4 percent below our
1998  - 2001 baseline average by 2006, either directly or by purchasing credits.

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
2004  and  2003,  the  Company  expended $1.5 and $2.6 million, respectively, 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
$6.5  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 $13.3 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  by  the  Company  and the DPS.  The 2003 Rate Plan covers the
period  from  2003  through  2006 and includes the following principal elements:
     The  Company's  rates  remained 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.  We  submitted a cost of service schedule supporting the 1.9 percent rate
increase for 2005 in accordance with the plan.  The increase became effective on
January  1,  2005  in accordance with the plan. If the Company's cost of service
filing  in  2006  established  that  a rate increase of less than 0.9 percent is
required  for  the  Company  to meet its revenue requirements, the Company would
implement  the lesser rate increase.  The VPSB retains the discretion to open an
investigation of the Company's rates at any time, at the request of the DPS, the
request of ratepayers, or on its own volition.  Certain ratepayers requested the
VPSB  to open such an investigation in connection with the Company's 1.9 percent
rate  increase  for  2005.  The  VPSB  granted the request in December 2004, and
then,  at  our request, closed and terminated its investigation in January 2005,
with  no  adverse  impact  on  the  Company's  rates.
     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 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.  The
Company  did not experience excess earnings in 2004.  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  carried  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  were  applied in 2004 to offset increased
costs.
     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  filed  with  the  VPSB  in 2004 a new fully-allocated cost of
service  study  and  rate  re-design,  which  allocates  the  Company's  revenue
requirement  among  all customer classes on the basis of current costs.  The new
rate  design is 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 was restricted
until new rates went into effect, which occurred in January 2005.  Although this
restriction  has  expired,  we  have  no  plans  to make material investments in
non-utility  operations.

LIQUIDITY  AND  CAPITAL  RESOURCES
----------------------------------
     Our  cash, net working capital and net operating cash flows are as follows:
<TABLE>
<CAPTION>
                                           At December 31,
                                             2004     2003
                                            -------  -------
(In thousands)
<S>                                         <C>      <C>
Cash and cash equivalents. . . . . . . . .  $ 1,720  $   786
                                            -------  -------
Current assets . . . . . . . . . . . . . .  $35,462  $31,688
Less current liabilities . . . . . . . . .   24,468   22,715
                                            -------  -------
Net working capital. . . . . . . . . . . .  $10,994  $ 8,973

Net cash provided by operating activities.  $26,162  $21,070
</TABLE>
We  expect most of our construction expenditures and dividends to be financed by
net  cash  provided  by  operating activities.  We anticipate that we will issue
long-term debt of approximately $25 million in 2006 for scheduled first mortgage
bond  redemptions  of  $14 million and to refinance accumulated short-term debt.
Material  risks  to  cash  flow  from  operations  include  regulatory risk, our
customer  concentration  risk  with  IBM,  slower  than anticipated load growth,
unfavorable  economic  conditions  and  increases  in  net  power  costs.

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,  including $4.6 million invested during 2004.  Our planned
investments  will  fund  in  part an increase in the amount of equity in VELCO's
capital  structure  and increased investment, principally driven by construction
of  the  Northwest  Reliability Project and other Vermont construction projects.
See  detailed  discussion  under  "Transmission  Expenses."

     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 over the past three
years  and  forecasted  for  2005  are  as  follows:
<TABLE>
<CAPTION>


                Generation   Transmission   Distribution   Other*    Total
                -----------  -------------  -------------  -------  -------
(In thousands)
Actual:
--------------
<S>             <C>          <C>            <C>            <C>      <C>
2002 . . . . .  $     3,258  $       1,827  $       9,173  $ 7,479  $21,737
2003 . . . . .        2,629          1,496          7,760    6,622   18,507
2004 . . . . .        3,053          2,898         10,908    5,005   21,864
Forecast:
--------------
2005 . . . . .  $     3,264  $       3,234  $      10,156  $ 6,122  $22,776
</TABLE>

*  Other  includes  Pine Street Barge Canal net expenditures of  $1.8 million in
2002,  $2.5  million  in 2003, $1.2 million in 2004 and an estimated $750,000 in
2005.

DIVIDEND  POLICY  - On February 14, 2005, the annual dividend rate was increased
from  $0.88  per  share  to  $1.00 per share, a payout ratio of approximately 48
percent based on 2004 earnings from continuing operations.  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 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.  The  Company  expects  to  increase  the  dividend in the first
quarter  of  each  year  until  the payout ratio falls in the middle of a payout
range  of  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.

FINANCING  AND  CAPITALIZATION
------------------------------
     During  June  2004,  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 $30.0
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 $3.0 million
outstanding  on the Fleet-Sovereign Agreement at December 31, 2004 at an average
rate  of  5.25 percent.  There was no non-utility short-term debt outstanding at
December  31, 2004 or 2003. The Fleet-Sovereign Agreement expires June 15, 2005.
The  Company anticipates that it will secure financing that replaces some or all
of  its  expiring  facilities  during  2005.

     During  2002, we redeemed $5.1 million of 10.0 percent first mortgage bonds
and  $12.5  million  of  outstanding  preferred  stock.

     In  2002,  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.
     The  credit  ratings  of the Company's first mortgage bonds at December 31,
2004  were:

<TABLE>
<CAPTION>


                       Moody's             Standard & Poor's
                       --------------------  -----------------
<S>                   <C>                <C>
First mortgage bonds  Baa1               BBB
</TABLE>
On  June  18,  2004  Moody's affirmed the Company' senior secured debt rating at
Baa1,  with  a stable outlook.  On November 3, 2004, Standard and Poor's Ratings
Services upgraded the Company's issuer credit rating to BBB from BBB-, citing an
improved  regulatory  climate  in  Vermont. Standard and Poor's Ratings Services
also 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 either of the credit
rating  agencies  listed  above.

     The  following  table  presents  a  summary of certain material contractual
obligations  existing  as  of  December  31,  2004.
<TABLE>
<CAPTION>

                                                      Payments Due by Period
                                                      ----------------------
           At December 31, 2004                            2006 and  2008 and    After
                                        TOTAL      2005       2007      2009      2009
------------------------------------  ----------  --------  --------  --------
(In thousands)
<S>                                   <C>         <C>       <C>       <C>       <C>
Long-term debt . . . . . . . . . . .  $   93,000  $      -  $ 14,000  $      -  $ 79,000
Interest on long-term debt . . . . .      70,170     6,534    12,068    11,068    40,500
Capital lease obligations. . . . . .       4,516       572       879       766     2,299
Hydro-Quebec power supply contracts.     574,044    50,960   100,986   102,723   319,375
Morgan Stanley Contract. . . . . . .      22,718    12,561    10,157         -         -
Independent Power Producers. . . . .     183,217    15,905    33,923    32,808   100,581
Stony Brook contract . . . . . . . .      46,808     2,876     6,024     6,506    31,402
VYNPC PPA. . . . . . . . . . . . . .     255,588    33,047    68,090    71,590    82,861
                                      ----------  --------  --------  --------  --------
    Total. . . . . . . . . . . . . .  $1,250,061  $122,455  $246,127  $225,461  $656,018
                                      ==========  ========  ========  ========  ========
</TABLE>


See  the  captions  "Power  Supply Expense" and "Power Contract Commitments" for
additional information about the Hydro-Quebec and MS power supply contracts

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 pay a portion of VELCO's
operating  costs,  including  its  debt  service  costs.

OTHER  RISKS  -  The  Town  of  Rockingham, Vermont, located in the southeastern
portion  of  our  service  territory,  has  exercised  an  option  to purchase a
hydro-electric  facility  partially  located  in  the  town  (the "Bellows Falls
facility").  If  Rockingham  or  its  assignee  is  successful  in arranging for
purchase  of  the  Bellows Falls facility, we expect to conclude an agreement to
permit  Rockingham  to  be  responsible for its own power supply needs, with the
Company  providing  distribution  and  other  services to the town.  In any such
agreement  the  Company  would continue to own its distribution plant located in
the  town  and  receive  distribution  services revenues sufficient to cover all
costs of providing services and all stranded costs associated with the Company's
present  obligation  to  provide  integrated  electric  service  to customers in
Rockingham.  Such  an  arrangement  would  require  VPSB  approval.  The Company
receives  annual  revenues  of  approximately  $3  million from its customers in
Rockingham.

     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
received  VPSB  approval  for,  and has made additional dam improvements, at the
facility.  The  VPSB has pending a regulatory proceeding to determine whether to
impose  regulatory  penalties  in  connection  with  the  1995 dam improvements.

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                                         44
    For  the  Years  Ended  December  31,  2004,  2003,  and  2002

Consolidated  Statements  of  Cash  Flows For the                             45
    Years  Ended  December  31,  2004,  2003,  and  2002

Consolidated  Balance  Sheets  as  of                                         46
    December  31,  2004  and  2003


Consolidated  Statements  of  Changes  In Shareholders Equity                 48
     And  Comprehensive  Income  For  the  Years  Ended  December  31,
      2004,  2003,  and  2002

Notes  to  Consolidated  Financial  Statements                                49

Quarterly  Financial  Information  (Unaudited)                               79


Consent  and  Reports  of  Independent Registered Public Accounting Firm      80

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
                                                                2004       2003       2002
                                                              ---------  ---------  ---------
(In thousands, except per share data)
<S>                                                           <C>        <C>        <C>
Retail and other revenues. . . . . . . . . . . . . . . . . .  $206,164   $201,569   $203,962
Wholesale revenues . . . . . . . . . . . . . . . . . . . . .    22,652     78,901     70,646
                                                              ---------  ---------  ---------
TOTAL OPERATING REVENUES . . . . . . . . . . . . . . . . . .   228,816    280,470    274,608
Operating expenses-Power Supply:
  Purchases from others. . . . . . . . . . . . . . . . . . .   137,503    189,450    188,381
  Company-owned generation . . . . . . . . . . . . . . . . .     6,516      7,856      5,067
Other operating. . . . . . . . . . . . . . . . . . . . . . .    17,537     17,534     13,851
Transmission . . . . . . . . . . . . . . . . . . . . . . . .    15,656     14,783     15,221
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . .     9,746      9,721      9,872
Depreciation and amortization. . . . . . . . . . . . . . . .    13,931     13,803     14,151
Taxes other than income. . . . . . . . . . . . . . . . . . .     6,687      6,897      6,942
Income taxes . . . . . . . . . . . . . . . . . . . . . . . .     5,762      5,120      6,043
                                                              ---------  ---------  ---------
    Total operating expenses . . . . . . . . . . . . . . . .   213,338    265,164    259,528
                                                              ---------  ---------  ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . .    15,478     15,306     15,080
                                                              ---------  ---------  ---------

OTHER INCOME
Equity in earnings of affiliates and non-utility operations.     1,232      1,493      2,777
Allowance for equity funds used during construction. . . . .       449        387        233
                                                              ---------
Other income . . . . . . . . . . . . . . . . . . . . . . . .       714        409        393
                                                              ---------
Other deductions . . . . . . . . . . . . . . . . . . . . . .      (308)      (210)      (918)
                                                              ---------  ---------  ---------
    Total other income . . . . . . . . . . . . . . . . . . .     2,087      2,079      2,485
                                                              ---------  ---------  ---------

INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . .     6,534      7,021      5,214
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . .       257        303      1,059
Allowance for borrowed funds used during construction. . . .      (285)      (267)      (103)
                                                              ---------  ---------  ---------
    Total interest charges . . . . . . . . . . . . . . . . .     6,506      7,057      6,170
                                                              ---------  ---------  ---------
INCOME FROM CONTINUING OPERATIONS
BEFORE PREFERRED DIVIDENDS . . . . . . . . . . . . . . . . .    11,059     10,328     11,395
Dividends on preferred stock . . . . . . . . . . . . . . . .         -          3         96
                                                              ---------  ---------  ---------
INCOME FROM CONTINUING OPERATIONS. . . . . . . . . . . . . .    11,059     10,325     11,299
Income from discontinued operations, net . . . . . . . . . .       525         79         99
                                                              ---------  ---------  ---------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . .  $ 11,584   $ 10,404   $ 11,398
                                                              =========  =========  =========
EARNINGS PER SHARE
Basic earnings per share from continuing operations. . . . .  $   2.18   $   2.08   $   2.02
Basic earnings per share from discontinued operations. . . .      0.10       0.01       0.02
                                                              ---------  ---------  ---------
Basic earnings per share . . . . . . . . . . . . . . . . . .  $   2.28   $   2.09   $   2.04
                                                              =========  =========  =========
Diluted earnings per share from continuing operations. . . .  $   2.10   $   2.01   $   1.96
Diluted earnings per share from discontinued operations. . .      0.10       0.01       0.02
                                                              ---------  ---------  ---------
Diluted earnings per share . . . . . . . . . . . . . . . . .  $   2.20   $   2.02   $   1.98
                                                              =========  =========  =========
Weighted average shares outstanding-basic. . . . . . . . . .     5,083      4,980      5,592
Weighted average equivalent shares outstanding-diluted . . .     5,254      5,140      5,756
</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
                                                                                       -----------
                                                                             2004          2003       2002
                                                                        ---------------  ---------  ---------
OPERATING ACTIVITIES                                                    (in thousands)
<S>                                                                     <C>              <C>        <C>
Income from continuing operations before preferred dividends . . . . .  $       11,059   $ 10,328   $ 11,395
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . .          13,931     13,803     14,151
Dividends from associated companies. . . . . . . . . . . . . . . . . .             863      2,081      2,400
Equity in undistributed earnings of associated companies . . . . . . .            (880)    (1,197)    (2,355)
Allowance for funds used during construction . . . . . . . . . . . . .            (733)      (654)      (335)
Amortization of deferred purchased power costs . . . . . . . . . . . .             318        318      3,236
Deferred income tax expense, net of investment tax credit amortization           3,699      1,479      3,577
Deferred purchased power costs . . . . . . . . . . . . . . . . . . . .            (667)      (570)    (2,003)
Rate levelization liability. . . . . . . . . . . . . . . . . . . . . .          (2,970)    (1,121)    (4,483)
Environmental and conservation deferrals, net. . . . . . . . . . . . .          (1,041)    (1,890)    (2,194)
Cash in advance of construction. . . . . . . . . . . . . . . . . . . .           2,246      1,222      1,690
Gain on sale of property . . . . . . . . . . . . . . . . . . . . . . .            (402)         -          -
Share-based compensation . . . . . . . . . . . . . . . . . . . . . . .           1,244          -          -
Changes in:
Accounts receivable and accrued utility revenues . . . . . . . . . . .          (1,120)      (189)      (896)
Prepayments, fuel and other current assets . . . . . . . . . . . . . .            (418)    (1,188)       850
Accounts payable and other current liabilities . . . . . . . . . . . .           1,567       (676)       (55)
Income taxes payable and receivable. . . . . . . . . . . . . . . . . .          (2,069)    (2,183)     3,863
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           1,009      1,428       (232)
                                                                        ---------------  ---------  ---------
Net cash provided by continuing operations . . . . . . . . . . . . . .          25,637     20,991     28,609
Net income from discontinued operations. . . . . . . . . . . . . . . .             525         79         99
                                                                        ---------------  ---------  ---------
Net cash provided by operating activities. . . . . . . . . . . . . . .          26,162     21,070     28,708
                                                                        ---------------  ---------  ---------

INVESTING ACTIVITIES
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . .         (20,823)   (16,617)   (19,543)
Restriction of cash for renewable energy investments . . . . . . . . .            (354)         -          -
Proceeds from sale of property . . . . . . . . . . . . . . . . . . . .             648          -          -
Investment in associated companies . . . . . . . . . . . . . . . . . .          (4,579)      (108)      (392)
Return of capital from associated companies. . . . . . . . . . . . . .             314      7,615        370
Investment in nonutility property. . . . . . . . . . . . . . . . . . .            (338)      (198)      (206)
                                                                        ---------------  ---------  ---------
Net cash used in investing activities. . . . . . . . . . . . . . . . .         (25,132)    (9,308)   (19,771)
                                                                        ---------------  ---------  ---------
FINANCING ACTIVITIES
Proceeds from issuance of long-term debt . . . . . . . . . . . . . . .               -          -     42,000
Repurchase of preferred stock. . . . . . . . . . . . . . . . . . . . .               -        (85)   (12,536)
Payments to acquire treasury stock . . . . . . . . . . . . . . . . . .               -         (3)   (16,320)
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . .           1,885        995      1,037
Reduction in long-term debt and term loan. . . . . . . . . . . . . . .               -     (8,000)   (25,322)
Short-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . .           2,500     (2,000)     2,500
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . .          (4,481)    (3,792)    (3,393)
                                                                        ---------------  ---------  ---------

Net cash provided by (used in) financing activities. . . . . . . . . .             (96)   (12,885)   (12,034)
                                                                        ---------------  ---------  ---------
Net increase in cash and cash equivalents. . . . . . . . . . . . . . .             934     (1,123)    (3,097)

Cash and cash equivalents at beginning of period . . . . . . . . . . .             786      1,909      5,006
                                                                        ---------------  ---------  ---------
blank
Cash and cash equivalents at end of period . . . . . . . . . . . . . .  $        1,720   $    786   $  1,909
                                                                        ===============  =========  =========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for:
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $        6,691   $  7,120   $  6,048
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           3,043      2,915      2,349
</TABLE>

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

<TABLE>
<CAPTION>

GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                                      December 31
                                                     2004      2003
                                                   --------  --------
(in thousands)
<S>                                                <C>       <C>
ASSETS
UTILITY PLANT
  Utility plant, at original cost . . . . . . . .  $339,269  $324,900
  Less accumulated depreciation . . . . . . . . .   119,633   110,111
                                                   --------  --------
  Utility plant, net of accumulated depreciation.   219,636   214,789
  Property under capital lease. . . . . . . . . .     4,731     5,047
  Construction work in progress . . . . . . . . .     8,345     9,026
                                                   --------  --------
  Total utility plant, net. . . . . . . . . . . .   232,712   228,862
                                                   --------  --------
OTHER INVESTMENTS
  Associated companies, at equity . . . . . . . .    10,179     5,896
  Other investments . . . . . . . . . . . . . . .     8,780     7,810
                                                   --------  --------
  Total other investments . . . . . . . . . . . .    18,959    13,706
                                                   --------  --------
CURRENT ASSETS
  Cash and cash equivalents . . . . . . . . . . .     1,720       786
  Accounts receivable, less allowance for
  doubtful accounts of $620 and $690. . . . . . .    18,216    17,331
  Accrued utility revenues. . . . . . . . . . . .     6,964     6,729
  Fuel, materials and supplies, average cost. . .     4,848     4,498
  Prepayments . . . . . . . . . . . . . . . . . .     1,674     1,922
  Income tax receivable . . . . . . . . . . . . .     1,717       422
  Other . . . . . . . . . . . . . . . . . . . . .       323         -
                                                   --------  --------
  Total current assets. . . . . . . . . . . . . .    35,462    31,688
                                                   --------  --------
DEFERRED CHARGES
  Demand side management programs . . . . . . . .     7,293     6,713
  Purchased power costs . . . . . . . . . . . . .     2,322     2,574
  Pine Street Barge Canal . . . . . . . . . . . .    13,250    12,954
  Net power supply deferral . . . . . . . . . . .    12,085    19,734
  Power supply derivative asset . . . . . . . . .    10,736     3,990
  Other regulatory assets . . . . . . . . . . . .     6,932     8,439
  Other deferred charges. . . . . . . . . . . . .     1,113     1,186
                                                   --------  --------
  Total deferred charges. . . . . . . . . . . . .    53,731    55,590
                                                   --------  --------
NON-UTILITY
  Other current assets. . . . . . . . . . . . . .         -       217
  Property and equipment. . . . . . . . . . . . .       247       248
  Other assets. . . . . . . . . . . . . . . . . .       508       640
                                                   --------  --------
  Total non-utility assets. . . . . . . . . . . .       755     1,105
                                                   --------  --------

TOTAL ASSETS. . . . . . . . . . . . . . . . . . .  $341,619  $330,951
                                                   ========  ========
</TABLE>


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

<TABLE>
<CAPTION>

GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                                       December 31
                                                    2004       2003
                                                  ---------  ---------
(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
5,968,118 and 5,860,854) . . . . . . . . . . . .  $ 19,894   $ 19,536
Additional paid-in capital . . . . . . . . . . .    78,852     76,081
Retained earnings. . . . . . . . . . . . . . . .    29,889     22,786
Accumulated other comprehensive income . . . . .    (2,353)    (1,787)
Treasury stock, at cost (827,639 shares) . . . .   (16,701)   (16,701)
                                                  ---------  ---------
Total common stock equity. . . . . . . . . . . .   109,581     99,915
Long-term debt, less current maturities. . . . .    93,000     93,000
                                                  ---------  ---------
Total capitalization . . . . . . . . . . . . . .   202,581    192,915
                                                  ---------  ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . .     4,493      4,963
                                                  ---------  ---------
CURRENT LIABILITIES
Short-term debt. . . . . . . . . . . . . . . . .     3,000        500
Accounts payable, trade and accrued liabilities.     9,437      8,493
Accounts payable to associated companies . . . .     7,391      6,821
Rate levelization liability. . . . . . . . . . .         -      2,970
Accrued taxes. . . . . . . . . . . . . . . . . .     1,290        633
Customer deposits. . . . . . . . . . . . . . . .     1,063        968
Interest accrued . . . . . . . . . . . . . . . .     1,136      1,152
Other. . . . . . . . . . . . . . . . . . . . . .     1,151      1,178
                                                  ---------  ---------
Total current liabilities. . . . . . . . . . . .    24,468     22,715
                                                  ---------  ---------
DEFERRED CREDITS
Power supply derivative liability. . . . . . . .    22,821     23,724
Accumulated deferred income taxes. . . . . . . .    32,223     30,000
Unamortized investment tax credits . . . . . . .     2,564      2,848
Pine Street Barge Canal cleanup liability. . . .     6,458      7,356
Accumulated cost of removal. . . . . . . . . . .    19,806     21,238
Deferred compensation. . . . . . . . . . . . . .     8,872      8,936
Other regulatory liabilities . . . . . . . . . .     4,012      2,643
Other deferred liabilities . . . . . . . . . . .    11,150     11,536
                                                  ---------  ---------
Total deferred credits . . . . . . . . . . . . .   107,906    108,281
                                                  ---------  ---------
COMMITMENTS AND CONTINGENCIES, NOTE 3
NON-UTILITY
Net liabilities of discontinued segment. . . . .     2,171      2,077
                                                  ---------  ---------
Total non-utility liabilities. . . . . . . . . .     2,171      2,077
                                                  ---------  ---------

TOTAL CAPITALIZATION AND LIABILITIES . . . . . .  $341,619   $330,951
                                                  =========  =========

</TABLE>


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

          CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY             ACCUMULATED
                       AND COMPREHENSIVE INCOME                                      OTHER               TOTAL
                                            COMMON STOCK     PAID-IN    RETAINED COMPREHENSIVE TREASURY  COMMON
                                            ------------
                                           SHARES    AMOUNT   CAPITAL    EARNINGS    INCOME     STOCK     EQUITY
                                         ----------  -------  --------  ----------  --------  ---------  ---------
(In thousands except share data)
<S>                                      <C>         <C>      <C>       <C>         <C>       <C>        <C>
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
Income before preferred dividends . . .          -         -         -     11,494         -          -     11,494
Other comprehensive income(loss). . . .          -         -         -          -    (2,374)         -     (2,374)
Common stock dividends-$0.60 per share.          -         -         -     (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)
Income before preferred dividends . . .          -         -         -     10,407         -          -     10,407
Other comprehensive income(loss). . . .          -         -         -          -       587          -        587
Common stock dividends-$0.76 per share.          -         -         -     (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
                                         ----------  -------  --------  ----------  --------  ---------  ---------
Common stock issuance:
Compensation programs . . . . . . . . .    107,264       358     2,771          -         -          -      3,129
Net income. . . . . . . . . . . . . . .          -         -         -     11,584         -          -     11,584
Other comprehensive income(loss). . . .          -         -         -          -      (566)         -       (566)
Common stock dividends-$0.88 per share.          -         -         -     (4,481)        -          -     (4,481)
                                         ----------  -------  --------  ----------  --------  ---------  ---------
BALANCE, DECEMBER 31, 2004. . . . . . .  5,140,479   $19,894  $ 78,852  $  29,889   $(2,353)  $(16,701)  $109,581
                                         ----------  -------  --------  ----------  --------  ---------  ---------
</TABLE>
The  accompanying  notes  are  an  integral  part  of the consolidated financial
statements.

<TABLE>
<CAPTION>

       CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME           For the years ended December 31,
                                                                 --------------------------------
                                                                        2004     2003      2002
                                                                      --------  -------  --------
In thousands
<S>                                                                   <C>       <C>      <C>
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $11,584   $10,404  $11,398
Minimum pension liability adjustment, net of applicable income taxes     (566)      587   (2,374)
of $391 benefit, $400 expense and $1.6 million benefit, respectively                           -
                                                                      --------
         Other comprehensive income. . . . . . . . . . . . . . . . .  $11,018   $10,991  $ 9,024
                                                                      ========  =======  ========
</TABLE>


The  accompanying  notes  are  an  integral  part  of the consolidated financial
statements.
NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS

A.  SIGNIFICANT  ACCOUNTING  POLICIES

ORGANIZATION  AND  BASIS OF PRESENTATION.  Green Mountain Power Corporation (the
"Company") is an investor-owned electric utility that transmits, distributes and
sells  electricity and utility construction services 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  electricity  to approximately 90,000 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  "VYNPC").

     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  section of the
Consolidated  Statements  of  Income.  Summarized  financial information for GMP
Real Estate Corporation and the Company's unregulated water heater program is as
follows:
<TABLE>
<CAPTION>
           Years ended December 31,
              2004    2003   2001
              -----  ------  -----
In thousands
<S>           <C>    <C>     <C>
Revenue. . .  $ 961  $1,087  $ 997
Expense. . .    594     704    744
              -----  ------  -----
Net Income .  $ 367  $  253  $ 263
              =====  ======  =====
</TABLE>
The  Company  accounts  for  its  investments  in  VYNPC, 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  for  additional  information.

     The  Company's  interests  in  jointly-owned  generating  and  transmission
facilities  are  accounted for on a pro-rata basis using the Company's ownership
percentages  and are recorded in the Company's Consolidated Balance Sheets.  The
Company's  share  of  operating expenses for these facilities is included in the
corresponding  operating  accounts  on  the  Consolidated  Statements of Income.

USE OF ESTIMATES.  In preparing the Financial Statements, management is required
to make estimates and assumptions that affect the reported amounts of assets and
liabilities  and  disclosure  of contingent assets and contingent liabilities at
the  date  of the Financial Statements, and the reported amounts of revenues and
expenses  during  the  reporting  period.  Changes  to  these  assumptions  and
estimates  could  have  a  material affect on the Company's Financial Statements
particularly  as  they  relate  to  unbilled  revenue,  pension  expense  and
contingencies.  However, the Company believes it has taken reasonable positions,
where assumptions and estimates are used, in order to minimize the impact to the
Company  that  could  result  if  actual  results  vary from the assumptions and
estimates.  In  management's  opinion,  the  areas of the Company where the most
significant  judgment  is  exercised  is  in  the valuation of unbilled revenue,
pension plan assumptions, contingency reserves, accumulated removal obligations,
regulatory  assets  and  liabilities,  the  allowance for uncollectible accounts
receivable  and  derivative  valuation.

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.
Incurred costs are deferred as regulatory assets when the Company concludes that
future  revenue  will  be provided to permit recovery of the previously incurred
cost.  The  Company  analyzes evidence supporting deferral, including provisions
for  recovery  in regulatory orders, past regulatory precedent, other regulatory
correspondence  and  legal  representations.

     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, net of regulatory liabilities
as  summarized  in  the  following  table:
<TABLE>
<CAPTION>

REGULATORY  ASSETS  AND  LIABILITIES
                                                        At December 31,
                                                      2004         2003
                                                 ---------------  -------
Regulatory assets:                               (in thousands)
<S>                                              <C>              <C>
Demand-side management programs . . . . . . . .  $         7,293  $ 6,713
Purchased power costs . . . . . . . . . . . . .            2,322    2,574
Pine Street barge canal . . . . . . . . . . . .           13,250   12,954
Net power supply deferral . . . . . . . . . . .           12,085   19,734
Other regulatory assets . . . . . . . . . . . .            6,932    8,439
                                                 ---------------  -------
Total regulatory assets . . . . . . . . . . . .           41,882   50,414
                                                 ---------------  -------
   Regulatory liabilities:
Rate levelization liability . . . . . . . . . .                -    2,970
Accumulated cost of removal . . . . . . . . . .           19,806   21,238
Other regulatory liabilities. . . . . . . . . .            4,012    2,643
                                                 ---------------  -------
Total regulatory liabilities. . . . . . . . . .           23,818   26,851
                                                 ---------------  -------
Regulatory assets net of regulatory liabilities  $        18,064  $23,563
                                                 ===============  =======
</TABLE>
*Substantially  all  regulatory  assets  are  being  recovered  in current rates
effective January 1, 2005 and, with the exception of Pine Street Barge Canal and
certain  power  contract  related  costs,  include  an  associated  return  on
investment.

     The  net  power supply deferral results from certain power supply contracts
that must be marked to fair value as derivatives under current accounting rules.
The  Company records contract specified prices for electricity as expense in the
period used, as opposed to fair market values reflected in the above table.  The
power  supply  contract expenses are fully recovered in the rates we charge, and
are  discussed  in  detail  under  Power  Supply  Derivatives.

     The  Company  defers  and amortizes replacement power costs associated with
unscheduled  outages  at the Vermont Yankee nuclear power plant owned by Entergy
Nuclear Vermont Yankee LLC ("ENVY') and other extraordinary losses.  The Company
also  defers and amortizes extraordinary costs associated with natural disaster,
severe  storms  costs or significant loss of load under a rate plan (see Note I,
Commitments  and  Contingencies).

     Other  regulatory  assets totaled $6.9 million and $8.4 million at December
31,  2004  and  2003, respectively, and consist 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.

     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.  The
Company  provides  for  regulatory  disallowances when management believes it is
both  probable  and  estimable  that  a  regulatory  liability  exists.

     Accumulated  costs  of  removal represent asset retirement costs previously
recovered  from ratepayers for other than legal obligations.  In accordance with
SFAS  143,  "Accounting  for Asset Retirement Obligations," the Company reflects
these  amounts as a regulatory liability.  Prior to SFAS 143, these amounts were
recorded  as  a part of the Company's Accumulated Depreciation.  We expect, over
time,  to recover or settle through future revenues any under- or over-collected
net  cost  of  removal.

DISCONTINUED  OPERATIONS.  The Company accounts for its wholly-owned subsidiary,
Northern  Water Resources ("NWR") as a discontinued operation.  NWR's assets and
liabilities consist primarily of deferred tax assets and liabilities relating to
a  number of investments that the company has discontinued, inactivated, sold in
part  or  retains  as  passive minority interests.  Remaining holdings include a
minority  equity  investment  in  a  wind  project that usually, but not always,
generates  tax  losses;  minority  interest in a manufacturer of waste treatment
equipment;  and non-performing loans.  The Company recognized income of $.10 per
share  from  Discontinued Operations during 2004, compared with earnings of $.01
and  $.02  in  2003  and  2002,  respectively, reflecting diminished exposure to
outstanding  litigation  that  led  to reversal of previously recorded reserves.
Substantially  all  of  NWR's  investments  have  been  written  off  except for
associated  deferred  tax  amounts,  net  of  applicable  valuation  allowances.


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 cash flows would be re-valued 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, 2004, 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.

UTILITY  PLANT.  The  cost  of  plant additions is recorded at original cost and
includes  all  construction-related  direct  labor  and  materials,  as  well as
indirect  construction  costs.  The cost of plant additions includes the cost of
money  ("Allowance  for  Funds  Used During Construction" or "AFUDC") when costs
applicable  to  construction work in progress have not otherwise been provided a
return  through  regulatory proceedings.  The costs of renewals and improvements
of  property  units  are  capitalized.  The  costs  of  maintenance, repairs and
replacements  of  minor  property items are charged to maintenance expense.  The
costs  of  units  of  property  removed  from service, net of salvage value, are
charged  to  accumulated  depreciation.  The  following  table  summarizes  the
Company's  investments  in  utility  plant.
<TABLE>
<CAPTION>

Property  Summary  at  December  31,

                                              2004        2003
                                           ----------  ----------
In thousands
<S>                                        <C>         <C>
Property, Plant and Equipment:
Intangible. . . . . . . . . . . . . . . .  $  12,390   $  14,091
Generation. . . . . . . . . . . . . . . .     72,156      68,532
Transmission. . . . . . . . . . . . . . .     39,368      37,093
Distribution. . . . . . . . . . . . . . .    186,863     178,292
General, including transportation . . . .     28,492      26,892
                                           ----------  ----------
  Total Plant in Service. . . . . . . . .    339,269     324,900
Accumulated Depreciation and Amortization   (119,633)   (110,111)
                                           ----------  ----------
Net Plant in Service. . . . . . . . . . .    219,636     214,789
Capital Lease . . . . . . . . . . . . . .      4,731       5,047
Construction Work in Progress . . . . . .      8,345       9,026
                                           ----------  ----------
Total Net Utility Plant . . . . . . . . .  $ 232,712   $ 228,862
                                           ==========  ==========
</TABLE>

DEPRECIATION.  The  Company  provides  for  depreciation using the straight-line
method based on the cost and estimated remaining service life of the depreciable
property outstanding at the beginning of the year and adjusted for salvage value
and  cost  of  removal  of  the  property.

     The  annual  depreciation  provision  was  approximately 3.3 percent during
2004,  3.3  percent during 2003 and 3.2 percent during 2002 of total depreciable
property.

DISPOSAL  OF  ASSETS.  During  2004,  the  Company  sold  non-utility  property
consisting of land and buildings for $648,000.  The Company recognized a gain of
approximately $402,000 related to the sale of these assets, which is recorded in
Other  Income  in  the  Consolidated  Statement  of  Income.

CASH  AND  CASH  EQUIVALENTS.  Cash  and  cash  equivalents  include  short-term
investments  with  original  maturities  less  than  ninety  days.

RESTRICTED  CASH.  The  Company  has  set  aside  $354,000,  included  in  Other
Investments, as of December 31, 2004, for renewable generation development under
a  VPSB  regulatory  order.

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 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 $3.0 million, $1.1 million and
$4.5  million in deferred revenues during 2004, 2003 and 2002, respectively.  At
December  31,  2004,  the Company has recognized all revenues deferred under the
VPSB  orders.  See  Note  I  for  additional  information.

ALLOWANCE  FOR  DOUBTFUL ACCOUNTS.  The Company estimates the amount of accounts
receivable  that  will not be collected and records these amounts as a reduction
to  accounts  receivable.
<TABLE>
<CAPTION>

Allowance  for  Doubtful  Accounts
              Balance at     Additions     Additions               Balance at
              Beginning of   Charged to     Charged to                 End of
              Period   Cost & Expenses   Other Accounts   Deductions   Period
              -------  ----------------  ---------------  -----------  -------
In thousands
<S>           <C>      <C>               <C>              <C>          <C>
2004 . . . .  $   691  $              -  $             -  $        71  $   620
2003 . . . .      547               144                -            -      691
2002 . . . .      576                 -               37           66      547
</TABLE>
EARNINGS  PER SHARE.  Basic earnings per share ("EPS") is calculated by dividing
net  income,  after  deductions for preferred dividends, by the weighted-average
common  shares  outstanding  for  the period.  SFAS No. 128, Earnings Per Share,
requires  the  disclosure of diluted EPS, which is similar to the calculation of
basic  EPS  except  that  the weighted-average common shares is increased by the
number  of potential dilutive common shares.  Diluted EPS reflects the impact of
the  issuance  of  common  shares  for  all  potential  dilutive  common  shares
outstanding  during  the  period,  including  stock  options.

     During  the  year  ended  December  31,  2000,  the Company granted 335,300
options  under its 2000 Stock Plan 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.  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,
                                         2004     2003     2002
                                        -------  -------  -------
In thousands, except per share amounts
<S>                                     <C>      <C>      <C>
Net income reported. . . . . . . . . .  $11,584  $10,404  $11,398
Pro-forma net income . . . . . . . . .  $11,503  $10,242  $11,114
Net income per share
  As reported-basic. . . . . . . . . .  $  2.28  $  2.09  $  2.04
  Pro-forma basic. . . . . . . . . . .  $  2.26  $  2.06  $  1.99
  As reported-diluted. . . . . . . . .  $  2.20  $  2.02  $  1.98
  Pro-forma diluted. . . . . . . . . .  $  2.19  $  1.99  $  1.93
</TABLE>

MAJOR CUSTOMERS AND OTHER CONCENTRATION RISKS.  The Company has one major retail
customer,  International  Business  Machines Corporation ("IBM"), that accounted
for  24.1  percent,  24.1 percent and 25.7 percent of retail MWh sales, and 16.4
percent,  16.6  percent  and  17.3  percent  of  the  Company's retail operating
revenues  in  2004,  2003  and  2002,  respectively.

     We  currently  estimate,  based  on a number of projected variables, that a
hypothetical  shutdown  of  the  IBM  facility  would  necessitate a retail rate
increase  for  all  remaining customers of approximately five percent, including
secondary  and  tertiary  impacts  of  such  a shutdown on other customer sales.

     Our  material  power supply contracts are principally with Hydro Quebec and
Vermont  Yankee  Nuclear  Power  Corporation  ("VYNPC").  These  contracts  are
expected  to  meet  approximately  75  percent  of our anticipated annual demand
requirements  during  the  next five years.  These supplier concentrations could
have a material impact on the Company's net power costs, if one or both of these
sources  were unavailable over an extended period of time.  We also have a power
supply  contract  with  Morgan  Stanley Capital Group, Inc. (the "Morgan Stanley
Contract") for approximately 16 percent of our annual load that expires December
31,  2006.

FAIR  VALUE  OF FINANCIAL INSTRUMENTS.  The fair value and carrying 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,
                                        2004                             2003
                                        ----                             ----
                              Calculated    Amount carried    Calculated    Amount carried
In thousands                  Fair Value   on balance sheet   Fair Value   on balance sheet
<S>                           <C>          <C>                <C>          <C>
Long-Term Debt, net,(Note F)  $    91,274  $          93,000  $    91,725  $          93,000
Derivatives, net . . . . . .       12,085             12,085       19,773             19,773
</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.

     The  fair  value  of  derivatives  is  discussed  below  under  "Derivative
Instruments."

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.

PURCHASED  POWER.  The  Company  records the annual cost of power obtained under
long-term  executory  contracts  as  operating  expenses.  The  contracts do not
convey to the Company the right to use the related property plant, or equipment.

DERIVATIVE  INSTRUMENTS.  The  Company utilizes derivative instruments primarily
to  reduce  power  supply  risk.  The  Company  does not hold derivative trading
positions.  The  Company  has continued to record expense related to derivatives
in  the  period  settled consistent with an accounting order issued by the VPSB.

     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  agreement (the "9701 agreement") that grants Hydro
Quebec  an  option  to  call  power at prices below current and estimated future
market  rates.  This agreement is effective through 2015.  From time to time, we
use  forward contracts to hedge the 9701 agreement.  Since we are required under
VPSB  order  to defer recognition of any SFAS 133 earnings effect until settled,
we  do  not evaluate derivatives for hedge accounting treatment.  If the Company
were  to terminate or sell any of its derivative contracts, it would immediately
record  the  gain  or  loss  on  that  contract, absent a regulatory order to do
otherwise.

       The  table  below presents assumptions used to estimate the fair value of
the  Morgan  Stanley  Contract  and  the 9701 agreement.  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            2.0%      32%-29%  $           62     2006
9701 Arrangement. . . .  Black-Scholes            4.3%      46%-27%  $           66     2015
</TABLE>

At  December  31, 2004, the Company had a liability in deferred credits of $22.8
million  reflecting  the fair value of the 9701 agreement, and an asset of $10.7
million,  reflecting  the  fair  value  of  the  Morgan  Stanley  Contract.  A
corresponding net regulatory asset of $12.1 million is also recorded in deferred
charges.  At  December  31,  2003, the Company had a liability of $23.7 million,
reflecting  the  fair value of the 9701 agreement, and an asset of $4.0 million,
reflecting  the  fair value of the Morgan Stanley Contract.  A corresponding net
regulatory  asset of $19.7 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.  Morgan  Stanley purchases a portion of the Company's power supply
resources  at  index  (fossil  fuel  resources)  or  specified (i.e., contracted
resources)  prices and then sells to us at a fixed rate to serve pre-established
load  requirements.  This  contract allows management to fix the cost of much of
its  power supply requirements, subject to power resource availability and other
risks.  The  Morgan  Stanley  Contract  expires  December  31,  2006.

RECLASSIFICATIONS.  The Company changed the classification of certain previously
reported  amounts  in  the accompanying balance sheet as of December 31, 2003 to
correct  immaterial  errors  related  to  the  accounting for income taxes.  The
effect  of the changes was to decrease accumulated deferred income taxes by $4.0
million,  increase  other  deferred  credits  by  $3.4 million, and increase net
liabilities  of  discontinued  operations  by  approximately  $600,000.  We made
conforming  changes  to  the tax footnote and cash flow statement.  In addition,
certain  prior  years amounts have been reclassified for consistent presentation
with  the  current  year.

OTHER  COMPREHENSIVE  INCOME.  Certain negative scenarios and unfavorable market
conditions (asset returns are lower than expected, reductions in discount rates,
and  liability  experience  losses)  may  cause  the  Pension Plan's accumulated
benefit obligation ("ABO") to exceed the fair value of Pension Plan assets as of
the measurement date and would result in an unfunded minimum liability.  If that
occurs,  and  the  minimum  liability  exceeds  the  accrued  benefit  cost,  an
additional minimum pension liability may be required to be recorded, net of tax,
as  a  non-cash  charge  to Other Comprehensive Income, included in Common Stock
Equity  on the Consolidated Balance Sheet.  The ABO represents the present value
of  benefits  earned  without  considering  future  salary  increases.

     Other comprehensive loss of $2.4 million, net of a $1.6 million income tax,
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 resulted in
a  reduction  in  other  comprehensive  loss  of  approximately $587,000, net of
$400,000  income tax.  During 2004, due principally to a decline in the discount
rate  used  for  pension  calculations,  we  recorded  an  increase  in  other
comprehensive  loss  of  $566,000,  net  of  $391,000  income  tax.

RECENT  ACCOUNTING  PRONOUNCEMENTS.  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 impact the
Company's  financial  position  or results of operations.  See FIN 45 discussion
related  to  Hydro  Quebec  under  Note  K.

     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 and December 2003, the Financial Accounting Standards Board
issued  Interpretation  46  and  46R  (Revised), respectively, "Consolidation of
Variable Interest Entities" ("VIEs").  This interpretation clarified application
of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," and
replaced  current  accounting  guidance  relating  to  consolidation  of certain
special  purpose  entities.  FIN 46 and FIN 46R define VIEs as entities that are
unable  to  finance  their  ongoing  operations  without additional subordinated
financing.  FIN  46R  requires  identification of the Company's participation in
VIEs  and  consolidation  of  those  VIEs  of  which  the Company is the primary
beneficiary.  The  Company  adopted  FIN  46 at December 31, 2003 and FIN 46R at
March  31,  2004,  and  was  not  required to consolidate any existing interests
pursuant  to  the  requirements  of  FIN  46  or  FIN  46R.

     On  December  8,  2003,  President  Bush  signed  into  law  the  Medicare
Prescription  Drug,  Improvement and Modernization Act of 2003 ("the Act").  The
Act  expanded Medicare to include, for the first time, coverage for prescription
drugs,  generally  effective January 1, 2006.  The Company provides health care,
life  insurance,  prescription  drug and other benefits to retired employees who
meet  certain  age  and  years  of service requirements.  The Company elected to
defer  recognition  of  any  impact  under FSP 106-1, "Accounting and Disclosure
Requirements  Related  to  the  Medicare  Prescription  Drug,  Improvement  and
Modernization  Act  of  2003."

     On  May  19,  2004,  the  FASB  issued  FASB  Staff Position No. FAS 106-2,
"Accounting  and  Disclosure  Requirements  Related to the Medicare Prescription
Drug,  Improvement  and  Modernization Act of 2003," which requires employers to
provide certain disclosures regarding the effect of the federal subsidy provided
by  the  Act.

     Pending  the  release  of  final  regulations,  the  Company  was unable to
conclude  whether  the benefits provided by the plan were actuarially equivalent
to  Medicare  Part  D under the Act, and to accurately measure the effect of the
change  on the accumulated postretirement benefit obligation ("APBO") or the net
periodic  postretirement  benefit cost ("net periodic cost").  This was a result
of  uncertainty  with  treatment  under the Act of contributions made by certain
retirees  and  the  Company's cap on employer medical premiums.  Regulations and
their  interpretations were finalized in January 2004, and the reduction in APBO
at  December  31,  2004,  was  determined to be approximately $3.5 million.  The
expected  subsidy  will  impact  annual  net  periodic  cost in 2005 and beyond.


     In  November  2004,  the FASB issued SFAS No. 151, "Inventory Costs" ("SFAS
151"),  which  clarifies  the  accounting  for abnormal amounts of idle facility
expense, freight, handling costs and wasted material.  SFAS 151 is effective for
inventory costs incurred during fiscal years beginning after June 15, 2005.  The
Company does not believe the adoption of SFAS 151 will have a material effect on
its  respective  financial  statements.

     In December 2004, the FASB issued a revision to SFAS No. 123R, "Share-Based
Payments,"  which  replaces  SFAS  No.  123,  "Accounting  for  Stock-Based
Compensation."  The revision determines how the Company will measure the cost of
employee  services  received  in exchange for share-based payments.  The cost of
share-based  payments  will  be based on the grant date fair value of the award.
The  guidance  is  effective  as of the beginning of the first interim or annual
reporting  period  after June 15, 2005.  The Company has not yet determined what
the  impact of this new standard will be on its financial position or results of
operations.

     In  December  2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary
Assets,  as  amended  of  APB  Opinion No. 29" ("SFAS 153"), which addresses the
measurement  of  exchanges  of  nonmonetary  assets  and  redefines the scope of
transactions  that  should  be  measured  based  on the fair value of the assets
exchanged.  SFAS  153  is effective for nonmonetary asset exchanges occurring in
fiscal  periods beginning after June 15, 2005.  The Company does not believe the
adoption  of  SFAS  153  will have a material effect on its respective financial
statements.

     In  December 2004, the FASB issued FASB Staff Position 109-1 ("FSP 109-1"),
which  was  effective  upon  issuance, to provide guidance of the application of
SFAS  No.  109,  "Accounting  for  Income  Taxes" ("SFAS 109"), to the provision
within  the  American Jobs Creation Act of 2004 ("Jobs Act") that provides a tax
deduction  on  qualified  production  activities.  The  Jobs  Act includes a tax
deduction  of  up  to  9  percent  (when  fully  phased-in) of the lesser of (a)
"qualified  production  activities  income,"  as defined in the Jobs Act, or (b)
taxable  income  (after  the  deduction for the utilization of any net operating
loss  carryforwards).  The  tax  deduction is limited to 50 percent of W-2 wages
paid  by  the  taxpayer.  FSP  109-1 clarifies that the manufacturer's deduction
provided  for  under the Jobs Act should be accounted for as a special deduction
in  accordance  with  SFAS 109 and not as a tax rate reduction.  The adoption of
FSB  109-1  had no impact on the Company's financial statements.  The Company is
evaluating  the effect that the manufacturer's deduction will have in subsequent
years.


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,
                                             2004     2003     2004    2003
                                           --------  -------  ------  ------
(IN THOUSANDS)
<S>                                        <C>       <C>      <C>     <C>
VELCO-common. . . . . . . . . . . . . . .    29.17%   28.41%  $7,041  $2,469
VELCO-preferred . . . . . . . . . . . . .    30.00%   30.00%     158     246
                                                              ------  ------
Total VELCO . . . . . . . . . . . . . . .                    7,199    2,715

VYNPC- Common . . . . . . . . . . . . . .    33.60%   33.60%   1,612   1,605
New England Hydro Transmission-Common . .     3.18%    3.18%     515     592
New England Hydro Transmission Electric-
    Common. . . . . . . . . . . . . . . .     3.18%    3.18%     853     984
                                                              ------  ------
Total investment in associated companies.                  $10,179   $5,896
                                                           ========  =======
</TABLE>
VELCO.  VELCO  and  its  wholly-owned  subsidiary, Vermont Electric Transmission
Company,  own  and operate transmission systems in Vermont over which bulk power
is  delivered  to all electric utilities in the state.  VELCO operates under the
terms  of  the  1985  Four-Party Agreement (as amended) with the Company and two
other  major  distribution  companies  in  Vermont.

     VELCO  has  entered  into transmission agreements with the State of Vermont
and  other electric utilities including the Company, 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 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 required
to  pay  for  its share of VELCO's operating costs including debt service costs.
The  Company  plans  to  make  capital investments of up to $20 million in VELCO
through  2007  in  support  of  various  transmission projects, including a $4.6
million  investment  made  in  the  last  quarter  of  2004.
<TABLE>
<CAPTION>

Summarized  unaudited  financial  information  for  VELCO  is  as  follows:

At  and  for  the  years  ended  December  31,
                                   2004       2003       2002
                                 ---------  ---------  ---------
(In thousands)
<S>                              <C>        <C>        <C>
Net income. . . . . . . . . . .  $  1,683   $  1,270   $  1,094
Company's equity in net income.  $    472   $    418   $    319
                                 =========  =========  =========
Total assets. . . . . . . . . .  $145,632   $126,793   $106,613
Liabilities and long-term debt.   120,983    117,393     97,417
                                 ---------  ---------  ---------
Net assets. . . . . . . . . . .  $ 24,649   $  9,400   $  9,196
                                 =========  =========  =========
Company's equity in net assets.  $  7,199   $  2,715   $  2,614
                                 =========  =========  =========
Amounts due from (to) VELCO . .  $ (4,068)  $ (4,190)  $ (5,550)
</TABLE>

Included  in  VELCO's  revenues  shown  above  are  transmission services to the
Company  (reflected  as  transmission  expenses in the accompanying Consolidated
Statements  of Income) amounting to $12.3 million in 2004, $12.0 million in 2003
and  $12.7  million  in  2002,  respectively.

VERMONT  YANKEE  NUCLEAR  POWER  CORPORATION ("VYNPC").  The Company's ownership
share  of  VYNPC  has  increased  from  approximately  19.0  percent  in 2002 to
approximately  33.6  percent  currently,  due  to  VYNPC's  purchase  of certain
minority  shareholders' interests.  The Company's entitlement to energy produced
by  the  Vermont  Yankee nuclear plant owned by ENVY remains at approximately 20
percent  of  plant  production.
<TABLE>
<CAPTION>

Summarized  unaudited  financial  information  for  VYNPC  is  as  follows:
At  and  for  the  years  ended  December  31,

                                            2004       2003*      2002
                                          ---------  ---------  ---------
(In thousands)
<S>                                       <C>        <C>        <C>
Earnings:
  Operating revenues . . . . . . . . . .  $167,399   $187,123   $175,722
  Net income applicable to common stock.       538      2,536      9,454
  Company's equity in net income . . . .  $    181   $    498   $  1,745
                                          =========  =========  =========
Total assets . . . . . . . . . . . . . .  $151,542   $150,720   $201,426
  Liabilities and long-term debt . . . .   146,747    145,946    150,413
                                          ---------  ---------  ---------
Net Assets . . . . . . . . . . . . . . .  $  4,795   $  4,774   $ 51,203
                                          =========  =========  =========
Company's equity in net assets . . . . .  $  1,612   $  1,605   $  9,721
                                          =========  =========  =========
Amounts due from (to) VYNPC. . . . . . .  $ (3,324)  $ (2,648)  $ (3,487)
</TABLE>
*The 2003 decrease in equity in net assets of VYNPC resulted from a distribution
of  proceeds,  in  the  form  of dividends to VYNPC owners, from the sale of the
VYNPC  nuclear  power  plant.

     On  July  31,  2002,  VYNPC  announced  that the sale of the Vermont Yankee
nuclear  power  plant  to  ENVY had been completed.  Since the Company no longer
owns an interest in the Vermont Yankee nuclear plant, we are not responsible for
the  costs  of  decommissioning  the plant, nor are we responsible for any plant
repairs or maintenance costs during outages.  See Note K for further information
concerning  our  long-term  power  contract  with  VYNPC.

     ENVY  has  announced  that,  under  current  operating  parameters, it will
exhaust  the capacity of its existing nuclear waste storage pool in 2007 or 2008
and  will need to store nuclear waste in so-called "dry fuel storage" facilities
to  be  constructed on the site.  Current Vermont law appears to require ENVY to
obtain  approval of the Vermont State legislature, in addition to VPSB approval,
to  construct and use such dry fuel storage facilities.  If ENVY is unsuccessful
in  receiving  favorable legislative action and/or regulatory approval, ENVY has
announced  that  it would be required to shut down the Vermont Yankee plant.  If
the  Vermont  Yankee  plant  is  shut  down, we would have to acquire substitute
baseload  power  resources, comprising approximately 35 percent of our estimated
total power supply needs.  At currently projected market prices, we estimate the
annual  incremental  cost  (in  excess of the projected costs of power under our
power  supply  contract  for  output  from the Vermont Yankee facility) would be
approximately  $9  million annually.  Recovery of those increased costs in rates
would  require  a  rate  increase  of  approximately  5  percent.

     In April 2004 ENVY reported that two short spent fuel rod segments were not
in  what  ENVY  believed to be their documented location in the spent fuel pool.
After  initial review and visual inspection of the spent fuel pool, ENVY did not
locate  the fuel rod segments.  By letter dated May 5, 2004, ENVY notified VYNPC
that based on the terms of the Purchase and Sale Agreement dated August 1, 2001,
and  facts at that time, it was ENVY's view that costs associated with the spent
fuel  rod  segment  inspection  effort  were the responsibility of VYNPC.  VYNPC
responded  that  based  on  the information at that time, there was no basis for
ENVY  to  claim the inspection was VYNPC's responsibility.  Subsequently, ENVY's
continuing documentation review led to the discovery of the fuel rod segments in
a  container  in  the  spent  fuel  pool.  We cannot predict the outcome of this
matter  at  this  time.

     On  June  18,  2004,  a  fire  in  the  electrical  conduits  leading  to a
transformer  outside  the  plant  resulted in a shutdown of the ENVY plant.  The
outage  ended  on  July 7, 2004.  In response to the Company's request, the VPSB
issued  a  final  accounting order allowing the Company to defer its incremental
replacement  power costs during the outage totaling approximately $500,000.  The
order  also  instructs  the  Company  to  apply  any  proceeds  received under a
Ratepayer  Protection  Proposal  ("RPP")  to  reduce  the  balance  of  deferred
replacement  power  costs.

     The  RPP  was  a part of ENVY's request to uprate or increase the output of
the  VY  nuclear  plant  that  was approved by the VPSB.  Under the RPP, we have
indemnification  rights  to  between  approximately $550,000 and $1.6 million to
recover  uprate-related reductions in output for the three-year period beginning
in  May  2004  and  ending after completion of the uprate (or a maximum of three
years),  depending on future wholesale energy market prices.  ENVY disputes that
the fire was uprate-related.  The Company has petitioned the VPSB to resolve the
dispute.


C.  COMMON  STOCK  EQUITY  AND  STOCK  AWARD  PLANS
     The  Company  maintains  a  Dividend  Reinvestment  and Stock Purchase Plan
("DRIP")  under  which 416,328 shares were reserved and unissued at December 31,
2004.  The  Company  also funds an Employee Savings and Investment Plan ("ESIP")
under  which  the  Company  may  contribute  shares  of  common  stock.

     During  2000, the Company's Board of Directors, with subsequent approval of
the Company's common shareholders, established a stock incentive plan (the "2000
Stock  Plan").  Under  this  plan,  up  to 500,000 shares of common stock may be
issued  in  the  form  of  options,  stock  grants,  stock  appreciation rights,
restricted  stock,  restricted  stock  units,  performance  awards  and  other
stock-based  awards to any employee, officer, consultant, contractor or director
providing  services to the Company, or its subsidiaries.  The Company has issued
stock  options, stock awards and deferred stock units to employees and directors
under  the plan.  Outstanding options become exercisable at between one and four
years  after the grant date and remain exercisable until 10 years from the grant
date.  As  of December 31, 2004, 23,023 shares are unissued under the 2000 Stock
Plan.

     During  2004, the Company's Board of Directors, with subsequent approval of
the  Company's  common  shareholders, established the 2004 Stock Incentive Plan,
under  which  225,000  shares  in  the  form  of  stock  grants,  options, stock
appreciation  rights,  restricted  stock and restricted stock units, performance
awards  or  other  stock-based  awards  can be granted to any employee, officer,
consultant,  contractor  or  director  providing services to the Company, or its
subsidiaries.  As  of  December  31,  2004, no shares have been issued under the
2004  Stock  Incentive  Plan.

     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, and no
options  were  granted  in 2004.  Options have been issued only to employees and
directors.

     The  fair  values  of options granted in 2003, and 2002 are $1.33 and $2.27
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,  2004:
<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
      ------  -------  -----------  -------  -------  -----  -----------  -----
<C>   <C>     <C>      <S>          <C>      <C>      <C>    <C>          <C>
2000  $ 7.90  145,600    5.6 years    6.05%        5  30.58         4.5%
2001  $16.77   18,100    6.6 years    5.25%        6  32.69         4.0%
2002  $17.90   49,300    7.6 years    4.50%      6.5  16.89         4.5%
2003  $20.64    2,300    8.3 years    2.48%        6  13.68         4.5%
      ------  -------
Total $11.07   215,300
     =======  =======
</TABLE>

<TABLE>
<CAPTION>
                                          Weighted     Range of
                                  Total    Average     Exercise     Options
                                  Options  Price      Prices      Exercisable
                                  -------  ------  -------------  -----------
<S>                               <C>      <C>     <C>            <C>
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
                                  -------  ------  -------------  -----------
Granted. . . . . . . . . . . . .        -       -              -
Exercised. . . . . . . . . . . .   84,150   12.11  $ 7.90-$20.96
Forfeited. . . . . . . . . . . .    1,400   18.65  $17.54-$20.96
                                  -------  ------  -------------
Outstanding at December 31, 2004  215,300  $11.07  $ 7.90-$22.62      213,500
                                  =======  ======  =============  ===========
</TABLE>
 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

                                              2004         2003     2002
                                         ---------------  -------  -------
                                         (in thousands)
<S>                                      <C>              <C>      <C>
Net income before preferred dividends .  $        11,584  $10,407  $11,494
Preferred stock dividend requirement. .                -        3       96
                                         ---------------  -------  -------
Net income applicable to common
   stock. . . . . . . . . . . . . . . .  $        11,584  $10,404  $11,398
                                         ===============  =======  =======

Average number of common shares-basic .            5,083    4,980    5,592
Dilutive effect of stock options. . . .              171      160      164
                                         ---------------  -------  -------
Average number of common shares-diluted            5,254    5,140    5,756
                                         ===============  =======  =======
</TABLE>





 As part of our long-term stock incentive program, unrestricted stock grants and
deferred  stock  unit  grants have been made to employees, senior management and
directors.  Unrestricted  stock  grants  are  recognized as compensation expense
based  on  the fair value of the awards at the grant date.  Deferred stock units
are  recognized as deferred compensation based on the fair value of the award at
the  grant date and charged to expense over the required service period for each
award.  Awards  to senior management vest over a two year service period.  Total
compensation  expense  from  all stock awards to directors, employees and senior
management  totaled  $1.2  million  in  2004  and  $422,000  in  2003.

     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.

     Appropriated  Retained  Earnings.  The  Company  had  appropriated retained
earnings  of  $353,000 and $277,000 at December 31, 2004 and 2003, respectively,
relating  to  regulatory  requirements  arising from ownership of hydro-electric
facilities.

     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 Amended and Restated Articles of Incorporation.  Under
the most restrictive of such provisions, approximately $28.6 million of retained
earnings  were  free  of  restrictions  at  December  31,  2004.


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
$300,000  of  the  7.0  percent  Class  C  preferred  stock outstanding.  During
November  2002,  the  Company  repurchased  the  remaining $200,000 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  $30.0 million 364-day revolving credit agreement with
Fleet  Financial  Services  ("Fleet")  joined  by  Sovereign Bank ("Sovereign"),
expiring  June  2005  (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 $3.0 million
outstanding at a weighted average rate of 5.25 percent, and $500,000 outstanding
at  a weighted average rate of 4 percent, under the Fleet-Sovereign Agreement at
December  31,  2004 and 2003, respectively.  There was no non-utility short-term
debt  outstanding  at  December  31,  2004  or  2003.

     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,  2004.


F.  LONG-TERM  DEBT
     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,  2004  and  2003.  The annual sinking fund requirements
(excluding  amounts that may be satisfied by property additions) are included in
the following table with interest rates and maturities as of December 31 for the
years  presented.

<TABLE>
<CAPTION>

     LONG-TERM  DEBT
     FIRST  MORTGAGE  BONDS               (In  thousands)
Interest rate-Maturity                             Annual Sinking Fund     2004     2003
                                                                          -------  -------
<S>                                               <C>                     <C>      <C>
  7.05%-Dec. 15, 2006. . . . . . . . . . . . . .                       -  $ 4,000  $ 4,000
  7.18%-Nov. 6, 2006 . . . . . . . . . . . . . .                       -   10,000   10,000
  6.04%-Dec. 1, 2017 . . . . . . . . . . . . . .  6,000,000 begins 2011    42,000   42,000
  6.7%-Nov. 1, 2018. . . . . . . . . . . . . . .                       -   15,000   15,000
  9.64%-Sept. 1, 2020. . . . . . . . . . . . . .                       -    9,000    9,000
  8.65%-Mar. 1, 2022 . . . . . . . . . . . . . .  $  500,000 begins 2012   13,000   13,000
                                                                          -------  -------
  Total Long-term Debt Outstanding          . . . . . . .                  93,000   93,000
  Less Current Maturities (due within one year).                                -        -
  TOTAL LONG-TERM DEBT, LESS CURRENT MATURITIES.           $               93,000  $93,000
                                                           ======================  =======
</TABLE>

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.


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  temporary  differences,  which  gave  rise  to  the  net  deferred tax
liability  at  December  31,  2004  and  December  31,  2003,  were  as follows:
<TABLE>
<CAPTION>

                                      AT  DECEMBER  31,
                                        2004     2003
                                       -------  -------
(In thousands)
<S>                                    <C>      <C>
DEFERRED TAX ASSETS
Contributions in aid of construction.  $ 2,155  $   896
Deferred compensation and
     postretirement benefits. . . . .    4,972    4,303
Self insurance and other reserves . .      639      637
Other . . . . . . . . . . . . . . . .    1,654    2,602
                                       -------  -------
                                       $ 9,420  $ 8,438
                                       -------  -------

DEFERRED TAX LIABILITIES
Property related. . . . . . . . . . .  $32,453  $29,230
Demand side management. . . . . . . .    2,955    2,558
Deferred purchased power costs. . . .    1,033      792
Pine Street reserve . . . . . . . . .    2,753    2,410
Other . . . . . . . . . . . . . . . .    2,449    3,448
                                       -------  -------
                                       $41,643  $38,438
                                       -------  -------
  Net accumulated deferred income
    tax liability . . . . . . . . . .  $32,223  $30,000
                                       =======  =======
</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,
                                        2004      2003      2002
                                       -------  --------  --------
(In thousands)
<S>                                    <C>      <C>       <C>
Net change in deferred income tax . .  $2,223   $ 3,529   $ 2,712
  liability
Change in income tax related
  regulatory assets and liabilities .   2,151    (2,166)    2,759
Change in tax effect of accumulated
  other comprehensive income. . . . .    (391)      398    (1,612)
                                       -------  --------  --------
Deferred income tax expense (benefit)  $3,983   $ 1,761   $ 3,859
                                       =======  ========  ========
</TABLE>
The  components  of  the  provision  for  income  taxes  are  as  follows:

<TABLE>
<CAPTION>

                              YEARS  ENDED  DECEMBER  31,
                                 2004     2003     2002
                                -------  -------  -------
(In thousands)
<S>                             <C>      <C>      <C>
Current federal income taxes .  $  461   $2,434   $1,873
Current state income taxes . .   1,602    1,207      593
                                -------  -------  -------
Total current income taxes . .   2,063    3,641    2,466
Deferred federal income taxes.   3,843    1,307    2,920
Deferred state income taxes. .     140      454      939
                                -------  -------  -------
Total deferred income taxes. .   3,983    1,761    3,859
Investment tax credits-net . .    (284)    (282)    (282)
                                -------  -------  -------
Income tax expense . . . . . .  $5,762   $5,120   $6,043
                                =======  =======  =======
</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,
                                                  2004      2003      2002
                                                --------  --------  --------
(In thousands)
<S>                                             <C>       <C>       <C>
Income before income taxes and
  preferred dividends. . . . . . . . . . . . .  $17,346   $15,527   $17,537
Federal statutory rate . . . . . . . . . . . .     35.0%     34.0%     34.0%
                                                --------  --------  --------
Computed "expected" federal income taxes . . .  $ 6,071   $ 5,279   $ 5,963
Increase (decrease) in taxes resulting from:
Tax versus book depreciation basis difference.     (149)       41        41
Dividends received credit. . . . . . . . . . .     (452)     (465)     (575)
Amortization of ITC. . . . . . . . . . . . . .     (284)     (282)     (282)
State tax. . . . . . . . . . . . . . . . . . .    1,133     1,082     1,011
Excess deferred taxes. . . . . . . . . . . . .     (123)      (60)      (60)
Wind energy production credit. . . . . . . . .     (125)     (130)        -
Other. . . . . . . . . . . . . . . . . . . . .     (309)     (345)      (55)
                                                --------  --------  --------
Total federal and state income tax . . . . . .  $ 5,762   $ 5,120   $ 6,043
                                                ========  ========  ========
Effective combined federal and state
  income tax rate. . . . . . . . . . . . . . .     33.2%     33.0%     34.5%
</TABLE>

H.  PENSION  AND  RETIREMENT  PLANS.
     The  Company  has a qualified non-contributory defined benefit pension plan
(the  "Pension  Plan")  covering  substantially  all  of  its  employees.  The
retirement benefits are based on the employees' level of compensation and length
of  service.  Under  the  terms  of the Pension Plan, employees are vested after
completing  five  years of service, and can retire when they reach age 55 with a
minimum of 10 years of service.  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 and postretirement
health  care  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 the Pension Benefit Guaranty Corporation, and so long as the Company's
liquidity  needs  do  not preclude such investments.  The Company made voluntary
defined  benefit  plan contributions totaling $3.5 million during 2003 and $2.25
million during 2004.  The Company currently plans to contribute between $2.0 and
$3.0  million  of  additional  funds  during  2005.

     During 2002, the Company's retirement plan asset return experience required
the  Company  to recognize a minimum pension liability of $4.0 million, and $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.

     During  2004,  the  Company  increased  its  previously  recognized minimum
pension  liability  by  $1  million  to approximately $4 million, primarily as a
result of a decrease in the pension plan discount rate.  Common equity decreased
approximately  $566,000,  net  of  applicable  income  tax,  through a charge to
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,  2004  and  2003.
<TABLE>
<CAPTION>

                                                At and for the years ended December 31,
                                                 Pension Benefits  Other Postretirement Benefits
                                                       -----------------------------
                                                   2004      2003      2004      2003
                                                 --------  --------  --------  ---------
(In thousands)
Change in projected benefit obligation:
<S>                                              <C>       <C>       <C>       <C>
Projected benefit obligation prior year end . .  $33,980   $29,937   $21,906   $ 20,707
Service cost. . . . . . . . . . . . . . . . . .      991       755       335        496
Interest cost . . . . . . . . . . . . . . . . .    2,005     1,900     1,165      1,316
Participant contributions . . . . . . . . . . .        -         -       115        136
Plan change . . . . . . . . . . . . . . . . . .        -       292         -     (1,812)
Change in actuarial assumptions . . . . . . . .        -         -         -          -
Actuarial (gain) loss . . . . . . . . . . . . .    1,225     2,789    (3,595)     2,070
Benefits paid . . . . . . . . . . . . . . . . .   (1,614)   (1,629)     (947)    (1,007)
Administrative expense. . . . . . . . . . . . .      (74)      (64)        -          -
                                                 --------  --------  --------  ---------
Projected benefit obligation as of year end . .  $36,513   $33,980   $18,979   $ 21,906
                                                 ========  ========  ========  =========
Accumulated benefit obligation. . . . . . . . .  $33,032   $30,459   $18,979   $ 21,906
Change in plan assets:
Fair value of plan assets as of prior year end.  $27,867   $21,104   $10,229   $  8,760
Administrative expenses paid. . . . . . . . . .      (74)      (64)        -          -
Participant contributions . . . . . . . . . . .        -         -         -          -
Employer contributions. . . . . . . . . . . . .    1,550     3,500       700          -
Actual return on plan assets. . . . . . . . . .    2,201     4,956       852      1,558
Benefits paid . . . . . . . . . . . . . . . . .   (1,614)   (1,629)     (110)       (89)
                                                 --------  --------  --------  ---------
Fair value of plan assets as of year end. . . .  $29,930   $27,867   $11,671   $ 10,229
                                                 ========  ========  ========  =========

Funded status as of year end. . . . . . . . . .  $(6,584)  $(6,113)  $(7,307)  $(11,677)
Unrecognized transition obligation. . . . . . .        -         -     2,624      2,952
Unrecognized prior service cost . . . . . . . .      815       984    (1,977)    (2,216)
Unrecognized net actuarial loss . . . . . . . .    7,438     6,372     5,322      9,250
                                                 --------  --------  --------  ---------
Prepaid (accrued) benefits at year end. . . . .  $ 1,669   $ 1,243   $(1,338)  $ (1,691)
                                                 ========  ========  ========  =========
</TABLE>

The Company also has a supplemental pension plan for certain employees.  Pension
costs  for  the  years  ended  December  31,  2004, 2003 and 2002 were $475,000,
$392,000  and  $408,000,  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
                                              2004      2003      2002     2004     2003     2002
                                            --------  --------  --------  -------  -------  -------
(In thousands)
<S>                                         <C>       <C>       <C>       <C>      <C>      <C>
Service cost . . . . . . . . . . . . . . .  $   991   $   755   $   668   $  335   $  496   $  296
Interest cost. . . . . . . . . . . . . . .    2,005     1,900     1,849    1,165    1,316    1,119
Expected return on plan assets . . . . . .   (2,285)   (1,851)   (2,112)    (857)    (740)    (851)
Amortization of transition asset . . . . .        -       (77)     (164)       -        -        -
Amortization of prior service cost . . . .      169       147       147     (239)     (58)     (58)
Amortization of the transition obligation.        -         -         -      328      328      328
Recognized net actuarial gain. . . . . . .      243       294         -      338      381       60
                                            --------  --------  --------  -------  -------  -------
    Net periodic benefit cost. . . . . . .  $ 1,123   $ 1,168   $   388   $1,070   $1,723   $  894
                                            ========  ========  ========  =======  =======  =======
</TABLE>
Assumptions  used  to determine pension and postretirement benefit costs and the
related  benefit  obligations  were:
<TABLE>
<CAPTION>

Assumptions used in               For the years ended December 31,
benefit obligation measurement               Pension benefits         Other Postretirement Benefits
                                                  2004         2003         2004         2003
                                              -----------  -----------  -----------  -----------
<S>                                           <C>          <C>          <C>          <C>
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . .        5.75%        6.00%        5.75%        6.00%
Expected return on plan assets . . . . . . .        8.25%        8.50%        8.25%        8.50%
Rate of compensation increase. . . . . . . .        4.00%        4.25%        4.00%        4.25%
Medical inflation. . . . . . . . . . . . . .           -            -        10.75%        9.25%
Measurement date . . . . . . . . . . . . . .  12/31/2004   12/31/2003   12/31/2004   12/31/2003
Census date. . . . . . . . . . . . . . . . .    1/1/2004     1/1/2003     1/1/2004     1/1/2003
</TABLE>
<TABLE>
<CAPTION>

       Assumptions used in                  For the years ended December 31,
      periodic cost measurement          Pension benefits Other Postretirement Benefits
                                               2004   2003   2004    2003
                                              -----  -----  -----  ------
<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 . . . . . . .  8.25%  8.50%  8.25%   8.50%
Rate of compensation increase. . . . . . . .  4.25%  4.25%  4.25%   4.25%
Current year trend . . . . . . . . . . . . .     -      -   9.25%  10.00%
Ultimate year trend. . . . . . . . . . . . .                5.50%   5.50%
Year of ultimate trend . . . . . . . . . . .                 2009   2009
</TABLE>


For  measurement  purposes,  a  10.75 percent annual rate of increase in the per
capita  cost  of  covered  medical  benefits was assumed for 2004.  This rate of
increase  gradually  declines  to  5.0  percent in 2011.  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, 2004 by 12.0 percent or $2.3 million and the total
of  the service and interest cost components of net periodic postretirement cost
for  the year ended December 31, 2004 by $190,000.  Decreasing the trend rate by
one  percentage  point  for  all  future  years  would  decrease the accumulated
postretirement  benefit  obligation  at December 31, 2004 by 9.3 percent or $1.8
million,  and  the  total  of  the  service  and interest cost components of net
periodic  postretirement  cost  for  2004  by  $156,000.

     The  Company's  defined  benefit  plan  investment  policy seeks to achieve
sufficient  growth  to  enable  the  defined  benefit plans to meet their 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>

Weighted Average Asset Allocation
                                Pension Assets         Other Postretirement Benefit Assets
Asset Category                      For the years ended December 31,
                     2005 TARGET  2004*    2003          2005 TARGET 2004   2003
-----------------------  -------  -------  ------------  -------  -------
<S>                      <C>      <C>      <C>           <C>      <C>      <C>
Equity Securities . . .   65.00%   48.96%        63.10%   65.00%   63.00%   62.00%
Debt Securities . . . .   30.00%   25.80%        24.92%   35.00%   32.00%   36.00%
Real Estate . . . . . .    0.00%    0.00%         0.00%    0.00%    0.00%    0.00%
Other . . . . . . . . .    0.00%   19.94%         6.60%    0.00%    5.00%    2.00%
Alternative investments    5.00%    5.30%         5.38%    0.00%    0.00%    0.00%
                         -------  -------  ------------  -------  -------  -------
Total . . . . . . . . .  100.00%  100.00%       100.00%  100.00%  100.00%  100.00%
                         =======  =======  ============  =======  =======  =======
</TABLE>


*The  large  difference between the target and actual allocations is due to a $5
million  cash  transfer between  funds  at  December  31,  2004

<TABLE>
<CAPTION>

                           Pension benefits Other Postretirement Benefits
                           ---------------- -----------------------------
                             Projected                  Projected
                                   Benefit                    Benefit
                   Contributions   payments   Contributions   payments
                   --------------  ---------  --------------  ---------
                    In Thousands
<S>                <C>             <C>        <C>             <C>
2005. . . . . . .  $        1,500  $   1,623  $        1,362  $     962
2006. . . . . . .           1,500      1,639           1,000        885
2007. . . . . . .           1,500      1,657           1,000        942
2008. . . . . . .           1,500      1,736           1,000        978
2009. . . . . . .           1,500      1,796           1,000      1,001
2010 through 2014           7,500     10,362           5,000      5,580
</TABLE>
I.  COMMITMENTS  AND  CONTINGENCIES

     Other  contingencies  are discussed under Note A, Regulatory Accounting and
Major Customers and Other Concentration Risks and Note B, Vermont Yankee Nuclear
Power  Corporation  ("VYNPC")  and  Note  K  Long-Term  Power  Purchases.

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.  There  are  no  current  legislative  or  regulatory
initiatives  pending  or  anticipated  in  Vermont  to  pursue  deregulation.
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  would 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.

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.  We
have  estimated total future costs of the Company's future obligations under the
consent decree to be approximately $6.5 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 $13.3 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 is
expected  to  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.

JOINTLY-OWNED  FACILITIES
-------------------------
     The  Company  has  joint-ownership  interests  in  electric  generating and
transmission  facilities  at  December  31,  2004,  as  follows:
<TABLE>
<CAPTION>
                                                        Share of     Share of
                           Ownership     Share of     Utility     Accumulated
                          Interest   Capacity        Plant       Depreciation
                          ---------  ---------  ---------------  -------------
                           (In %)     (In MW)             (In thousands)
<S>                       <C>        <C>        <C>              <C>
Highgate . . . . . . . .       33.8       67.6  $        10,296  $       5,196
McNeil . . . . . . . . .       11.0        5.9            9,109          5,665
Stony Brook (No. 1). . .        8.8       31.0           10,377          9,408
Wyman (No. 4). . . . . .        1.1        6.8            1,980          1,443
Metallic Neutral Return.       59.4          -            1,563            867
</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 Operating
Expenses in the Consolidated Statements of Income under Company-owned generation
for  the  three listed generation plants and under Transmission for the Metallic
Neutral  Return  and  Highgate facilities.  Each participant in these facilities
must  provide  its  own  financing.

RATE  MATTERS
-------------
RETAIL  RATE CASES - On December 22, 2003, the VPSB approved our 2003 Rate Plan,
jointly  proposed  by  the  Company and the Vermont Department of Public Service
("DPS").  The  2003  Rate  Plan  covers  the  period  from 2003 through 2006 and
includes  the  following  principal  elements:
     The  Company's  rates  remained 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.  We  submitted a cost of service schedule supporting the 1.9 percent rate
increase  for  2005 in accordance with the plan.  That increase became effective
on  January  1,  2005  in  accordance  with  the plan.  If the Company's cost of
service filing in 2006 establishes that a rate increase of less than 0.9 percent
is  required  for  the  Company  to  meet  its revenue requirement, including an
allowed  return on equity of 10.5 percent, the Company will implement the lesser
rate  increase.  The VPSB retains the discretion to open an investigation of the
Company's  rates  at  any  time,  at  the  request  of  the  DPS, the request of
ratepayers,  or  on  its own volition.  Certain ratepayers requested the VPSB to
open  such  an  investigation  in connection with the Company's 1.9 percent rate
increase  for 2005.  The VPSB granted the request in December 2004, and then, at
our  request,  closed  and terminated its investigation in January 2005, with no
adverse  impact  on  the  Company's  rates.
     The  Company  may  seek  additional  rate  increases  in  extraordinary
circumstances,  such  as  severe  storm  repair  costs,  natural  disasters,
unanticipated  unit  outages,  or  significant  losses  of  customer  load.
     The  Company's  allowed  return  on  equity  is 10.5 percent for the period
January  1,  2003  through  December  31,  2006.  During  the  same  period, the
Company's  earnings  on  utility  operations  are  capped  at 10.5 percent.  The
Company  did not experience excess earnings in 2004.  Excess earnings in 2005 or
2006  will  be refunded to customers as a credit on customer bills or applied to
recover  regulatory  assets,  as  the  Department  directs.
     The  Company  carried  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  were  applied in 2004 to offset increased
costs.
     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  filed  with  the  VPSB  in 2004 a new fully allocated cost of
service  study  and  rate  re-design,  which  allocates  the  Company's  revenue
requirement  among  all customer classes on the basis of current costs.  The new
rate  design is 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 was restricted
until new rates went into effect, which occurred in January 2005.  Although this
restriction  has  expired,  we  have  no  plans  to make material investments in
non-utility  operations.

COMPETITION
-----------
     The Town of Rockingham, Vermont, located in the southeastern portion of our
service territory, has exercised an option to purchase a hydro-electric facility
partially located in the town (the "Bellows Falls facility").  If Rockingham, or
its  assignee,  is  successful  in  arranging  for purchase of the Bellows Falls
facility,  we  expect  to  conclude  an  agreement  to  permit  Rockingham to be
responsible  for  its  own  power  supply  needs,  with  the  Company  providing
distribution  and other services to the town's electric department.  In any such
agreement  the  Company  would continue to own its distribution plant located in
the  town  and  receive  distribution  services revenues sufficient to cover all
costs of providing services and all stranded costs associated with the Company's
present  obligation  to  provide  integrated  electric  service  to customers in
Rockingham.  Such  an  agreement  would  require  VPSB  approval.  The  Company
receives  annual  revenues  of  approximately  $3  million from its customers in
Rockingham.

OTHER  REGULATORY  MATTERS
--------------------------
     Central Vermont Public Service Corporation ("CVPS") is currently subject to
a  rate  investigation  by  the VPSB.  In that proceeding, the DPS has advocated
positions  that,  if  adopted  by  the  VPSB  and  applied to the Company, could
adversely  affect  our cash flows and operating results.  Areas of risk include:

*     The  Department's  advocacy  for  an  earnings  cap calculation that would
potentially  subject  all  items  on the balance sheet and income statement to a
retroactive review in order to determine whether the Company has met or exceeded
the earnings cap.  Our 2003 Rate Plan provides that the Company operate under an
earnings cap through 2006.  The Company calculates its earnings under the cap in
a manner that differs from the methodology advocated by the DPS in the CVPS rate
proceeding.

*     DPS  advocacy for elimination or reduction of costs of future removal that
are  currently  embedded  in depreciation rates and reflected in our cash flows.
The  methodology  we currently employ is consistent with that used in most other
regulatory  jurisdictions.

*     DPS  advocacy  for  reduced  rates  of  return  on  equity  for  CVPS.

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
hydro-electric  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
received  VPSB  approval  for,  and  has made additional dam improvements at the
facility.  The  VPSB has pending a regulatory proceeding to determine whether to
impose  regulatory  penalties  in  connection  with  the  1995 dam improvements.


J.     OBLIGATIONS  UNDER  TRANSMISSION  INTERCONNECTION  SUPPORT  AGREEMENT AND
OTHER  LEASES
     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  provides  2,000  megawatts  of capacity for
transmission  of  Hydro Quebec power 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,  2004,  the  present  value  of  the  Company's
obligation  is  approximately  $4.2  million.

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

                        Years ending
                       December 31
                     ---------------
                     (In thousands)
<S>                  <C>
2005. . . . . . . .  $           383
2006. . . . . . . .              383
2007. . . . . . . .              383
2008. . . . . . . .              383
2009. . . . . . . .              383
Total for 2010-2015            2,299
    Total . . . . .  $         4,216
                     ===============
</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
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.
<TABLE>
<CAPTION>

Purchased  power  expense  by  significant  contract  supplier
for the Years ended December 31,
                        2004     2003     2002
                       -------  -------  -------
In thousands
<S>                    <C>      <C>      <C>
Hydro Quebec. . . . .  $48,309  $46,367  $47,914
Morgan Stanley. . . .   11,106   59,311   71,259
VYNPC . . . . . . . .   33,331   38,109   34,385
Small Power Producers   15,832   15,277   14,393
Stony Brook . . . . .    1,696    2,222    1,766
</TABLE>

Information,  including  estimates  for the Company's portion of certain minimum
costs,  with  regard  to  significant  purchased power contracts of this type in
effect  during  2004  follow.

VERMONT  YANKEE.
     The  Company has a long-term power purchase contract with VYNPC, 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, including costs to
decommission the plant, 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  VYNPC  sale  of  its  nuclear power plant to ENVY also calls for ENVY,
through its power contract with VYNPC, 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 ("PPA"), including projected
charges  for  the  years  indicated,  follows:
<TABLE>
<CAPTION>

                                             VYNPC
                                        Contract
                                       ----------
<S>                                    <C>         <C>
(Dollars in thousands except per KWh)
Capacity acquired . . . . . . . . . .     106 MW
Contract period expires . . . . . . .       2012
Company's share of output . . . . . .         20%
Annual energy charge. . . . . . . . .       2004   $32,838
  estimated . . . . . . . . . . . . .  2005-2012   $31,949
Average cost per KWh. . . . . . . . .       2004   $ 0.044
  estimated . . . . . . . . . . . . .  2005-2012   $ 0.041
</TABLE>
 Prices under the PPA range from $39 to $45 per megawatt hour.  The PPA contains
a  provision  known  as  the  "low  market adjuster," which calls for a downward
adjustment  in  the  contract  price  if  market  prices for electricity fall by
defined  amounts  beginning  November 2005.  If market prices rise, however, PPA
prices  are  not  adjusted  upward  in  excess  of  the  PPA  price.

     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  its  share  of  the Vermont Yankee power plant sale
proceeds, approximately $8.2 million, during October 2003, and used the proceeds
to  retire  debt.

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
"VJO 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 VJO Contract
participant  fails  to  meet  its  obligation  under the VJO Contract with Hydro
Quebec, the remaining contract participants, including the Company, will step-up
to  the  defaulting  participant's  share  on  a  prorated  basis.

     In accordance with guidance set forth in FIN 45, the Company is required to
disclose  the  "maximum  potential  amount of future payments (undiscounted) the
guarantor  could  be  required to make under the guarantee."  Such disclosure is
required  even  if  the  likelihood  of  triggering the guarantee is remote.  In
regards  to the "step-up" provision in the VJO Contract, the Company must assume
that  all  members  of  the  VJO simultaneously default in order to estimate the
"maximum  potential"  amount of future payments.  The Company believes this is a
highly  unlikely  scenario  given that the majority of VJO members are regulated
utilities  with  regulated  cost  recovery.  Each  VJO  participant has received
regulatory  approval  to  recover the cost of this purchased power.  Despite the
remote  chance  that  such  an event could occur, the Company estimates that its
undiscounted  purchase  obligation  would  be approximately $880 million for the
remainder  of  the  contract,  assuming that all members of the VJO defaulted by
January  1,  2005  and remained in default for the duration of the contract.  In
such  a scenario, the Company would then own the power and could seek to recover
its costs from the defaulting members, its retail customers, or resell the power
in the wholesale power markets in New England.  The range of outcomes (full cost
recovery,  potential  loss  or  potential  profit)  would be highly dependent on
Vermont  regulation  and  wholesale  market  prices  at  the  time.

     Hydro  Quebec  also has the right to reduce the load factor from 75 percent
to 65 percent under the VJO Contract a total of three times over the life of the
contract.  The  Company  can  delay  such  reduction  by  one year under the VJO
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  net  cost  of  Hydro Quebec's exercise of its option increased power supply
expense  during  2003  by  approximately  $4.5  million.

     During  2003,  Hydro  Quebec exercised its second option to reduce the load
factor  for 2004 at an incremental expense of approximately $1.8 million.  Hydro
Quebec  exercised  its third option in 2004 for deliveries occurring principally
during  2005  that  we  estimate  will  result in an incremental expense of $1.8
million  based  on current market prices that could change by a material amount.
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  VJO  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.

     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, and there are no generation plant
outage  risks,  though  there  are  outage risks related to the operation of the
transmission  system.

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

                                                                          THE VJO CONTRACT
                                                              SCHEDULE B                SCHEDULE C3
                                          -------------------------------------       -------------
                                                           (Dollars in thousands except per KWh)
<S>                       <C>                                    <C>            <C>       <C>      <C>
Capacity acquired. . . .                                 68 MW                                46 MW
Contract period. . . . .                             1995-2015                            1995-2015
Minimum energy purchase.                                65%-75%                              65%-75%
(annual load factor)
Annual energy charge . .                                  2004   $      9,868             $ 6,812
  estimated. . . . . . .                             2005-2015   $     13,756        (1)  $ 9,400   (1)
Annual capacity charge .                                  2004   $     16,813             $11,613
  estimated. . . . . . .                             2005-2015   $     17,121        (1)  $11,699   (1)
Average cost per KWh . .                                  2004   $      0.073             $ 0.076
  estimated. . . . . . .                             2005-2015   $      0.064        (2)  $ 0.064   (2)
</TABLE>
(1)  Estimated  average  includes  load  factor reduction to 65 percent in 2005.
 (2)  Estimated  average  in nominal dollars levelized over the period indicated
     includes  amortization  of  payments  to  Hydro  Quebec.

     Under  a  separate  arrangement established in 1996 (the "9701 agreement"),
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 VJO
Contract.  The  cumulative  amount  of energy purchased under the 9701 agreement
shall  not  exceed  950,000  MWh.  Hydro  Quebec's  option  to  curtail  energy
deliveries  pursuant  to  the VJO 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 VJO 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, 2004, Hydro Quebec had purchased or
called  to  purchase  566,000  MWh  under  option  B.

     The  Company  believes  that  it  is  probable  that Hydro Quebec will call
options  A and B for 2005, and has purchased replacement power for approximately
half  of  the  expected  call  at  an  incremental  cost  of  $1.1  million.

     In  2004,  Hydro  Quebec  exercised  option  A and option B, and called for
deliveries  to  third  parties  at a net expense to the Company of approximately
$3.2  million,  including  capacity  charges.

     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.

MORGAN  STANLEY  CONTRACT.
     In  February  1999, the Company entered into a contract with Morgan Stanley
Capital Group, Inc. (the "Morgan Stanley Contract").  In August 2002, the Morgan
Stanley  Contract  was  modified  and extended to December 31, 2006.  The Morgan
Stanley Contract price is substantially below current market prices.  The Morgan
Stanley  Contract  currently  supplies approximately 16 percent of the Company's
estimated  customer  demand  ("load").

     Under  the  Morgan  Stanley  Contract,  on  a  daily  basis,  and at Morgan
Stanley's discretion, we sell power to Morgan Stanley from part of our portfolio
of  power  resources  at  predefined  operating  and pricing parameters.  Morgan
Stanley  sells  to the Company, at a predefined price, power sufficient to serve
pre-established  load  requirements.  We  remain  responsible  for  resource
performance  and availability.  The Morgan Stanley Contract provides no coverage
against  major unscheduled power supply outages.  Beginning January 1, 2004, the
Company reduced the power that it sells pursuant to the Morgan Stanley Contract.
The  output  of some of our power-supply resources, including purchases pursuant
to  our  Hydro  Quebec  and  VYNPC  contracts, which were sold to Morgan Stanley
through  2003,  are  no  longer  included  in the Morgan Stanley Contract.  This
reduction in sales to Morgan Stanley reduced wholesale revenues by approximately
$56.2  million  during 2004 when compared with 2003, and correspondingly reduced
power  supply expense by a similar amount.  This change did not adversely affect
the  Company's  operating results or its opportunity to earn its allowed rate of
return  during  2004.

     The  Company  purchased  or  expects to purchase the following amounts from
Morgan  Stanley  for  the  years  indicated:
<TABLE>
<CAPTION>
                      The  Morgan  Stanley
                           Contract
                         -------------
<S>                      <C>            <C>   <C>
Capacity acquired*. . .       1-182 MW
Contract period expires           2006
Annual energy charge :.
2004                     $11.1 million
2005 estimate . . . . .  $12.6 million
2006 estimate . . . . .  $10.2 million
</TABLE>
*Capacity ranges between 0 and 182 MW over the remaining contract life depending
on  the  scheduled  hour.

     Beginning  January  1, 2004, the Company reduced the power that it sells to
Morgan  Stanley  under  the  contract.  The reduction in sales lowered wholesale
revenues  by  approximately  $56  million, and power supply expense by a similar
amount.  The  change  did not adversely affect the Company's opportunity to earn
its  allowed  rate  of  return  during  2004.

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

UNIT  PURCHASES.
     Under  a long-term contract with Massachusetts Municipal Wholesale Electric
Company  ("MMWEC"),  the  Company  is  purchasing a percentage of the electrical
output  of  the Stony Brook production plant constructed by MMWEC.  The contract
obligates  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 plant is operating, for the life of
the  unit.  The  cost of power obtained under this long-term contract, including
payments  required  when  the 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 this purchased power
contract  in  effect  during  2004  follows:

<TABLE>
<CAPTION>

                                            STONY
                                            BROOK
                                   -----------------------
                                   (Dollars in thousands)
<S>                                <C>
Plant capacity. . . . . . . . . .                352.0 MW
Company's share of output . . . .                    4.40%
Company's annual share of:
  Interest. . . . . . . . . . . .  $                  107
  Other debt service. . . . . . .                     466
  Other capacity. . . . . . . . .                     537
Total annual capacity . . . . . .  $                1,110
                                   =======================

Company's share of long-term debt  $                1,304
</TABLE>

INDEPENDENT  POWER  PRODUCERS.
     The  Company  receives  power  from  several  independent  power  producers
("IPPs").  These plants use water, biomass and trash as fuel.  Most of the power
comes  through  a  state-appointed  purchasing  agent,  Vermont  Electric  Power
Producers  Inc.  ("VEPPI"),  which  assigns power to all Vermont utilities under
VPSB  rules.  In  2004,  the  Company received 124,617 MWh under these long-term
contracts at a cost of $15.8 million.  These IPP purchases amount to 6.0 percent
of  the  Company's  total  MWh  purchased  and  11.5  percent  of purchase power
expenses.  Estimated  purchases  from  IPPs  are expected to be $15.9 million in
2005,  $16.5  million  in 2006, $17.4 million in 2007, $17.3 million in 2008 and
$15.5  million  in  2009.


L.  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>

 Amounts  in  thousands  except per share data                   2004 Quarter ended
                                                  MARCH      JUNE     SEPTEMBER   DECEMBER    TOTAL
                                                 --------  --------  -----------  ---------  --------
<S>                                              <C>       <C>       <C>          <C>        <C>
Operating revenues. . . . . . . . . . . . . . .  $63,123   $54,585   $   54,926   $  56,182  $228,816
Operating income. . . . . . . . . . . . . . . .    5,019     2,776        4,595       3,088    15,478
Net income-continuing operations. . . . . . . .  $ 3,740   $ 1,783   $    3,392   $   2,144  $ 11,059
Net income-discontinued operations. . . . . . .       (6)       (1)          (2)        534       525
Net Income applicable to common stock . . . . .  $ 3,734   $ 1,782   $    3,390   $   2,678  $ 11,584
                                                 ========  ========  ===========  =========  ========
Basic earnings per share from:
  Continuing operations . . . . . . . . . . . .  $  0.74   $  0.35   $     0.67   $    0.42  $   2.18
  Discontinued operations . . . . . . . . . . .        -         -            -        0.10      0.10
  Basic earnings per share. . . . . . . . . . .  $  0.74   $  0.35   $     0.67   $    0.52  $   2.28
                                                 ========  ========  ===========  =========  ========
  Weighted average common shares outstanding. .    5,046     5,072        5,089       5,124     5,083
Diluted earnings per share from:
  Continuing operations . . . . . . . . . . . .  $  0.72   $  0.34   $     0.65   $    0.39  $   2.10
  Discontinued operations . . . . . . . . . . .        -         -            -        0.10      0.10
  Diluted earnings per share. . . . . . . . . .  $  0.72   $  0.34   $     0.65   $    0.49  $   2.20
                                                 ========  ========  ===========  =========  ========
  Weighted average common and common equivalent    5,205     5,228        5,251       5,282     5,254
shares outstanding
</TABLE>


<TABLE>
<CAPTION>
                                                             2003  Quarter  ended
                                                MARCH      JUNE    SEPTEMBER   DECEMBER    TOTAL
                                               --------  --------  ----------  ---------  --------
<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
                                               -------  -------  ----------  ---------  --------
<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>

REPORT  OF  INDEPENDENT  REGISTERED  PUBLIC  ACCOUNTING  FIRM

To  the  Board  of  Directors  and  Stockholders  of
Green  Mountain  Power  Corporation

We  have  audited the accompanying consolidated balance sheets of Green Mountain
Power  Corporation  and subsidiaries (the "Company") as of December 31, 2004 and
2003,  and  the  related  consolidated  statements  of  income,  changes  in
shareholders'  equity  and  comprehensive income, and cash flows for each of the
three  years  in the period ended December 31, 2004.  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 the standards of the Public Company
Accounting  Oversight  Board  (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,  such consolidated financial statements present fairly, in all
material  respects,  the  financial position of Green Mountain Power Corporation
and  subsidiaries  as  of  December  31, 2004 and 2003, and the results of their
operations  and their cash flows for each of the three years in the period ended
December  31,  2004, in conformity with accounting principles generally accepted
in  the  United  States  of  America.

We  have  also  audited,  in accordance with the standards of the Public Company
Accounting  Oversight  Board (United States), the effectiveness of the Company's
internal  control over financial reporting as of December 31, 2004, based on the
criteria  established  in  Internal  Control-Integrated  Framework issued by the
Committee  of Sponsoring Organizations of the Treadway Commission and our report
dated March 21, 2005 expressed an unqualified opinion on management's assessment
of  the effectiveness of the Company's internal control over financial reporting
and  an  adverse  opinion on the effectiveness of the Company's internal control
over  financial  reporting  because  of  a  material  weakness.

DELOITTE  &  TOUCHE  LLP
Boston,  Massachusetts
March  21,  2005



<PAGE>
REPORT  OF  INDEPENDENT  REGISTERED  PUBLIC  ACCOUNTING  FIRM

To  the  Board  of  Directors  and  Stockholders  of
Green  Mountain  Power  Corporation

We  have  audited  management's  assessment,  included  in  the  accompanying
Management's  Report  on  Internal  Control Over Financial Reporting, that Green
Mountain  Power  Corporation  and  subsidiaries (the "Company") did not maintain
effective  internal  control  over  financial reporting as of December 31, 2004,
because  of  the  effect  of  the  material  weakness identified in management's
assessment  based  on  the  criteria  established in Internal Control-Integrated
Framework  issued  by  the Committee of Sponsoring Organizations of the Treadway
Commission.  The  Company's  management is responsible for maintaining effective
internal  control  over  financial  reporting  and  for  its  assessment  of the
effectiveness  of internal control over financial reporting.  Our responsibility
is  to  express  an  opinion  on  management's  assessment and an opinion on the
effectiveness  of  the Company's internal control over financial reporting based
on  our  audit.

We  conducted  our  audit in accordance with the standards of the Public Company
Accounting  Oversight  Board  (United  States).  Those standards require that we
plan  and  perform  the  audit  to  obtain  reasonable  assurance  about whether
effective  internal  control  over  financial  reporting  was  maintained in all
material  respects.  Our  audit  included obtaining an understanding of internal
control  over  financial  reporting, evaluating management's assessment, testing
and  evaluating  the design and operating effectiveness of internal control, and
performing  such  other  procedures  as  we  considered  necessary  in  the
circumstances.  We  believe  that  our audit provides a reasonable basis for our
opinions.

A  company's internal control over financial reporting is a process designed by,
or  under  the  supervision  of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's  board  of  directors,  management,  and  other  personnel  to provide
reasonable  assurance  regarding  the reliability of financial reporting and the
preparation  of  financial  statements  for external purposes in accordance with
generally  accepted  accounting  principles.  A  company's internal control over
financial  reporting  includes those policies and procedures that (1) pertain to
the  maintenance  of  records  that, in reasonable detail, accurately and fairly
reflect  the  transactions  and  dispositions  of the assets of the company; (2)
provide  reasonable  assurance  that  transactions  are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting  principles,  and  that  receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection  of  unauthorized  acquisition,  use,  or disposition of the company's
assets  that  could  have  a  material  effect  on  the  financial  statements.

Because  of  the  inherent  limitations  of  internal  control  over  financial
reporting,  including  the  possibility  of  collusion  or  improper  management
override  of  controls,  material misstatements due to error or fraud may not be
prevented or detected on a timely basis.  Also, projections of any evaluation of
the  effectiveness  of  the  internal control over financial reporting to future
periods  are subject to the risk that the controls may become inadequate because
of  changes in conditions, or that the degree of compliance with the policies or
procedures  may  deteriorate.

A  material  weakness is a significant deficiency, or combination of significant
deficiencies,  that  results  in  more  than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be prevented
or  detected.  The  following material weakness has been identified and included
in  management's  assessment:  Deficiencies  existed  in  both  the  design  and
operating effectiveness of controls associated with the Company's accounting for
income  taxes.  These deficiencies include a failure to timely reconcile account
balances  including the preparation of a tax balance sheet, incorrect accounting
for  tax  accounts  related  to  the  contributions  in advance of construction,
certain  tax credits and non-regulated tax accounts, and insufficient dedication
of  resources to the preparation, supervision and review of tax accounting.  The
deficiencies  resulted  in  an  immaterial  adjustment  to  properly present the
financial  statements  in  accordance  with  generally  accepted  accounting
principles.  The deficiencies were concluded to represent a material weakness in
the  aggregate due to the potential for additional misstatements and the lack of
mitigating  controls  to  detect  the misstatements.  This material weakness was
considered  in determining the nature, timing, and extent of audit tests applied
in  our  audit  of  the consolidated financial statements as of and for the year
ended  December  31,  2004,  of  the Company and this report does not affect our
report  on  such  financial  statements.

In  our  opinion,  management's  assessment  that  the  Company did not maintain
effective  internal control over financial reporting as of December 31, 2004, is
fairly  stated,  in  all material respects, based on the criteria established in
Internal  Control-Integrated  Framework  issued  by  the Committee of Sponsoring
Organizations  of  the Treadway Commission.  Also in our opinion, because of the
effect  of  the  material  weakness  described  above  on the achievement of the
objectives  of  the  control  criteria, the Company has not maintained effective
internal  control over financial reporting as of December 31, 2004, based on the
criteria  established  in  Internal  Control-Integrated  Framework issued by the
Committee  of  Sponsoring  Organizations  of  the  Treadway  Commission.

We  have  also  audited,  in accordance with the standards of the Public Company
Accounting  Oversight  Board  (United  States),  the  consolidated  financial
statements  as  of  and for the year ended December 31, 2004, of the Company and
our  report  dated  March  21,  2005  expressed  an unqualified opinion on those
financial  statements.

DELOITTE  &  TOUCHE  LLP
Boston,  Massacusetts
March  21,  2005




<PAGE>

ITEM  9.  CHANGES  IN  AND  DISAGREEMENTS  WITH  ACCOUNTANTS
         ON  ACCOUNTING  AND  FINANCIAL  DISCLOSURE
None.

ITEM  9A.  CONTROLS  AND  PROCEDURES
Evaluation  of  Disclosure  Controls  and  Procedures
-----------------------------------------------------
     Pursuant  to  Rule  13a-15(b) under the Securities Exchange Act of 1934, we
carried  out  an evaluation, with the participation of our management, including
our chief executive officer and chief 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  chief  executive officer and chief
financial officer concluded that our disclosure controls and procedures were not
effective  as  of  such  date  because  we identified a material weakness in our
internal control over financial reporting in our accounting for income taxes, as
described  below.  Due  to  this  material  weakness, in preparing our financial
statements  at and for the year ended December 31, 2004, we performed additional
procedures  relating  to  our  accounting  for  income taxes to ensure that such
financial  statements  were stated fairly in all material respects in accordance
with  generally  accepted  accounting  principles  in  the  United  States.

Management's  Report  on  Internal  Control  Over  Financial  Reporting
     Our  management  is  responsible  for establishing and maintaining adequate
internal  control  over  financial  reporting,  as such term is defined in Rules
13a-15(f)  and  15d-15(f) under the Securities Exchange Act of 1934, as amended.
Under  the  supervision  and with the participation of our management, including
our  chief  executive  officer  and  chief  financial  officer,  we conducted an
evaluation of the effectiveness of our internal control over financial reporting
based  on  the  framework in "Internal Control - Integrated Framework" issued by
the  Committee of Sponsoring Organizations of the Treadway Commission.  Based on
this assessment under the criteria for effective internal control over financial
reporting  described in "Internal Control - Integrated Framework," issued by the
Committee  of  Sponsoring  Organizations  of the Treadway Commission, management
determined  that as of December 31, 2004, we did not maintain effective internal
control  over  financial  reporting,  due  to a material weakness as a result of
deficiencies  in  both  the  design  and  operating  effectiveness  of  controls
associated  with  our accounting for income taxes.  These deficiencies include a
failure  to timely reconcile account balances including the preparation of a tax
balance  sheet,  incorrect  accounting  for  tax  accounts  related  to  the
contributions  in advance of construction, certain tax credits and non-regulated
tax  accounts,  and  insufficient  dedication  of resources for the preparation,
supervision  and  review of tax accounting.  The material weakness identified by
management  resulted  in  an immaterial reclassification of certain deferred tax
liabilities  to other deferred credit accounts on the Company's balance sheet as
of December 31, 2003.  These deficiencies were concluded to represent a material
weakness due to the potential for additional misstatements and the lack of other
mitigating  controls  to  detect  the  misstatements.

     Management's  assessment  of the effectiveness of our internal control over
financial  reporting  as  of  December  31,  2004 has been audited by Deloitte &
Touche LLP, an independent registered public accounting firm, as stated in their
report  which  is  included  herein.

Management's  Remediation  Plans
     In  addition  to the required use of a tax balance sheet in accordance with
FAS  109,  we  intend to take the following actions to improve and remediate the
material  weakness  in  our  internal  control  over  financial  reporting:
     We will implement additional and enhanced internal reviews in the tax area,
including  tax  rate  reconciliations,  commencing in the first quarter of 2005.
     We will retain and implement an additional review by outside experts on tax
accounting,  including  regulatory  tax items, on a periodic basis commencing in
the  first  quarter  of  2005.
     We  will  implement  new  tax  accounting software to improve controls over
complex  spreadsheet  models  during  the  latter  half  of 2005.
We  believe  these  actions  will  strengthen  our  internal  control  over
financial  reporting and address the material weakness identified by management.
Our management has committed what it believes to be sufficient resources to this
remediation  plan,  but  there can be no assurance that all control deficiencies
will  be  remediated  on  a  timely basis.  The Audit Committee will monitor the
progress  of  our  remediation  efforts.
     Any failure to implement and maintain the improvements in the controls over
our  financial  reporting,  or difficulties encountered in the implementation of
these  improvements  in  our  controls, could cause us not to meet our reporting
obligations.

Changes  in  Internal  Controls
     We continue to review, revise and improve the effectiveness of our internal
control  over financial reporting, including strengthening our internal controls
relating to accounting for income taxes as described above.  Except as described
above, we have made no significant change in our internal control over financial
reporting in connection with our fourth quarter evaluation that would materially
affect,  or is reasonably likely to materially affect, our internal control over
financial  reporting.

<PAGE>

                                    PART III

ITEM  10

     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 will be set forth under the captions "Election
of  Directors,"  "Nominees for Election to the Board of Directors," "Information
About  Our Board of Directors" and "Section 16(a) Beneficial Ownership Reporting
Compliance,"  in the Company's definitive proxy statement relating to its annual
meeting  of  stockholders  to  be  held  on  May  23, 2005.  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 April 2005.

     Because  our  common  stock  is  listed on the New York Stock Exchange (the
"NYSE"),  our  chief  executive officer is required to make, and he has made, an
annual  certification to the NYSE stating that he was not aware of any violation
by  us  of  the  corporate  governance listing standards of the NYSE.  Our chief
executive officer made his annual certification to that effect to the NYSE as of
June  7, 2004.  In addition, we have filed, as exhibits to this Annual Report on
Form  10-K,  the certifications of our principal executive officer and principal
financial  officer required under Sections 906 and 302 of the Sarbanes Oxley Act
of 2002 to be filed with the SEC regarding the quality of our public disclosure.

ITEMS  11,  12,  13  AND  14

     The  information  called  for  by  Items  11,  12,  13  and  14, "Executive
Compensation," "Security Ownership of Certain Beneficial Owners and Management,"
"Certain Relationships and Related Transactions," and "Principal Accounting Fees
and  Services," will be set forth under the captions "Executive Compensation and
Other  Information,"  "Compensation Committee Report on Executive Compensation,"
"Pension  Plan  Information  and  Other  Benefits,"  "Equity  Compensation  Plan
Information,"  "Securities  Ownership  of  Certain  Beneficial  Owners  and
Management,"  and  "Audit  Committee  Report"  in the Company's definitive proxy
statement  relating  to its annual meeting of stockholders to be held on May 23,
2005.  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  April  2005.


<PAGE>
ITEM  15.  EXHIBITS,  FINANCIAL  STATEMENT  SCHEDULES,  AND  REPORTS ON FORM 8-K
     List  of  documents  filed  as  part  of  this  Form  10-K:
     (1)     Financial  Statements.  See  the  Index  to the Company's financial
statements  set  forth  in  Item  8  hereof.
(2)     Financial  Statement  Schedules.  N/A.
(3)     Exhibits.  See the Exhibit Index set forth at the end of this Form 10-K.

<PAGE>

                                   SIGNATURES

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

                                             GREEN  MOUNTAIN  POWER  CORPORATION



    Date:  March  28,  2005               By:/s/  Christopher  L.  Dutton______
                                             ----------------------------------
                                             Christopher  L.  Dutton,  President
                                             and  Chief  Executive  Officer



     Pursuant  to  the requirements of the Securities Exchange Act of 1934, this
report  has  been  signed  below  by  the  following  persons  on  behalf of the
registrant  and  in  the  capacities  and  on  the  dates  indicated.

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


 /s/  Christopher  L. Dutton_  President, Chief Executive         March 28, 2005
-----------------------------
   Christopher  L.  Dutton         Officer,  and  Director


 /s/  Mary  G.  Powell_______  Chief Operating Officer,           March 28, 2005
-----------------------------
   Mary  G.  Powell             Senior  Vice  President

 /s/  Robert  J.  Griffin  Chief  Financial  Officer,  Vice      March  28, 2005
-------------------------
   Robert  J.  Griffin          President  and  Treasurer

     *Nordahl  L.  Brue         )     Chairman  of  the  Board

     *Elizabeth  Bankowski     )

     *William  H.  Bruett       )

     *Merrill  O.  Burns        )

     *David  R.  Coates         )     Directors

     *Kathleen  C.  Hoyt        )

     *Euclid  A.  Irving        )

     *Marc  A.  vanderHeyden    )


*By:  _/s/  Christopher L. Dutton                                 March 28, 2005
      ---------------------------
        Christopher  L.  Dutton
        (Attorney  -  in  -  Fact)


<TABLE>
<CAPTION>

     ITEM  15(A)3  AND  ITEM  15C.  EXHIBITS               SEC  docket
                    incorporated
                    by  reference
     Exhibit               or  Page  filed

  Number    Description                                                         Exhibit        herewith
----------  -----------------------------------------------------------------  ----------  ----------------
<C>         <S>                                                                <C>         <C>
       3-1  Amended and Restated Articles of Incorporation dated. . . . . . .          3A  Form 10-Q
            May 27, 2004.                                                                  June 2004
       3.b  By-laws of the Company, as amended February 10, 1997. . . . . . .         3.b  Form 10-K 1996
                                                                                                   (1-8291)
       3.c  By-laws of the Company, as amended December 8, 2003.. . . . . . .           3  Form 8-K Dec. 8
                                                                                              2003 (1-8291)
     4.b.1  Indenture of First Mortgage and Deed of Trust dated . . . . . . .         4.b          2-27300
            as of February 1, 1955.
     4.b.2  First Supplemental Indenture dated as of April 1, 1961. . . . . .       4.b.2          2-75293
     4.b.3  Second Supplement Indenture dated as of January 1, 1966.. . . . .       4.b.3          2-75293
     4.b.4  Third Supplemental Indenture dated as of July 1, 1968.. . . . . .       4.b.4          2-75293
     4.b.5  Fourth Supplemental Indenture dated as of October 1, 1969.. . . .       4.b.5          2-75293
     4.b.6  Fifth Supplemental Indenture dated as of December 1, 1973.. . . .       4.b.6          2-75293
     4.b.7  Seventh Supplemental Indenture dated as of August 1, 1976.. . . .       4.b.7          2-99643
     4.b.8  Eighth Supplemental Indenture dated as of December 1, 1979. . . .       4.b.8          2-99643
     4.b.9  Ninth Supplemental Indenture dated as of July 15, 1985. . . . . .       4.b.9          2-99643
    4.b.10  Tenth Supplemental Indenture dated as of June 15, 1989. . . . . .      4.b.10  Form 10-K 1989
                                                                                                   (1-8291)
    4.b.11  Eleventh Supplemental Indenture dated as of September 1, 1990.. .      4.b.11  Form 10-Q Sept.
                                                                                              1990 (1-8291)
    4.b.12  Twelfth Supplemental Indenture dated as of March 1, 1992. . . . .      4.b.12  Form 10-K 1991
                                                                                                   (1-8291)
    4.b.13  Thirteenth Supplemental Indenture dated as of March 1, 1992.. . .      4.b.13  Form 10-K 1991
                                                                                                   (1-8291)
    4.b.14  Fourteenth Supplemental Indenture dated as of November 1, 1993. .      4.b.14  Form 10-K 1993
                                                                                                   (1-8291)
    4.b.15  Fifteenth Supplemental Indenture dated as of November 1, 1993.. .      4.b.15  Form 10-K 1993
                                                                                                   (1-8291)
    4.b.16  Sixteenth Supplemental Indenture dated as of December 1, 1995.. .      4.b.16  Form 10-K 1995
                                                                                                   (1-8291)
    4.b.17  Revised form of Indenture as filed as an Exhibit to . . . . . . .      4.b.17  Form 10-Q Sept.
            Registration Statement No. 33-59383.                                              1995 (1-8291)
    4.b.18  Credit Agreement by and among Green Mountain Power, The Bank. . .      4.b.18  Form 10-K 1997
            of Nova Scotia, State Street Bank and Trust Company, Fleet                             (1-8291)
            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 December 1, 2002..      4.b.19  Form 10-K 2002
                                                                                                   (1-8291)
      10.a  Form of Insurance Policy issued by Pacific Insurance Company, . .        10.a          33-8146
            with respect to indemnification of Directors and Officers.
    10.b.1  Firm Power Contract dated September 16, 1958, between the . . . .        13.d          2-27300
            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 between the. . .      13.f.1          2-49697
            Company and Vermont Yankee Nuclear Power Corporation.
 10.b.3(a)  Amendment, dated April 15, 1983, to Power Contract between the. .   10.b.3(a)          33-8164
            Company and Vermont Yankee Nuclear Power Corporation.
 10.b.3(b)  Additional Power Contract, dated February 1, 1984, between the. .   10.b.3(b)          33-8164
            Company and Vermont Yankee Nuclear Power Corporation.
    10.b.4  Capital Funds Agreement, dated February 1, 1968, between the. . .        13.e          2-34346
            Company and Vermont Yankee Nuclear Power Corporation.
    10.b.5  Amendment, dated March 12, 1968, to Capital Funds Agreement . . .        13.f          2-34346
            between the Company and Vermont Yankee Nuclear Power Corporation.
    10.b.6  Guarantee Agreement, dated November 5, 1981, of the Company for .      10.b.6          2-75293
            its proportionate share of the obligations of Vermont Yankee
            Nuclear Power Corporation under a $40 million loan arrangement.
    10.b.7  Three-Party Power Agreement among the Company, VELCO and. . . . .        13.i          2-49697
            Central Vermont Public Service Corporation
            dated November 19, 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 Company, VELCO . . .      10.b.9          2-49697
            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 al, to enter. . . .        5.16          2-52900
            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 Company and. . . . .        13.v          2-49697
            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 amended . . . . .     10.b.20          33-8164
            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 the sale of firm .     10.b.28          33-8164
            power and energy by the Power Authority of the State of
            New York to the Vermont Public Service Board.
   10.b.30  Bulk Power Purchase Contract dated April 7, 1976, between . . . .     10.b.32          2-75293
            VELCO and the Company.
   10.b.33  Agreement amending New England Power Pool Agreement dated as. . .     10.b.33          33-8164
            of December 1, 1981, providing for use of transmission inter-
            connection between New England and Hydro Quebec.
   10.b.34  Phase I Transmission Line Support Agreement dated . . . . . . . .     10.b.34          33-8164
            as of December 1, 1981, and Amendment No. 1 dated as of
            June 1, 1982, between VETCO and participating New England
            utilities for construction, use and support of Vermont
            facilities of transmission interconnection between
            New England and Hydro Quebec.
   10.b.35  Phase I Terminal Facility Support Agreement dated as of . . . . .     10.b.35          33-8164
            December 1, 1981, and Amendment No. 1 dated as of June 1,
            1982, between New England Electric Transmission Corporation
            and participating New England utilities for construction,
            use and support of New Hampshire facilities of transmission
            interconnection between New England and Hydro Quebec.
   10.b.36  Agreement with respect to use of Quebec Interconnection . . . . .     10.b.36          33-8164
            dated as of December 1, 1981, among participating New England
            utilities for use of transmission interconnection between
            New England and Hydro Quebec.
   10.b.39  Vermont Participation Agreement for Quebec Interconnection. . . .     10.b.39          33-8164
            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 trans-
            mission interconnection between New England and Hydro Quebec.
   10.b.40  Vermont Electric Transmission Company, Inc. Capital Funds . . . .     10.b.40          33-8164
            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 interconnection between
            New England and Hydro Quebec.
   10.b.41  VETCO Capital Funds Support Agreement dated as of July 15,. . . .     10.b.41          33-8164
            1982, between VELCO and participating Vermont utilities for
            allocation of VELCO's obligation to VETCO under the Capital
            Funds Agreement.
   10.b.42  Energy Banking Agreement dated March 21, 1983, among Hydro. . . .     10.b.42          33-8164
            Quebec, VELCO, NEET and participating New England utilities
            acting by and through the NEPOOL Management Committee for
            terms of energy banking between participating New England
            utilities and Hydro Quebec.
   10.b.43  Interconnection Agreement dated March 21, 1983, between . . . . .     10.b.43          33-8164
            Hydro Quebec and participating New England utilities acting
            by and through the NEPOOL Management Committee for terms and
            conditions of energy transmission between New England and
            Hydro Quebec.
   10.b.44  Energy Contract dated March 21, 1983, between Hydro Quebec. . . .     10.b.44          33-8164
            and participating New England utilities acting by and through
            the NEPOOL Management Committee for purchase of surplus energy
            from Hydro Quebec.
   10.b.50  Agreement for Joint Ownership, Construction and Operation of. . .     10.b.50          33-8164
            the Highgate Transmission Interconnection, dated August 1,
            1984, between certain electric distribution companies,
            including the Company.
   10.b.51  Highgate Operating and Management Agreement, dated as of. . . . .     10.b.51          33-8164
            August 1, 1984, among VELCO and Vermont electric-utility
            companies, including the Company.
   10.b.52  Allocation Contract for Hydro Quebec Firm Power dated July 25,. .     10.b.52          33-8164
            1984, between the State of Vermont and various Vermont
            electric utilities, including the Company.
   10.b.53  Highgate Transmission Agreement dated as of August 1, 1984, . . .     10.b.53          33-8164
            between the Owners of the Project and various Vermont electric
            distribution companies.
   10.b.61  Agreements entered in connection with Phase II of the NEPOOL/ . .     10.b.61          33-8164
            Hydro Quebec + 450 KV HVDC Transmission Interconnection.
   10.b.62  Agreement between UNITIL Power Corp. and the Company to sell. . .     10.b.62          33-8164
            23 MW capacity and energy from Stony Brook Intermediate
            Combined Cycle Unit.
   10.b.68  Firm Power and Energy Contract dated December 4, 1987, between. .     10.b.68  Form 10-K 1992
            Hydro Quebec and participating Vermont utilities, including                            (1-8291)
            the Company, for the purchase of firm power for up to
            thirty years.
   10.b.69  Firm Power Agreement dated as of October 26, 1987, between. . . .     10.b.69  Form 10-K 1992
            Ontario Hydro and Vermont Department of Public Service.                                (1-8291)
   10.b.70  Firm Power and Energy Contract dated as of February 23, 1987, . .     10.b.70  Form 10-K 1992
            between the Vermont Joint Owners of the Highgate facilities                            (1-8291)
            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 February 23, 1987,. . . . .     10.b.71  Form 10-K 1992
            between the Vermont Joint Owners of the Highgate facilities                            (1-8291)
            and Hydro Quebec.
   10.b.72  Participation Agreement dated as of April 1, 1988, between. . . .     10.b.72  Form 10-Q
            Hydro Quebec and participating Vermont utilities, including                    June 1988
            the Company, implementing the purchase of firm power for up                            (1-8291)
            to 30 years under the Firm Power and Energy Contract dated
            December 4, 1987 (previously filed with the Company's Annual
            Report on Form 10-K for 1987, Exhibit Number 10.b.68).
10.b.72(a)  Restatement of the Participation Agreement filed as Exhibit . . .  10.b.72(a)  Form 10-K 1988
            10.b.72 on Form 10-Q for June 1988.                                                    (1-8291)
   10.b.77  Firm Power and Energy Contract dated December 29, 1988, . . . . .     10.b.77  Form 10-K 1988
            between Hydro Quebec and participating Vermont utilities,                              (1-8291)
            including the Company, for the purchase of up to 54 MW of
            firm power and energy.
   10.b.78  Transmission Agreement dated December 23, 1988, between the . . .     10.b.78  Form 10-K 1988
            Company and Niagara Mohawk Power Corporation (Niagara Mohawk),                         (1-8291)
            for Niagara Mohawk to provide electric transmission to the
            Company from Rochester Gas and Electric and Central Hudson
            Gas and Electric.
   10.b.81  Sales Agreement dated May 24, 1989, between the Town of . . . . .     10.b.81  Form 10-Q
            Hardwick, Hardwick Electric Department and the Company for                     June 1989
            the Company to purchase all of the output of Hardwick's
            generation and                                                                         (1-8291)
            transmission sources and to provide Hardwick with all-
            requirements energy and capacity except for that provided by
            the Vermont Department of Public Service or Federal
            Preference Power.
   10.b.82  Sales Agreement dated July 14, 1989, between Northfield . . . . .     10.b.82  Form 10-Q
            Electric Department and the Company for the Company to                         June 1989
            purchase all of the output of Northfield's generation and                              (1-8291)
            transmission sources and to provide Northfield with all-
            requirements energy and capacity except for that provided
            by the Vermont Department of Public Service or Federal
            Preference Power.
   10.b.85  Power Purchase and Sale Agreement between Morgan Stanley. . . . .     10.b.85  Form 10-K 1998
            Capital Group Inc. and the Company.                                                    (1-8291)
   10.b.90  Power Purchase Agreement between Entergy Nuclear Vermont. . . . .     10.b.90  Form 10-Q June
            Yankee LLC and Vermont Yankee Nuclear Power Corporation.                          2002 (1-8291)
   10.b.91  First Amendment to Purchase Power Agreement listed as Exhibit . .     10.b.91  Form 10-Q June
            Number 10.b.90, between Entergy Nuclear Vermont Yankee LLC                        2002 (1-8291)
            and Vermont Yankee Nuclear Power Corporation.
   10.b.92  Amendment to Power Purchase and Sale Agreement between Morgan . .     10.b.92  Form 10-K 2002
            Stanley Capital Group, Inc. and the Company.                                           (1-8291)
   10.b.93  2001 Amendatory Agreement Power Supply Agreement between. . . . .     10.b.93  Form 10-K 2004
            the Company and Vermont Yankee Nuclear Power Corporation.
   10.b.94  Fourth Amended and Restated Credit Agreement by and among . . . .     10.b.94  Form 10-K 2004
            Green Mountain Power Corporation, Fleet National Bank,
            Sovereign Bank and Fleet National Bank as Agent dated
            June 16, 2004.
</TABLE>

<TABLE>
<CAPTION>


          Management  contracts  or  compensatory  plans  or  arrangements  required
Exhibit     to  be  filed  as  exhibits  to  this  Form  10-K  pursuant  to  Item  14(c).,
 Number   all under SEC Docket 1-8291                                    Exhibit
--------  ------------------------------------------------------------  ----------
<C>       <S>                                                           <C>         <C>
 10.d.1b  Green Mountain Power Corporation Second Amended and. . . . .     10.d.1b  Form 10-K 1993
          Restated Deferred Compensation Plan for Directors.
 10.d.1c  Green Mountain Power Corporation Second Amended and Restated     10.d.1c  Form 10-K 1993
          Deferred Compensation Plan for Officers.
 10.d.1d  Amendment No. 93.1 to the Amended and Restated Deferred. . .     10.d.1d  Form 10-K 1993
          Compensation Plan for Officers.
 10.d.1e  Amendment No. 94.1 to the Amended and Restated Deferred. . .     10.d.1e  Form 10-Q
          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 Officers' Insurance Plan. .      10.d.4  Form 10-K 1991
 10.d.4a  Green Mountain Power Corporation Officers' Insurance . . . .     10.d.4a  Form 10-K 1990
          Plan as amended.
  10.d.8  Green Mountain Power Corporation Officers' Supplemental. . .      10.d.8  Form 10-K 1990
          Retirement Plan.
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, Jr.. . . . . . . . .     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, Jr.. . . .     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 2003
 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
 10.d.64  Deferred Stock Unit Agreement with E. A. Bankowski . . . . .     10.d.64  Form 10-Q
                                                                                    June 2004
 10.d.65  Deferred Stock Unit Agreement with N. L. Brue. . . . . . . .     10.d.65  Form 10-Q
                                                                                    June 2004
 10.d.66  Deferred Stock Unit Agreement with W. H. Bruett. . . . . . .     10.d.66  Form 10-Q
                                                                                    June 2004
 10.d.67  Deferred Stock Unit Agreement with M. O. Burns . . . . . . .     10.d.67  Form 10-Q
                                                                                    June 2004
 10.d.68  Deferred Stock Unit Agreement with D. R. Coates. . . . . . .     10.d.68  Form 10-Q
                                                                                    June 2004
 10.d.69  Deferred Stock Unit Agreement with K. C. Hoyt. . . . . . . .     10.d.69  Form 10-Q
                                                                                    June 2004
 10.d.70  Deferred Stock Unit Agreement with E. A. Irving. . . . . . .     10.d.70  Form 10-Q
                                                                                    June 2004
 10.d.71  Deferred Stock Unit Agreement with M. A. vanderHeyden. . . .     10.d.71  Form 10-Q
                                                                                    June 2004
 10.d.72  Director Deferral Agreement with E. A. Bankowski . . . . . .        10.1  Form 8-K
                                                                                    Dec. 2, 2004
 10.d.73  Director Deferral Agreement with M. O. Burns . . . . . . . .        10.2  Form 8-K
                                                                                    Dec. 2, 2004
 10.d.74  Director Deferral Agreement with E. A. Irving. . . . . . . .        10.3  Form 8-K
                                                                                    Dec. 2, 2004
 10.d.75  Officer Deferral Agreement with S. C. Terry. . . . . . . . .        10.4  Form 8-K
                                                                                    Dec. 2, 2004
 10.d.76  Officer Deferral Agreement with W. S. Oakes. . . . . . . . .        10.5  Form 8-K
                                                                                    Dec. 2, 2004
 10.d.77  Board of Directors' Resolutions Amending Deferred. . . . . .  10.1, 10.2  Form 8-K
          Compensation Plan                                                         Dec. 30, 2004
 10.d.78  Officer Compensation Table . . . . . . . . . . . . . . . . .     10.d.78  Form 10-K 2004
 10.d.79  2005 Management Compensation Plan Description. . . . . . . .     10.d.79  Form 10-K 2004
 10.d.80  Green Mountain Power Corporations Officers' Supplemental . .     10.d.80  Form 10-K 2004
          Retirement Plan with C. L. Dutton
 10.d.81  Green Mountain Power Corporations Officers' Supplemental . .     10.d.81  Form 10-K 2004
          Retirement Plan with R. J. Griffin
 10.d.82  Green Mountain Power Corporations Officers' Supplemental . .     10.d.82  Form 10-K 2004
          Retirement Plan with W. S. Oakes
 10.d.83  Green Mountain Power Corporations Officers' Supplemental . .     10.d.83  Form 10-K 2004
          Retirement Plan with M. G. Powell
 10.d.84  Green Mountain Power Corporations Officers' Supplemental . .     10.d.84  Form 10-K 2004
          Retirement Plan with D. J. Rendall, Jr.
 10.d.85  Green Mountain Power Corporations Officers' Supplemental . .     10.d.85  Form 10-K 2004
          Retirement Plan with S. C. Terry
 10.d.86  Green Mountain Power Corporation 2004 Stock Incentive Plan .     10.d.86  Form 10-K 2004
 10.d.87  Green Mountain Power Corporation Third Amended and Restated.     10.d.87  Form 10-K 2004
          Deferred Compensation Plan for Certain Officers.
      14  Green Mountain Power Corporation's Code of Ethics. . . . . .          14  Form 10-K 2004
          and Conduct dated October 6, 2003.
  23.a.2  Consent of Deloitte and Touche LLP . . . . . . . . . . . . .      23.a.2
      24  Limited Power of Attorney. . . . . . . . . . . . . . . . . .          24
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