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, 2000

                         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_


     THE  AGGREGATE  MARKET  VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF
THE  REGISTRANT AS OF MARCH 21, 2001, WAS APPROXIMATELY $77,278,643 BASED ON THE
CLOSING  PRICE  OF $13.84 FOR THE COMMON STOCK ON THE NEW YORK STOCK EXCHANGE AS
REPORTED  BY  THE  WALL  STREET  JOURNAL.
     THE  NUMBER  OF  SHARES  OF COMMON STOCK OUTSTANDING ON MARCH 21, 2001, WAS
5,583,717
                       DOCUMENTS INCORPORATED BY REFERENCE
     The  Company's Definitive Proxy Statement relating to its Annual Meeting of
Stockholders  to  be  held  on  May  17,  2001,  to be filed with the Commission
pursuant  to  Regulation  14A  under  the  Securities  Exchange  Act of 1934, is
incorporated  by  reference  in Items 10, 11, 12 and 13 of Part III of this Form
10-K.




2

Green  Mountain  Power  Corporation
Form  10-K  for  the  fiscal  year  ended  December  31,  2000
Table  of  contents                              Page
Part  I,  Item  1,  Company  business                    3
Item  2,  Property                                      17
Item  3,  Legal  Proceedings                            19
Item  4,  Submission  of  matters  to  vote             19
Part  II,  Item  5,  Market  related  matters           20
Item  6,  Five-Year  Financial  Highlights              22
Item  7,  Management's  Discussion  and  Analysis       23
Item  8,  Index  to  Consolidated  Financial  Statements
     and  Notes          39
Item  9,  Changes  and  Disagreements  with  Accountants 72
Items  10  through  13,  Certain  Officer  information   72
Item  14,  Exhibits,  Financial  Statement  Schedules,   72
     And  Reports  on  Form  8-K




PART  I

ITEM  1.  BUSINESS
THE  COMPANY
     Green  Mountain  Power  Corporation  (the  "Company")  is  a public utility
operating company engaged in supplying electrical energy in the State of Vermont
in  a  territory  with  approximately one quarter of the State's population.  We
serve  approximately  86,000  customers.  The Company was incorporated under the
laws  of  the  State  of  Vermont  on  April  7,  1893.

     Our  sources  of  revenue  for  the  year  ended  December 31, 2000 were as
follows:
*     25.2%  from  residential  customers;
*     25.4%  from  small  commercial  and  industrial  customers;
*     16.0%  from  large  commercial  and  industrial  customers;
*     31.9%  from  sales  to  other  utilities;  and
*     1.5%  from  other  sources.

     During  2000,  our  energy  resources  for  retail  and  wholesale sales of
electricity  were  obtained  as  follows:
*     35.8%  from hydroelectric sources (3.9% Company-owned, 0.1% New York Power
Authority  ("NYPA"),  29.5%  Hydro-Quebec  and  2.3%  small  power  producers);
*     28.8%  from  a nuclear generating source (the Vermont Yankee nuclear plant
described  below);
*     2.8%  from  wood;
*     2.7%  from  oil;
*     2.2%  from  natural  gas;  and
*     0.4%  from  wind.
     The  remaining  27.3%  was  purchased  on  a  short-term  basis  from other
utilities  through  the  Independent  System  Operator  of  New England ("ISO"),
formerly  the  New  England  Power  Pool  ("NEPOOL").
     In  2000,  we  purchased 92.8% of the energy required to satisfy our retail
and  wholesale  sales  of  electricity  (including energy purchased from Vermont
Yankee  Nuclear  Power  Corporation ("Vermont Yankee") and under other long-term
purchase  arrangements).  See  Note  K  of  Notes  to  Consolidated  Financial
Statements("Notes"),  Annual  Report  to  Stockholders,  2000 ("Annual Report").
     A  major source of the Company's power supply is our entitlement to a share
of  the  power  generated  by  the  531  megawatt  (MW)  Vermont  Yankee nuclear
generating plant owned and operated by Vermont Yankee Nuclear Power Corporation.
We  have  a 17.9% equity interest in Vermont Yankee.  For information concerning
Vermont  Yankee,  see  Power  Resources  -  Vermont  Yankee.
     The  Company  participates  in  NEPOOL,  a regional bulk power transmission
organization  established  to assure reliable and economical power supply in the
Northeast.  The  ISO was created to manage the operations of NEPOOL in 1999. The
ISO  works  as  a clearinghouse for purchasers and sellers of electricity in the
new  deregulated markets. Sellers place bids for the sale of their generation or
purchased  power  resources  and  if demand is high enough the output from those
resources  is  sold.  We  must  purchase additional electricity to meet customer
demand  during  periods  of  high  usage  and  to  replace energy repurchased by
Hydro-Quebec under an arrangement negotiated in 1997.  Our costs to serve demand
during  periods  of  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.  The cost of securing
future  power supplies has also risen in tandem with higher summer supply costs.
     The  Company's  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  of  Montpelier, Barre, South Burlington, Vergennes and Winooski, as
well  as  the  Village  of  Essex  Junction  and  a  number of smaller towns and
communities.  We  also  distribute electricity in four separate areas located in
southern  and  southeastern  Vermont  that are interconnected with our principal
service  area  through the transmission lines of Vermont Electric Power Company,
Inc.  ("VELCO")  and  others.  Included  in  these  areas are the communities of
Vernon  (where  the Vermont Yankee plant is located), Bellows Falls, White River
Junction, Wilder, Wilmington and Dover.  We supply at wholesale a portion of the
power  requirements  of  several municipalities and cooperatives in Vermont.  We
are  obligated  to  meet the changing electrical requirements of these wholesale
customers,  in contrast to our obligation to other wholesale customers, which is
limited  to  specified  amounts  of capacity and energy established by contract.
     Major  business  activities  in our service areas include computer assembly
and  components  manufacturing  (and  other electronics manufacturing), software
development,  granite  fabrication,  service  enterprises  such  as  government,
insurance,  regional  retail  shopping  and  tourism  (particularly  winter
recreation),  and  dairy  and  general  farming.

SEGMENT  INFORMATION
     The  Company has partially sold or disposed of the operations and assets of
Mountain  Energy,  Inc.  ("MEI"), classified as discontinued operations in 1999.
MEI  was  renamed  Northern  Water  Resources,  Inc.  in January 2001.  Industry
segment information required to be disclosed is presented in Note L of the Notes
to  Annual  Report.

SEASONAL  NATURE  OF  BUSINESS
      Winter recreational activities, longer hours of darkness and heating loads
from  cold  weather  usually cause our peak electric sales to occur in December,
January  or  February.  Our heaviest load in 2000, 323.5 MW, occurred on January
17,  2000.
      We  charge  our  customers  higher  rates  for  billing cycles in December
through  March  and  lower  rates  for  the  remaining months.  These are called
seasonally  differentiated  rates.  In  order  to  eliminate  the  impact of the
seasonally  differentiated rates on earnings, we defer some of the revenues from
those  four  months and account for them in later periods in which we have lower
revenues  or  higher  costs.  In prior periods, by deferring certain revenues we
are  able  to  match  our  revenues  to  our  costs  more  accurately.
      Under  this  structure, retail electric rates produce average revenues per
kilowatt-hour  during  four peak season months (December through March) that are
approximately  30% higher than during the eight off-season months (April through
November).  See  Energy  Efficiency  and  Rate  Design.
     Under  NEPOOL market rules implemented in May 1999, the cost basis that had
supported  the  Company's  rate  design was eliminated, making the seasonal rate
structure  no  longer  appropriate.  A  request  to  eliminate the seasonal rate
structure  in  all  classes  of service effective April 2001 was approved by the
Vermont  Public  Service  Board  (the  "VPSB")  in  January  2001.


SINGLE  CUSTOMER  DEPENDENCE
     The  Company  had one major retail customer, IBM, metered at two locations,
that  accounted  for  11.2  percent,  11.8  percent,  and  14.7 percent of total
operating  revenues,  and  16.5  percent,  16.4  percent and 17.1 percent of the
Company's retail operating revenues in 2000, 1999 and 1998, respectively.  IBM's
percent  of  total  revenues  in  2000  decreased  due  to  an increase in total
operating  revenues  as  a  result of sales for resale pursuant to the Company's
power  supply agreement with Morgan Stanley Capital Group, Inc. ("MS"), which is
discussed in greater detail in Management's Discussion and Analysis of Financial
Condition and Results of Operations ("MD and A")-Power Contract Commitments.  No
other  retail  customer  accounted  for more than 1.0% of our revenue during the
past  three  years.  Under  the  present regulatory system, the loss of IBM as a
customer  would  require the Company to seek rate relief to recover the revenues
previously  paid  by  IBM from other customers in an amount sufficient to offset
the  fixed  costs  that IBM had been covering through its payments.  See Notes A
and  K  of  the  Notes  to  Annual  Report.

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,

                                                      2000         1999         1998         1997         1996
                                                   -----------  -----------  -----------  -----------  -----------
<S>                                                <C>          <C>          <C>          <C>          <C>
Total capability (MW) . . . . . . . . . . . . . .       411.1        393.2        396.9        416.9        425.8
Net system peak . . . . . . . . . . . . . . . . .       323.5        317.9        312.5        311.5        313.0
                                                   -----------  -----------  -----------  -----------  -----------
Reserve (MW). . . . . . . . . . . . . . . . . . .        87.6         75.3         84.4        105.4        112.8
                                                   ===========  ===========  ===========  ===========  ===========
Reserve % of peak . . . . . . . . . . . . . . . .        27.1%        23.7%        27.0%        33.8%        36.0%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . .   1,053,223    1,095,738      972,723    1,073,246    1,192,881
Wind. . . . . . . . . . . . . . . . . . . . . . .      12,246        7,956            -            -            -
Nuclear . . . . . . . . . . . . . . . . . . . . .     803,303      731,431      607,708      772,030      680,613
Conventional steam. . . . . . . . . . . . . . . .   2,704,427    2,328,267      750,602      560,504      705,331
Internal combustion . . . . . . . . . . . . . . .      35,699       12,312       40,148        4,827        2,674
Combined cycle. . . . . . . . . . . . . . . . . .      73,433       99,962      118,322      104,836       51,162
                                                   -----------  -----------  -----------  -----------  -----------
                    Total production. . . . . . .   4,682,331    4,275,666    2,489,503    2,515,443    2,632,662
Less non-firm sales to other utilities. . . . . .   2,573,576    2,152,781      499,409      524,192      663,175
                                                   -----------  -----------  -----------  -----------  -----------
Production for firm sales . . . . . . . . . . . .   2,108,755    2,122,885    1,990,094    1,991,251    1,969,487
Less firm sales and  lease transmissions. . . . .   1,954,898    1,920,257    1,883,959    1,870,914    1,814,371
                                                   -----------  -----------  -----------  -----------  -----------
Losses and company use (MWH). . . . . . . . . . .     153,857      202,628      106,134      120,337      155,115
                                                   ===========  ===========  ===========  ===========  ===========
Losses as a % of total production . . . . . . . .        3.29%        4.74%        4.26%        4.78%        5.89%
System load factor (***). . . . . . . . . . . . .        68.8%        80.3%        71.8%        71.6%        69.7%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . .        22.5%        25.6%        39.1%        42.7%        45.3%
Wind. . . . . . . . . . . . . . . . . . . . . . .         0.3%         0.2%         0.0%         0.0%         0.0%
Nuclear . . . . . . . . . . . . . . . . . . . . .        17.1%        17.1%        24.4%        30.6%        25.9%
Conventional steam. . . . . . . . . . . . . . . .        57.8%        54.5%        30.2%        22.3%        26.8%
Internal combustion . . . . . . . . . . . . . . .         0.8%         0.3%         1.6%         0.2%         0.1%
Combined cycle. . . . . . . . . . . . . . . . . .         1.6%         2.3%         4.8%         4.2%         1.9%
                                                   -----------  -----------  -----------  -----------  -----------
                  Total . . . . . . . . . . . . .       100.0%       100.0%       100.0%       100.0%       100.0%
                                                   ===========  ===========  ===========  ===========  ===========

Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . .     558,682      544,447      533,904      549,259      557,726
Commercial & industrial - small . . . . . . . . .     704,126      688,493      665,707      645,331      630,838
Commercial & industrial - large . . . . . . . . .     683,296      664,110      636,436      608,051      584,249
Other . . . . . . . . . . . . . . . . . . . . . .       6,713        3,138        3,476        3,939        2,898
                                                   -----------  -----------  -----------  -----------  -----------
Total retail sales and lease transmissions. . . .   1,952,817    1,900,188    1,839,522    1,806,581    1,775,712
Sales to Municipals & Cooperatives (Rate W) . . .       2,081       20,069       44,437       64,333       38,660
                                                   -----------  -----------  -----------  -----------  -----------
Total Requirements Sales. . . . . . . . . . . . .   1,954,898    1,920,257    1,883,959    1,870,914    1,814,371
Other Sales for Resale. . . . . . . . . . . . . .   2,573,576    2,152,781      499,409      524,192      663,175
                                                   -----------  -----------  -----------  -----------  -----------
Total sales and  lease transmissions(MWH) . . . .   4,528,474    4,073,038    2,383,368    2,395,106    2,477,546
                                                   ===========  ===========  ===========  ===========  ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . .      72,424       71,515       71,301       70,671       70,198
Commercial and industrial small . . . . . . . . .      12,746       12,438       12,170       11,989       11,828
Commercial and industrial large . . . . . . . . .          23           23           23           23           25
Other . . . . . . . . . . . . . . . . . . . . . .          65           66           70           75           75
                                                   -----------  -----------  -----------  -----------  -----------
             Total. . . . . . . . . . . . . . . .      85,258       84,042       83,564       82,758       82,126
                                                   ===========  ===========  ===========  ===========  ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . .       12.50        12.32        11.56        11.18        10.87
Commercial & industrial - small . . . . . . . . .       10.00         9.88         9.29         9.10         8.96
Commercial & industrial - large . . . . . . . . .        6.51         6.55         6.32         6.22         6.28
                                                   -----------  -----------  -----------  -----------  -----------
Total retail including lease. . . . . . . . . . .        9.52         9.47         8.96         8.79         8.72
                                                   ===========  ===========  ===========  ===========  ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . .       7,717        7,617        7,488        7,772        7,945
Revenues including lease revenues . . . . . . . .  $      965   $      938   $      865   $      869   $      863
</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.





EMPLOYEES
     As  of  December  31,  2000,  the  Company  had 197 employees, exclusive of
temporary  employees,  and  our  subsidiary, MEI, had five employees.    The 101
union  employees  on  strike from January 4, 2001 through January 26, 2001 acted
professionally  throughout  the  three  week  strike.  The Company considers its
relations  with  employees  to  be  excellent.

STATE  AND  FEDERAL  REGULATION
     General.  The  Company  is subject to the regulatory authority of the VPSB,
which  extends  to  retail rates, services and facilities, securities issues and
various  other  matters.  The separate Vermont Department of Public Service (the
"Department"),  created  by  statute  in 1981, is responsible for development of
energy  supply  plans for the State of Vermont (the "State"), purchases of power
as  an  agent  for  the  State  and  other general regulatory matters.  The VPSB
principally  conducts  quasi-judicial  proceedings,  such  as rate setting.  The
Department,  through  a Director for Public Advocacy, is entitled to participate
as  a  litigant  in  such  proceedings  and  regularly  does  so.
     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  IBM  that  provides  for contractually established
charges,  rather than tariff rates, for incremental loads.  See Item 7. MD and A
-  Results  of  Operations  -  Operating  Revenues  and  MWh  Sales.
     Our  wholesale rate on sales to two wholesale customers is regulated by the
Federal  Energy  Regulatory  Commission  ("FERC").  Revenues from sales to these
customers  were  less  than  1%  of  operating  revenues  for  2000.
     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%  of  the  Company's  operating  revenues  for  2000.
     On  April  24,  1996, the FERC issued Orders 888 and 889 which, among other
things,  required  the  filing  of  open access transmission tariffs by electric
utilities,  and  the  functional  separation  by utilities of their transmission
operations  from  power  marketing operations.  Order 888 also supports the full
recovery  of legitimate and verifiable wholesale power costs previously incurred
under  federal  or  state  regulation.
     On  July  17,  1997, the FERC approved our Open Access Transmission Tariff,
and  on  August  30,  1997 we filed our compliance refund report.  In accordance
with  Order 889, we have also functionally separated our transmission operations
and  filed  with the FERC a code of conduct for our transmission operations.  We
do  not  anticipate  any material adverse effects or loss of wholesale customers
due to the FERC orders mentioned above.  The Open Access tariff could reduce the
amount  of capacity available to the Company from such facilities in the future.
See  Item  7.  MD  and  A  -  Transmission  Expenses.
     The  Company  has  equity  interests  in  Vermont Yankee, VELCO and Vermont
Electric  Transmission  Company,  Inc.  ("VETCO"),  a wholly owned subsidiary of
VELCO.  We have filed an exemption statement under Section 3(a)(2) of the Public
Utility  Holding  Company  Act  of  1935,  thereby  securing  exemption from the
provisions  of  such  Act,  except  for  Section  9(a)(2),  which  prohibits the
acquisition of securities of certain other utility companies without approval of
the  Securities  and  Exchange  Commission  ("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  hydro-electric  projects  owned  by  the Company:


<TABLE>
<CAPTION>


                        Issue Date   Licensed Period
                      -------------  ---------------
<S>            <C>              <C>
Project Site:
Bolton. . . .  February 5,1982  February 5,1982 - February 4, 2022
Essex . . . .  March 30, 1995   March 1, 1995 - March 1, 2025
Vergennes . .  June 29, 1999    June 1, 1999 - May 31, 2029
Waterbury . .  July 20, 1954    September 1, 1951 - August 31, 2001
</TABLE>



Major  project  licenses  provide  that  after  an initial twenty-year period, a
portion  of the earnings of such project in excess of a specified rate of return
is  to  be  set  aside in appropriated retained earnings in compliance with FERC
Order  #5,  issued  in  1978.  Although the twenty-year periods expired in 1985,
1969  and  1971  in  the  cases  of the Essex, Vergennes and Waterbury projects,
respectively,  the  amounts  appropriated  are  not  material.
     The  relicensing  application  for Waterbury was filed in August 1999.  The
Company  expects  the  project  to  be relicensed for a 30 year term in the near
future  and  does  not  have  any  competition  for  the  licenses.
     Department  of Public Service Twenty-Year Electric Plan.  In December 1994,
the Department adopted an update of its twenty-year electrical power-supply plan
(the  "Plan")  for the State.  The Plan includes an overview of statewide growth
and  development as they relate to future requirements for electrical energy; an
assessment  of  available  energy  resources; and estimates of future electrical
energy  demand.
     In  June  1996,  we  filed  with  the VPSB and the Department an integrated
resource  plan  pursuant  to  Vermont  Statute 30 V.S.A.   218c.  That filing is
still  pending  before  the  VPSB.

RECENT  RATE  DEVELOPMENTS
     On  March  2,  1998, the VPSB released its Order dated February 27, 1998 in
the  then  pending  rate  case.  The VPSB authorized us to increase our rates by
3.61  percent, which gave us increased annual revenues of $5.6 million. The VPSB
Order  denied us the right to charge customers $5.48 million of the annual costs
for  power  purchased  under  our  contract  with Hydro-Quebec.  The VPSB denied
recovery  of  these  costs  for  the  following  reasons:
*     the  VPSB claimed that we had acted imprudently by committing to the power
contract  with  Hydro-Quebec  in  August 1991 (the imprudence disallowance); and
*     to  the  extent  that the costs of power to be purchased from Hydro-Quebec
were  then  higher  than current estimates of market prices for power during the
Contract  term,  after  accounting for the imprudence disallowance, the contract
power  was  not  "used  and  useful".
     On  May  8,  1998,  we filed a request with the VPSB to increase our retail
rates  by  12.93 percent due to higher power costs, the cost of the January 1998
ice  storm,  and  investments  in  new  plant  and  equipment.
     On  November 18, 1998, by Memorandum of Understanding ("MOU"), the Company,
the  Department  and  IBM  agreed to stay rate proceedings in the 1998 rate case
until  or after September 1, 1999, or such earlier date as the parties may later
agree  to  or  the  VPSB may order.  The agreement to suspend our 1998 rate case
delayed the date of a final decision on the 1998 rate case to December 15, 1999,
and  we  recognized  an  additional loss of $5.25 million in the last quarter of
1998 representing the effect of the continued disallowance of Hydro-Quebec costs
through  December  15,  1999.  The MOU provided for a 5.5% temporary retail rate
increase,  to  produce  $8.9 million in annualized additional revenue, effective
with service rendered December 15, 1998.  An additional surcharge was permitted,
without further VPSB order, in order to produce additional revenues necessary to
provide  the  Company  with the capacity to finance 1999 Pine Street Barge Canal
site  expenditures.  The  MOU was approved by the VPSB on December 11, 1998. The
MOU  did  not  provide  for  any  specific disallowance of power costs under our
purchase  power  contract with Hydro-Quebec.  Issues respecting recovery of such
power  costs  were preserved for future proceedings.  The stay and suspension of
this  pending  rate case and the temporary rate levels agreed to in the MOU were
designed  to  allow  us to continue to provide adequate and efficient service to
our  customers  while  we  seek  mitigation  of  power  supply  costs.
      On September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments  to the MOU that the Company had entered into with the Department and
IBM.  The  two  amendments  continued the stay of proceedings until September 1,
2000,  with  a  final  decision  expected  by December 31, 2000.  The amendments
maintained  the  other  features  of  the original MOU, and the second amendment
provided  for a temporary rate increase of 3 percent, in addition to the current
temporary  rate  level,  to  become  effective  as  of  January  1,  2000.
     The Company reached a final settlement agreement with the Department in the
pending  rate case during November 2000. The final settlement agreement contains
the  following  provisions:
*     A rate increase of 3.42 percent above existing rates, beginning with bills
rendered  January 23, 2001, and prior temporary rate increases become permanent;
*     Rates  are  set  at  levels  that  recover  the Company's Hydro-Quebec VJO
contract  costs,  effectively ending the regulatory disallowances experienced by
the  Company  over  the  past  three  years;
*     The  Company  agrees  not  to  seek any further increase in electric rates
prior  to  April  2002 (effective in bills rendered January 2003) unless certain
substantially  adverse  conditions  arise,  including  a  provision  allowing  a
request  for  rate  relief  if  power  supply  costs increase in excess of $3.75
million  over  forecasted  levels;
*     The  Company agreed to write off approximately $3.2 million in unrecovered
rate  case  litigation  costs,  and  to  freeze  its  dividend  rate  until  it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
*     Seasonal  rates  will  be  eliminated  April  2001,  which  is expected to
generate  approximately  $6  million in cash flow that can be utilized to offset
increased  costs  during  2001,  2002  and  2003;  and
*     The  Company  agrees  to consult extensively with the Department regarding
capital  spending commitments for upgrading our electric distribution system and
to  adopt  customer  care and reliability performance standards, in a first step
toward  possible  development  of  performance-based  rate-making.
     On  January  23,  2001, the VPSB approved the Company's settlement with the
Department,  with  two  additional  conditions:
*     The  VPSB  Order requires the Company and customers to share equally, with
an  $8.0  million  limit  to the customers' share,  any premium above book value
realized  by  the  Company  in any future merger, acquisition or asset sale; and
*     The  second  condition  restricts  Company  investments  in  non-utility
operations.
          For  further  information regarding recent rate developments, see Item
7.  MD  and  A  - Liquidity and Capital Resources, Rates, and Note I of Notes to
Annual  Report.

COMPETITION  AND  RESTRUCTURING
     Electric  utilities  historically  have  had  exclusive  franchises for the
retail  sale  of  electricity  in  specified  service  territories.  Legislative
authority  has  existed  since  1941 that would permit Vermont cities, towns and
villages  to own and operate public utilities.  Since that time, no municipality
served  by the Company has established or, as far as is known to the Company, is
presently  taking  steps  to  establish  a  municipal  public  utility.
     In  1987,  the Vermont General Assembly enacted legislation that authorized
the  Department  to  sell electricity on a significantly expanded basis.  Before
the new law was passed, the Department's authority to make retail sales had been
limited.  It  could  sell  at  retail only to residential and farm customers and
could  sell  only  power that it had purchased from the Niagara and St. Lawrence
projects  operated  by  the  New  York  Power  Authority.
     Under  the  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.  The  Department  has  made  limited additional retail sales of
electricity.  The  Department retains its traditional responsibilities of public
advocacy  before  the  VPSB  and  electricity  planning  on  a  statewide basis.
     In  certain  states  across  the country, including the New England states,
legislation  has  been  enacted  to  allow  retail  customers  to  choose  their
electricity  suppliers,  with  incumbent  utilities  required  to  deliver  that
electricity  over  their  transmission  and  distribution  systems.  Increased
competitive pressure in the electric utility industry may restrict the Company's
ability  to  charge  energy prices sufficient to recover embedded costs, such as
the cost of purchased power obligations or of generation facilities owned by the
Company.  The  amount by which such costs might exceed market prices is commonly
referred  to  as  stranded  costs.
     Regulatory  and  legislative  authorities  at the federal level and in some
states,  including  Vermont  where  legislation  has  not  been  enacted,  are
considering  how  to  facilitate competition for electricity sales.  For further
information  regarding  Competition  and  Restructuring,  See Item 7. MD and A -
Future  Outlook.

POWER  RESOURCES
     The  Company has renewed a contract with Morgan Stanley Capital Group, Inc.
as  the  result of our all power requirements solicitation in 1999.  See Notes I
and  K  of  Notes  to  Consolidated  Financial  Statements.
     The Company generated, purchased or transmitted 2,790,018 MWh of energy for
retail and requirements wholesale customers for the twelve months ended December
31,  2000.  The  corresponding  maximum  one-hour  integrated demand during that
period was 323.5 MW on January 17, 2000.  This compares to the previous all-time
peak  of  322.6  MW  on  December  27,  1989.  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  to  Annual  Report.


<TABLE>
<CAPTION>

Net  Electricity  Generated  and  Purchased  and  Capacity  at  Peak

                                      During year       At time of
                                   Ended 12/31/2000   of annual peak
                                          MWH             percent        KW     percent
                                   -----------------  ---------------  -------  --------
<S>                                <C>                <C>              <C>      <C>
Wholly-owned plants:
Hydro . . . . . . . . . . . . . .           108,230              3.9%   35,300      8.6%
Diesel and Gas Turbine. . . . . .            35,699              1.3%   46,200     11.3%
Wind. . . . . . . . . . . . . . .            12,246              0.4%      850      0.2%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . . .            15,443              0.6%    7,100      1.7%
Stony Brook I . . . . . . . . . .            50,537              1.8%   31,000      7.6%
McNeil. . . . . . . . . . . . . .            33,569              1.2%    6,600      1.6%
Owned in association with Others:
Vermont Yankee Nuclear. . . . . .           803,303             28.8%   95,680     23.3%
Long Term Purchases:
Hydro-Quebec. . . . . . . . . . .           824,993             29.5%  114,200     27.8%
Stony Brook I . . . . . . . . . .            22,896              0.8%   14,150      3.5%
Other:
NYPA. . . . . . . . . . . . . . .             1,453              0.1%      250      0.1%
Small Power Producers . . . . . .           120,000              4.3%   24,650      6.0%
Short-term purchases. . . . . . .           761,649             27.3%   34,100      8.3%
                                   -----------------  ---------------  -------  --------
Total . . . . . . . . . . . . . .         2,790,018                    410,080
Less system sales energy. . . . .            (2,256)                         -
                                   -----------------              ---------------
Net Own Load. . . . . . . . . . .         2,787,762           100.00%  410,080   100.00%
                                   =================  ===============  =======  ========
</TABLE>


Vermont  Yankee.
     On October 15, 1999, the owners of Vermont Yankee Nuclear Power Corporation
accepted  a  bid  from  AmerGen Energy Company for the Vermont Yankee generating
plant,  intending  to  complete  the sale before December 2000.  AmerGen and the
Department  then  negotiated  a  revised  offer  in  November  2000,  which  was
subsequently  dismissed  as insufficient by the VPSB in February 2001.   Entergy
Nuclear Inc. has also made an offer, and two other companies have indicated they
would  participate  in  an  auction, if held.  The plant is likely to be sold at
auction,  the  terms  and  conditions  of  which  are  unknown  at  this  time.
     The  Company  and  Central Vermont Public Service Corporation acted as lead
sponsors  in  the  construction  of  the  Vermont  Yankee  Nuclear  Plant,  a
boiling-water  reactor  designed  by General Electric Company.  The plant, which
became operational in 1972, has a generating capacity of 531 MW.  Vermont Yankee
has  entered  into  power  contracts  with  its sponsor utilities, including the
Company,  that expire at the end of the life of the unit.  Pursuant to our power
contract,  we  are  required  to  pay 20% of Vermont Yankee's operating expenses
(including  depreciation and taxes), fuel costs (including charges in respect of
estimated  costs  of  disposal of spent nuclear fuel), decommissioning expenses,
interest  expense and return on common equity, whether or not the Vermont Yankee
plant  is operating.  In 1969, we sold to other Vermont utilities a share of our
entitlement  to the output of Vermont Yankee.  Accordingly, those utilities have
an  obligation  to  pay  us  2.338% of Vermont Yankee's operating expenses, fuel
costs,  decommissioning  expenses, interest expense and return on common equity,
whether  or  not  the  Vermont  Yankee  plant  is  operating.
     Vermont  Yankee  has  also  entered  into capital funds agreements with its
sponsor  utilities  that  expire  on December 31, 2002.  Under our Capital Funds
Agreement, we are required, subject to obtaining necessary regulatory approvals,
to  provide  20% of the capital requirements of Vermont Yankee not obtained from
outside  sources.
     In  December 1996, August 1997 and July 1998, decisions were made to retire
three  New England nuclear units, Connecticut Yankee, Maine Yankee and Millstone
1  effective  immediately,  with  several  years remaining on each license.  The
NRC's  most recently issued Systematic Assessment of Licensee Performance scores
for  Vermont  Yankee  are  for  the  period  January  19, 1997 to July 18, 1998.
Operations,  engineering,  maintenance and plant support were rated good.  These
scores  were  identical to Vermont Yankee's scores for the prior 18 month-period
except  for  plant  support,  which  declined  from  superior.
     During  periods  when  Vermont  Yankee  power  is  unavailable,  we  incur
replacement power costs in excess of those costs that we would have incurred for
power  purchased from Vermont Yankee.  Replacement power is available to us from
the  ISO and through contractual arrangements with other utilities.  Replacement
power  costs  adversely  affect cash flow and, absent deferral, amortization and
recovery through rates, would adversely affect reported earnings.  Routinely, in
the  case of scheduled outages for refueling, the VPSB has permitted the Company
to  defer,  amortize  and  recover  these  excess  replacement  power  costs for
financial  reporting  and  rate  making  purposes over the period until the next
scheduled  outage.  Vermont  Yankee  has adopted an 18-month refueling schedule.
The 2001 refueling outage is tentatively scheduled to begin June 2001, though it
may  occur  earlier.  In the case of unscheduled outages of significant duration
resulting  in  substantial  unanticipated  costs for replacement power, the VPSB
generally  has  authorized  deferral,  amortization  and recovery of such costs.
     Vermont Yankee's current estimate of costs to decommission the plant, using
the  1993  FERC  approved  5.4  percent  escalation  rate, is approximately $430
million,  of  which  $247  million  has  been funded.  At December 31, 2000, our
portion of the net non-funded liability was $33 million, which we expect will be
recovered through rates over Vermont Yankee's remaining operating life.  Vermont
Yankee's  current  operating  license  expires  March  2012.
     During  the  year  ended  December 31, 2000, we used 803,303 MWh of Vermont
Yankee  energy to meet 28.8% of our retail and requirements wholesale ("Rate W")
sales.  The  average  cost  of Vermont Yankee electricity in 2000 was $0.039 per
KWh.  Vermont  Yankee's annual capacity factor for 2000 was 99.2%, compared with
90.9%  in  1999,  73.6% in 1998 and 93.5% in 1997.  The 1999 capacity factor was
the  best  ever  for  Vermont Yankee in a year that included a refueling outage.
     See  Note  B  of  Notes  to  Annual  Report.

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

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

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

     Phase  II.  Agreements  executed in 1985 among the Company, VELCO 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
System  and that of Hydro-Quebec.  Phase II expanded the Phase I facilities from
690 MW to 2,000 MW, and provides for transmission of Hydro-Quebec power from the
Phase  I  terminal  in  northern  New  Hampshire  to  Sandy Pond, Massachusetts.
Construction  of Phase II commenced in 1988 and was completed in late 1990.  The
Phase  II  facilities commenced commercial operation November 1, 1990, initially
at  a  rating of 1,200 MW, and increased to a transfer capability of 2,000 MW in
July 1991.  The Hydro-Quebec-NEPOOL Firm Energy Contract provides for the import
of  economical Hydro-Quebec energy into New England.  The Company is entitled to
3.2%  of the Phase II power-supply benefits.  Total construction costs for Phase
II were approximately $487,000,000.  The New England participants, including the
Company,  have  contracted to pay monthly their proportionate share of the total
cost  of  constructing,  owning and operating the Phase II facilities, including
capital  costs.  As  a  supporting  participant,  the  Company must make support
payments  under  30-year  agreements.  These support agreements meet the capital
lease  accounting requirements under SFAS 13.  At December 31, 2000, the present
value  of  the Company's obligation was approximately $6,449,000.  The Company's
projected  future  minimum  payments  under  the Phase II support agreements are
approximately  $430,000  for  each  of  the  years 2001-2005 and an aggregate of
$4,299,000  for  the  years  2006-2020.
     The  Phase  II  portion  of  the  project  is  owned  by  New  England
Hydro-Transmission  Electric  Company,  Inc.  and New England Hydro-Transmission
Corporation,  subsidiaries  of  New England Electric System, in which certain of
the  Phase  II  participating  utilities,  including  the  Company,  own  equity
interests.  The  Company  owns  approximately  3.2%  of  the  equity  of  the
corporations  owning  the Phase II facilities.  During construction of the Phase
II  project,  the  Company, as an equity sponsor, was required to provide equity
capital.  At  December  31, 2000, the capital structure of such corporations was
approximately  39%  common  equity and 61% long-term debt.  See Notes B and J of
Notes  to  Annual  Report.
     At  times,  we  request  that  portions  of  our  power  deliveries  from
Hydro-Quebec and other sources be routed through New York.  Our ability to do so
could  be  adversely  affected by the proposed tariff that NEPOOL has filed with
the  FERC,  which  would  reduce  our  allocation  of  capacity  on transmission
interfaces  with  New York.  As a result, our ability to import power to Vermont
from  outside  New  England  could  be adversely affected, thereby impacting our
power  costs in the future.  See Item 7. MD and A - Transmission Issues and Note
J  of  Notes  to  Annual  Report.

     Hydro-Quebec  Power  Supply  Contracts.  We  have  several  purchase  power
contracts  with  Hydro-Quebec.  The  bulk  of our purchases are comprised of two
schedules,  B  and  C3,  pursuant to a Firm Contract dated December 1987.  Under
these  two  schedules, we purchase 114.2 MW.  Under an arrangement negotiated in
January  1996,  we received payments from Hydro-Quebec of $3,000,000 in 1996 and
$1,100,000  in  1997.  In  accordance  with such arrangement, we agreed to shift
certain transmission requirements, purchase certain quantities of power and make
certain  minimum  payments  for  periods  in  which  power is not purchased.  In
addition,  in  November 1996, we entered into a Memorandum of Understanding with
Hydro-Quebec under which Hydro-Quebec paid $8,000,000 to the Company in exchange
for  certain  power  purchase  options.  The  exercise  of these options in 2000
resulted in an increase of approximately $7.7 million to power supply expense to
meet  contractual  obligations  under  the  Company's  December  1997  sell-back
agreement  with Hydro-Quebec.  See Item 7. MD and A - Power Supply Expenses, and
Notes  I,  J  and  K  of  Notes  to  Annual  Report.
     In  2000,  we used 406,408 MWh under Schedule B, 273,088 MWh under Schedule
C3, and 149,551 MWh under the HQ 9601 and 9602 arrangements to meet 29.7% of our
retail  and  requirements  wholesale  sales.  The  average  cost of Hydro-Quebec
electricity  in  1999  was  $0.06  per  KWh.

     Stony  Brook  I.  The  Massachusetts  Municipal  Wholesale Electric Company
("MMWEC")  is  principal  owner  and  operator  of  Stony  Brook,  a  352.0-MW
combined-cycle intermediate generating station located in Ludlow, Massachusetts,
which  commenced commercial operation in November 1981.  We entered into a Joint
Ownership  Agreement with MMWEC dated as of October 1, 1977, whereby we acquired
an  8.8%  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  2000, we used 73,433 MWh from this plant to meet 2.6% of our retail
and requirements wholesale sales at an average cost of $0.064 per KWh.  See Note
I  and  K  of  Notes  to  Annual  Report.

     Wyman  Unit  #4.  The  W.  F.  Wyman Unit #4, which is located in Yarmouth,
Maine,  is  an  oil-fired  steam plant with a capacity of 620 MW.  Central Maine
Power  Company  sponsored  the  construction  of  this  plant.  We  have  a
joint-ownership  share  of  1.1%  (7.1  MW)  in  the  Wyman #4 unit, which began
commercial  operation  in  December  1978.
     During  2000,  we used 15,443 MWh from this unit to meet 0.6% of our retail
and  requirements  wholesale  sales  at an average cost of $0.044 per kWh, based
only on operation, maintenance, and fuel costs incurred during 2000.  See Note I
of  Notes  to  Annual  Report.

     McNeil  Station.  The  J.C. McNeil station, which is located in Burlington,
Vermont,  is  a  wood chip and gas-fired steam plant with a capacity of 53.0 MW.
We  have  an  11.0%  or  5.8  MW interest in the J. C. McNeil plant, which began
operation in June 1984.  In 1989, the plant added the capability to burn natural
gas  on  an  as-available/interruptible  service  basis.
     During  2000,  we used 33,569 MWh from this unit to meet 1.2% of our retail
and  requirements  wholesale  sales  at an average cost of $0.053 per kWh, based
only on operation, maintenance, and fuel costs incurred during 2000.  See Note I
of  Notes  to  Annual  Report.

     Independent Power Producers.  The VPSB has adopted rules that implement for
Vermont  the  purchase  requirements  established  by  federal law in the Public
Utility  Regulatory Policies Act of 1978 ("PURPA").  Under the rules, qualifying
facilities  have  the  option to sell their output to a central state-purchasing
agent  under  a  variety  of  long-  and  short-term,  firm and non-firm pricing
schedules.  Each  of  these  schedules  is  based  upon  the  projected  Vermont
composite system's power costs that would be required but for the purchases from
independent  producers.  The  State  purchasing  agent  assigns  the  energy  so
purchased,  and  the  costs of purchase, to each Vermont retail electric utility
based  upon  its pro rata share of total Vermont retail energy sales.  Utilities
may  also  contract  directly  with  producers.  The  rules  provide  that  all
reasonable  costs  incurred by a utility under the rules will be included in the
utilities'  revenue  requirements  for  rate-making  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 2000 was approximately 32.9%
or  49.3  MW.
     The  rated capacity of the qualifying facilities currently selling power to
VEPPI  is approximately 74.5 MW.  These facilities were all online by the spring
of  1993, and no other projects are under development.  We do not expect any new
projects to come online in the foreseeable future because the excess capacity in
the  region  has  eliminated  the  need  for  and value of additional qualifying
facilities.
     In  2000,  through our direct contracts and VEPPI, we purchased 120,000 MWh
of  qualifying facilities production to meet 4.3% of our retail and requirements
wholesale  sales  at  an  average  cost  of  $0.113  per  KWh.

     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 may make purchases or sales of power on short notice and
generally  for  brief  periods  of  time  when  it  appears  economic  to do so.
Opportunity  purchases  are  arranged  when it is possible to purchase power for
less  than  it  would  cost  us  to  generate  the  power  with our own sources.
Purchases  also  help us save on replacement power costs during an outage of one
of  our  base load sources.  Opportunity sales are arranged when we have surplus
energy  available at a price that is economic to other regional utilities at any
given  time.  The  sales are arranged based on forecasted costs of supplying the
incremental  power necessary to serve the sale.  Prices are set so as to recover
all  of the forecasted fuel or production costs and to recover some, if not all,
associated  capacity  costs.
     During  2000,  we  purchased  757,595  MWh, meeting 27.1% of our retail and
requirements  wholesale  sales,  at  an  average  cost  of  $0.044  per  kWh.
     Company  Hydroelectric  Power.  The  Company wholly owns and operates eight
hydroelectric  generating facilities located on river systems within its service
area,  the  largest  of  which  has  a  generating  output  of  7.8  MW.
     In  2000,  the  Company  owned hydroelectric plants provided 108,230 MWh of
low-cost  energy, meeting 3.9% of our retail and requirements wholesale sales at
an average cost of $0.051 per kWh based on total embedded costs and maintenance.
See  State  and  Federal  Regulation  -  Licensing.

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

     Fuel.  During  2000,  our  retail  and  requirements  wholesale  sales were
provided  by  the  following  fuel  sources:
*     35.8%  from  hydroelectric  sources  (3.9% Company-owned, 0.1% NYPA, 29.5%
Hydro-Quebec  and  2.3%  small  power  producers);
*     28.8%  from  a nuclear generating source (the Vermont Yankee nuclear plant
described  below);
*     2.8%  from  wood;
*     2.7%  from  oil;
*     2.2%  from  natural  gas;
*     0.4%  from  wind  power  producers;  and
*     27.3% was purchased on a short-term basis from other utilities through the
Independent  System  Operator  of  New England ("ISO"), formerly the New England
Power  Pool  ("NEPOOL").
     Vermont  Yankee  has  several  requirement-based  contracts  for  the  four
components  (uranium,  conversion,  enrichment  and fabrication) used to produce
nuclear  fuel.  These contracts are executed only if the need or requirement for
fuel  arises.  Under these contracts, any disruption of operating activity would
allow  Vermont  Yankee to cancel or postpone deliveries until actually required.
The  contracts  extend through various time periods and contain clauses to allow
Vermont  Yankee  the  option  to  extend  the  agreements.  Negotiation  of  new
contracts  and  renegotiations  of  existing  contracts  routinely occurs, often
focusing  on  one  of  the  four  components  at  a time.   The 1999 reload cost
approximately  $20.8  million.  Future  reload  costs  will depend on market and
contract  prices
     On January 20, 1997, Vermont Yankee entered into an agreement with a former
uranium  supplier  whereby  the  supplier  could  opt  to terminate a production
purchase  agreement  dated  August  4,  1978.  Although  there  had  been  no
transactions  under the production purchase agreement for several years, Vermont
Yankee  maintained certain financial rights.  In consideration for the option to
terminate  the  production purchase agreement and the subsequent exercise of the
option,  Vermont  Yankee  received  $600,000  in  1997, which was recorded as an
offset  to  nuclear fuel expense.  The potential future payments over a ten-year
period range from zero to $2.4 million.  No payments were received in 2000 under
this  agreement.  Due  to  the  uncertainty  of  this  transaction, any benefits
received  will  be  recorded  on  a  cash  basis.
     Vermont  Yankee  has a contract with the United States Department of Energy
("DOE")  for  the  permanent disposal of spent nuclear fuel.  Under the terms of
this  contract, in exchange for the one-time fee discussed below and a quarterly
fee  of  1  mil  per  kWh  of  electricity generated and sold, the DOE agrees to
provide  disposal  services  when  a  facility  for spent nuclear fuel and other
high-level  radioactive  waste is available, which is required by contract to be
prior  to  January  31,  1998.  The  actual  date for these disposal services is
expected  to  be  delayed  many years.  DOE currently estimates that a permanent
disposal  facility  will  not  begin  operation  before  2010.  A  DOE temporary
disposal  site  may be provided in a few years, but no decision has been made to
proceed  on  providing  a  temporary  disposal  site  at  this  time.
     The  DOE  contract  obligates  Vermont  Yankee  to  pay  a  one-time fee of
approximately  $39.3  million  for  disposal costs for all spent fuel discharged
through  April  7,  1983.  Although such amount has been collected in rates from
the  Vermont Yankee participants, Vermont Yankee has elected to defer payment of
the  fee  to  the DOE as permitted by the DOE contract.  The fee must be paid no
later  than  the  first  delivery  of  spent  nuclear fuel to the DOE.  Interest
accrues  on  the unpaid obligation based on the thirteen-week Treasury Bill rate
and  is  compounded  quarterly.  Through  2000  Vermont  Yankee  accumulated
approximately  $108.0 million in an irrevocable trust to be used exclusively for
settling this obligation at some future date, provided the DOE complies with the
terms  of  the  aforementioned  contract.
     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 2000, and, while no
assurance  can  be  given, we do not anticipate any such difficulty during 2001.
None  of  the  utilities  from  which  we  expect  to purchase oil- or gas-fired
capacity in 2001 has advised us of grounds for doubt about maintenance of secure
sources  of  oil  and  gas  during  the  year.
     Wood  for  the  McNeil  plant  is  furnished  to  the  Burlington  Electric
Department  from  a  variety  of sources under short-term contracts ranging from
several  weeks'  to six months' duration.  The McNeil plant used 299,246 tons of
wood  chips  and  mill residue, 1,146,045 gallons of fuel oil, and 1.044 billion
cubic  feet  of  natural  gas  in  2000.  The  McNeil plant, assuming any needed
regulatory  approvals are obtained, is forecasting year 2001 consumption of wood
chips  to  be  300,000  tons,  fuel  oil  of  200,000  gallons  and  natural gas
consumption  of  26  million  cubic  feet.
     The  Stony  Brook  combined-cycle  generating station is capable of burning
either  natural  gas  or oil in two of its turbines.  Natural gas is supplied to
the  plant  subject  to  its  availability.  During  periods  of  extremely cold
weather,  the supplier reserves the right to discontinue deliveries to the plant
in  order  to  satisfy  the demand of its residential customers.  We assume, for
planning and budgeting purposes, that the plant will be supplied with gas during
the  months of April through November, and that it will run solely on oil during
the  months  of  December  through  March.  The  plant  maintains  an oil supply
sufficient  to  meet  approximately  one-half  of  its  annual  needs.
     Wind  Project.  The  Company was selected by the DOE and the Electric Power
Research  Institute  ("EPRI") to build a commercial scale wind-powered facility.
The  DOE and EPRI provided partial funding for the wind project of approximately
$3.9  million.  The  net  cost  to  the  Company  of the project, located in the
southern  Vermont town of Searsburg, was $7.8 million.  The eleven wind turbines
have  a  rating  of  6  MW  and  were  commissioned  July  1,  1997.
     In  2000,  the  plant  provided  12,246  MWh, meeting 0.4% of the Company's
retail  and  requirements  wholesale  sales at an average cost of $0.07 per kWh.

ENERGY  EFFICIENCY
     In  2000,  GMP  focused  its energy efficiency services on transferring its
programs  that encouraged customers to install energy efficient equipment to the
Energy  Efficiency  Utility  created  by  the  VPSB  in  1999  to  manage energy
efficiency  programs  for all utilities in Vermont.  The Company's customers are
now  billed  a separate EEU charge that we remit directly to the EEU. During the
past  eight  years  the Company's efficiency programs have achieved a cumulative
annual  savings  of  89,000 megawatthours, saving approximately $7.9 million per
year  for  our  customers.  In  2000,  we spent approximately $305,000 on energy
efficiency  programs.


RATE  DESIGN
     The  Company  seeks to design rates to encourage the shifting of electrical
use  from  peak  hours  to off-peak hours.  Since 1976, we have offered optional
time-of-use  rates  for  residential  and  commercial  customers.  Currently,
approximately 2,160 of the Company's residential customers continue to be billed
on  the  original  1976  time-of-use rate basis.   In 1987, the Company received
regulatory  approval  for  a  rate design that permitted it to charge prices for
electric  service  that  reflected  as  accurately  as  possible the cost burden
imposed  by  each  customer  class.  The Company's rate design objectives are to
provide  a  stable  pricing  structure  and  to  accurately  reflect the cost of
providing  electric services.  This rate structure helps to achieve these goals.
Since  inefficient  use  of  electricity  increases  its cost, customers who are
charged  prices  that reflect the cost of providing electrical service have real
incentives  to follow the most efficient usage patterns.  Included in the VPSB's
order  approving  this  rate design was a requirement that the Company's largest
customers  be  charged  time-of-use  rates  on  a  phased-in  basis by 1994.  At
December  31,  2000,  approximately  1,360  of  the Company's largest customers,
comprising  52%  of  retail  revenues,  continue to receive service on mandatory
time-of-use  rates.
     In  May 1994, the Company filed its current rate design with the VPSB.  The
parties,  including the Department, IBM and a low-income advocacy group, entered
into  a settlement that was approved by the VPSB on December 2, 1994.  Under the
settlement,  the  revenue  allocation to each rate class was adjusted to reflect
class-by-class  cost changes since 1987, the differential between the winter and
summer  rates  was  reduced, the customer charge was increased for most classes,
and  usage  charges were adjusted to be closer to the associated marginal costs.
     No  modifications  to  base  rate  redesign have taken place since the VPSB
Order  issued  on  December  2,  1994,  however,  as  previously noted, the VPSB
Settlement  Order  of  January  2001  eliminates  seasonal  rate  differentials
effective  April  2001.

DISPATCHABLE  AND  INTERRUPTIBLE  SERVICE  CONTRACTS
     In  2000,  we  had  28  dispatchable  power  contracts:  20  contracts were
year-round,  while  the  8  seasonal contracts include two major ski areas.  The
dispatchable  portion  of the contracts allows customers to purchase electricity
during  times  designated  by the Company when low cost power is available.  The
customer's  demand  during  these  periods  is not considered in calculating the
monthly  billing.  This program enables the Company and the customers to benefit
from  load  control.  We  shift  load  from  our  high cost peak periods and the
customer  uses  inexpensive power at a time when its use provides maximum value.
These  programs  are  available  by  tariff  for  qualifying  customers.

CONSTRUCTION  AND  CAPITAL  REQUIREMENTS
     Our  capital expenditures for 1998 through 2000 and projection for 2001 are
set forth in Item 7. Management's Discussion And Analysis Of Financial Condition
and  Results  Of  Operations  -  Liquidity  and  Capital Resources-Construction.
Construction  projections  are  subject  to continuing review and may be revised
from  time-to-time  in  accordance  with  changes  in  the  Company's  financial
condition,  load  forecasts,  the  availability and cost of labor and materials,
licensing  and  other  regulatory requirements, changing environmental standards
and  other  relevant  factors.
     For  the  period  1998-2000,  internally  generated funds, after payment of
dividends,  provided  approximately 59 percent of total capital requirements for
construction,  sinking  fund  obligations  and  other  requirements.  Internally
generated  funds  provided  40  percent  of  such  requirements  for  2000.  We
anticipate  that for 2001, internally generated funds will provide approximately
90 percent of total capital requirements for regulated operations, the remainder
to  be  derived  from  bank  loans.
     In  connection  with  the  foregoing,  see Item 7. MD and A - Liquidity and
Capital  Resources.

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  Canal site and other
environmental  matters see Item 7. MD and - Environmental Matters, and Note I of
Notes  to  Annual  Report.

UNREGULATED  BUSINESSES
     In  1998, we sold the assets of our wholly owned subsidiary, Green Mountain
Propane Gas Company.  In 1999, Green Mountain Resources, Inc. sold its remaining
interest  in  Green  Mountain Energy Resources to Green Funding I.  During 1999,
the  Company  discontinued  operations  of  Mountain  Energy,  Inc.  ("MEI"),  a
subsidiary  of  the  Company  that  invests in wastewater, energy efficiency and
generation  businesses.  The  loss  in  2000  reflects the sale of most of MEI's
remaining  energy  assets  and the current estimated costs of winding down MEI's
wastewater  businesses.  For  information  regarding  our  remaining unregulated
businesses,  see  Item  7.  MD  and A - Future Outlook - Unregulated Businesses.


<PAGE>
EXECUTIVE  OFFICERS

The Executive Officers names, ages, and positions of the Company as of March 15,
2001  are:


Nancy  Rowden  Brock      45
Vice  President,  Chief Financial Officer and Treasurer since December 1998, and
Secretary  since  August  1999.  Chief Corporate Strategic Planning Officer from
March  1998  to  December  1998.  Prior  to  joining  the Company, she was Chief
Financial Officer of SAL, Inc., 1997; and Senior Vice President, Chief Financial
Officer  and  Treasurer  for  the  Chittenden  Corporation  from  1988  to 1996.

Christopher  L.  Dutton    52
     President,  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       44
     Controller  since October 1996.  Manager of General Accounting from 1990 to
1996.

Walter  S.  Oakes         54
     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          40
     Senior  Vice  President-Customer  and  Organizational  Development  since
December 1999. Vice President-Administration from February 1999 through December
1999.  Vice President, Human Resources and Organizational Development from March
1998  to  February  1999.  Prior  to  joining  the Company, she was President of
HRworks,  a  human  resources  management firm, from January 1997 to March 1998.
From  1992  to January 1997, she worked for KeyCorp in Vermont, most recently as
Senior  Vice  President  Community Banking.  At KeyCorp, she also served as Vice
President  Administration  and  Vice  President  of  Human  Resources.

Stephen  C.  Terry       58
     Senior  Vice  President-Government  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.

Jonathan  H.  Winer     49
     President  of  Mountain  Energy, Inc. since March 1997.  Vice President and
Chief  Operating  Officer  of  Mountain  Energy,  Inc.  from 1989 to March 1997.
Resigned  effective  January  17,  2001.

     Officers  are  elected  by  the  Board  of Directors of the Company and its
wholly-owned  subsidiaries,  as appropriate, for one-year terms and serve at the
pleasure  of  such  boards  of  directors.



ITEM  2.  PROPERTY
GENERATING  FACILITIES
     Our  Vermont properties are located in five areas and are interconnected by
transmission  lines  of  VELCO and New England Power Company.  We wholly own and
operate eight hydroelectric generating stations with a total nameplate rating of
36.1  MW  and  an  estimated  claimed  capability  of  35.7 MW.  We also own two
gas-turbine  generating  stations  with an aggregate nameplate rating of 59.9 MW
and  an  estimated  aggregate claimed capability of 73.2 MW.  We have two diesel
generating  stations  with  an  aggregate  nameplate  rating  of  8.0  MW and an
estimated  aggregate  claimed  capability  of  8.6  MW.  We  also  have  a  wind
generating  facility  with  a  nameplate  rating  of  6.1  MW.
     We  also  own:
*     17.9%  of  the outstanding common stock, and are entitled to 17.662% (93.8
MW  of  a  total  531  MW)  of  the  capacity,  of  Vermont  Yankee,
*     1.1%  (7.1  MW  of  a  total 620 MW) joint-ownership share of the Wyman #4
plant  located  in  Maine,
*     8.8%  (31.0 MW of a total 352 MW) joint-ownership share of the Stony Brook
I  intermediate  units  located  in  Massachusetts,  and
*     11.0%  (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, 2000, approximately 1.5 miles of 115 kV
transmission  lines,  10.5 miles of 69 kV transmission lines, 5.4 miles of 44 kV
and 284.6 miles of 34.5 kV transmission lines.  Our distribution system includes
approximately  2,705 miles of overhead lines of 2.4 kV to 34.5 kV, and about 461
miles  of  underground  cable  of  2.4  kV  to  34.5 kV.  At such date, we owned
approximately  158,820  kVa  of  substation transformer capacity in transmission
substations,  569,750  kVa  of  substation  transformer capacity in distribution
substations and 1,085,000 kVa of transformers for step-down from distribution to
customer  use.

     The  Company  owns  34.8%  of the Highgate transmission inter-tie, a 225-MW
converter  and  transmission  line  used  to  transmit  power from Hydro-Quebec.
     We  also  own  29.5%  of the common stock and 30% of the preferred stock of
VELCO,  which  operates  a  high-voltage  transmission  system  interconnecting
electric  utilities  in  the  State  of  Vermont.

PROPERTY  OWNERSHIP
     The  Company's 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.
     The Company has also provided a second mortgage, lien and security interest
in  the  collateral pledged under the first mortgage bond indenture to two banks
participating  in  the  Company's revolving credit agreement with Fleet National
Bank  and  Citizens  Bank  of  Massachusetts.

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

                            Location           Name          Fuel    MW(1)
                         ---------------  ---------------  --------  -----
<S>                      <C>              <C>              <C>       <C>    <C>
Wholly Owned
Hydro . . . . . . . . .  Middlesex, VT    Middlesex #2     Hydro       3.3
Hydro . . . . . . . . .  Marshfield, VT   Marshfield #6    Hydro       4.9
Hydro . . . . . . . . .  Vergennes, VT    Vergennes #9     Hydro       2.1
Hydro . . . . . . . . .  W. Danville, VT  W. Danville #15  Hydro       1.1
Hydro . . . . . . . . .  Colchester, VT   Gorge #18        Hydro       3.3
Hydro . . . . . . . . .  Essex Jct., VT   Essex #19        Hydro       7.8
Hydro . . . . . . . . .  Waterbury, VT    Waterbury #22    Hydro       5.0  (4)
Hydro . . . . . . . . .  Bolton, VT       DeForge #1       Hydro       7.8
Diesel. . . . . . . . .  Vergennes, VT    Vergennes #9     Oil         4.2
Diesel. . . . . . . . .  Essex Jct., VT   Essex #19        Oil         4.4
Gas . . . . . . . . . .  Berlin, VT       Berlin #5        Oil        56.6
Turbine . . . . . . . .  Colchester, VT   Gorge #16        Oil        16.1
Wind. . . . . . . . . .  Searsburg, VT    Searsburg        Wind        1.2
Jointly Owned
Steam . . . . . . . . .  Vernon, VT       Vermont Yankee   Nuclear    93.8  (2)
Steam . . . . . . . . .  Yarmouth, ME     Wyman #4         Oil         7.1
Steam . . . . . . . . .  Burlington, VT   McNeil           Wood/Gas    6.6  (3)
Combined. . . . . . . .  Ludlow, MA       Stony Brook #1   Oil/Gas    31.0  (2)
                Total Winter Capability                              256.3
                                                                   ========
</TABLE>

(1)   Winter  capability  quantities  are  used  since  the Company's peak usage
occurs  during  the  winter months.  Some unit ratings are reduced in the summer
months  due  to higher ambient temperatures.  Capability shown includes capacity
and  associated  energy  sold  to  other  utilities.

(2)   For  a  discussion  of  the  impact  of  various power supply sales on the
availability  of  generating facilities, see Item 1. Business - Power Resources.

(3)   The  Company's entitlement in McNeil is 5.8 MW.  However, we receive up to
6.6  MW  as  a  result  of  other  owners'  losses  on  this  system.

(4)   Reservoir  has  been  drained,  dam  awaiting  repairs  by  Army  Corps of
Engineers.
CORPORATE  HEADQUARTERS

The  Company  terminated  an  operating  lease  for  its  corporate headquarters
building  and  two of its service center buildings in the first quarter of 1999.
During  1998,  the  Company recorded a loss of approximately $1.9 million before
applicable  income  taxes  to  reflect  the  probable  loss  resulting from this
transaction.  The  Company sold its corporate headquarters building in 1999, but
retained  ownership  of  the  two  service  centers.


ITEM  3.  LEGAL  PROCEEDINGS
     The  Company is involved in several legal proceedings, the outcome of which
will  significantly  affect  the viability and or potential profitability of the
Company.  The  most  significant  legal  proceeding  is  arbitration  about
Hydro-Quebec's  non-delivery  of power as a result of the January 1998 ice storm
in  eastern  North  America.  See  the  discussion  under  Item  7.  MD  and A -
Environmental  Matters,  Rate Matters, and Note I of the Notes to Annual Report.


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  the  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  1999  and  2000:
<TABLE>
<CAPTION>



      HIGH               LOW
      --------------  ---------
<C>   <S>             <C>        <C>
1999    $. . . . . .  $
      First Quarter.   11  3/16   9  3/4
      Second Quarter   11  5/16  8 11/16
      Third Quarter.         14   10 1/4
      Fourth Quarter     10 1/4    7 1/8
2000
      First Quarter.          9  6  9/16
      Second Quarter     8  1/2   6  5/8
      Third Quarter.     8  3/4   7  3/8
      Fourth Quarter    14  3/4  7  9/16
</TABLE>




The  number  of  common  stockholders  of record as of March 21, 2001 was 6,050.

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>
1999  $ 0.1375  $ 0.1375  $ 0.1375  $ 0.1375
2000  $ 0.1375  $ 0.1375  $ 0.1375  $ 0.1375
</TABLE>




Dividend  Policy  On  November  23,  1998,  the  Company's  Board  of  Directors
announced a reduction in the quarterly dividend from $0.275 per share to $0.1375
per  share on the Company's common stock.  The current indicated annual dividend
is  $0.55  per  share  of  common  stock.

     Our current dividend policy reflects changes affecting the electric utility
industry,  which  is moving away from the traditional cost-of-service regulatory
model  to  a  competition  based  market  for  power  supply.

     The  current environment prompted us to reassess the appropriateness of our
traditional dividend policy.   Historically, we based our dividend policy on the
continued validity of three assumptions: The ability to achieve earnings growth,
the  receipt  of  an allowed rate of return that accurately reflects our cost of
capital,  and  the retention of our exclusive franchise.  The Company's Board of
Directors  will continue to assess and adjust the dividend, when appropriate, as
the  Vermont  electric  industry  evolves  towards competition.  In addition, if
other  events  beyond  our  control  cause  the Company's financial situation to
deteriorate  further,  the  Board  of  Directors  will also consider whether the
current  dividend  level  is appropriate or if the dividend should be reduced or
eliminated.  See  Item  7.  MD  and  A  -  Future  Outlook,  Competition  and
Restructuring,  and  Note  C  of  Notes  to  Annual  Report. for a discussion of
dividend  restrictions.

<TABLE>
<CAPTION>

ITEM  6.   SELECTED  FINANCIAL  DATA

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


                                                2000       1999       1998       1997       1996
                                              ---------  ---------  ---------  ---------  ---------
In thousands, except per share data
<S>                                           <C>        <C>        <C>        <C>        <C>
Operating Revenues . . . . . . . . . . . . .  $277,326   $251,048   $184,304   $179,323   $179,009
Operating Expenses . . . . . . . . . . . . .   272,066    243,102    178,832    163,808    162,882
                                              ---------  ---------  ---------  ---------  ---------
    Operating Income . . . . . . . . . . . .     5,260      7,946      5,472     15,515     16,127
                                              ---------  ---------  ---------  ---------  ---------

Other Income
  AFUDC - equity . . . . . . . . . . . . . .       284        134        104        357        175
  Other. . . . . . . . . . . . . . . . . . .     2,422      3,319      1,509      1,074      1,739
                                              ---------  ---------  ---------  ---------  ---------
    Total other income . . . . . . . . . . .     2,706      3,453      1,613      1,431      1,914
                                              ---------  ---------  ---------  ---------  ---------

Interest Charges
  AFUDC - borrowed . . . . . . . . . . . . .      (228)       (91)      (131)      (315)      (468)
  Other. . . . . . . . . . . . . . . . . . .     7,485      7,274      8,007      7,965      7,866
                                              ---------  ---------  ---------  ---------  ---------
    Total interest charges . . . . . . . . .     7,257      7,183      7,876      7,650      7,398
                                              ---------  ---------  ---------  ---------  ---------
Net Income (Loss) from continuing. . . . . .       709      4,216       (791)     9,296     10,643
  operations before preferred dividends
Net Income (Loss) from discontinued
  operations, including provisions
  for loss on disposal . . . . . . . . . . .    (6,549)    (7,279)    (2,086)       142      1,316
Dividends on Preferred Stock . . . . . . . .     1,014      1,155      1,296      1,433      1,010
                                              ---------  ---------  ---------  ---------  ---------
Net Income (Loss)Applicable
  to Common Stock. . . . . . . . . . . . . .  $ (6,854)  $ (4,218)  $ (4,173)  $  8,005   $ 10,949
                                              =========  =========  =========  =========  =========

Common Stock Data
  Earnings per share-continuing operations .  $  (0.06)  $   0.57   $  (0.40)  $   1.54   $   1.95
  Earnings per share-discontinued operations  $  (1.19)  $  (1.36)  $  (0.40)  $   0.03   $   0.27
  Earnings per share-basic and diluted . . .  $  (1.25)  $  (0.79)  $  (0.80)  $   1.57   $   2.22
  Cash dividends declared per share. . . . .  $   0.55   $   0.55   $   0.96   $   1.61   $   2.12
  Weighted average shares outstanding. . . .     5,491      5,361      5,243      5,112      4,933
</TABLE>
<TABLE>
<CAPTION>

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


                                             2000      1999      1998      1997      1996
                                           --------  --------  --------  --------  --------
In thousands
<S>                                        <C>       <C>       <C>       <C>       <C>
ASSETS
  Utility Plant, Net. . . . . . . . . . .  $194,672  $192,896  $195,556  $196,720  $189,853
  Other Investments . . . . . . . . . . .    20,730    20,665    20,678    21,997    20,634
  Current Assets. . . . . . . . . . . . .    53,652    33,238    35,700    29,125    30,901
  Deferred Charges. . . . . . . . . . . .    46,036    41,853    35,576    35,831    43,224
  Non-Utility Assets. . . . . . . . . . .     1,518    11,099    27,314    42,060    39,927
                                           --------  --------  --------  --------  --------
    Total Assets. . . . . . . . . . . . .  $316,608  $299,751  $314,824  $325,733  $324,539
                                           ========  ========  ========  ========  ========

CAPITALIZATION AND LIABILITIES
  Common Stock Equity . . . . . . . . . .  $ 92,044  $100,645  $106,755  $114,377  $111,554
  Redeemable Cumulative Preferred Stock .    12,795    14,435    16,085    17,735    19,310
  Long-Term Debt, Less Current Maturities    72,100    81,800    88,500    93,200    94,900
  Capital Lease Obligation. . . . . . . .     6,449     7,038     7,696     8,342     9,006
  Current Liabilities . . . . . . . . . .    68,109    36,708    28,825    25,286    21,037
  Deferred Credits and Other. . . . . . .    61,794    59,125    59,889    53,723    54,968
  Non-Utility Liabilities . . . . . . . .     3,317         -     7,074    13,070    13,764
                                           --------  --------  --------  --------  --------
    Total Capitalization and Liabilities.  $316,608  $299,751  $314,824  $325,733  $324,539
                                           ========  ========  ========  ========  ========
</TABLE>

ITEM  7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF  OPERATIONS.
     In this section, we explain the general financial condition and the results
of  operations  for  Green  Mountain  Power  Corporation (the "Company") and its
subsidiaries.  This  explanation  includes:
*     factors  that  affect  our  business;
*     our  earnings  and  costs  in  the  periods presented and why they changed
between  periods;
*     the  source  of  our  earnings;
*     our  expenditures  for capital projects and what we expect they will be in
the  future;
*     where  we  expect  to  get  cash  for  future  capital  expenditures;  and
*     how  all  of  the  above  affects  our  overall  financial  condition.

     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 "Future
Outlook", "Transmission Issues", "Environmental Matters", "Rates" and "Liquidity
and  Capital  Resources"  in  this  section,  and  include:
*     regulatory  and  judicial  decisions  or  legislation;
*     weather;
*     energy  supply  and  demand  and  pricing;
*     contractual  commitments;
*     availability,  terms,  and  use  of  capital;
*     general  economic  and  business  environment;
*     nuclear  and  environmental  issues;  and
*     industry  restructuring  and  cost  recovery  (including  stranded costs).

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

EARNINGS  SUMMARY
          On  January 23, 2001, the Vermont Public Service Board ("VPSB") issued
an order (the "Settlement Order") approving a settlement between the Company and
the  Vermont  Department  of  Public  Service (the "Department") that grants the
Company  an  immediate  3.42  percent rate increase, and allows full recovery of
power supply costs under the Hydro-Quebec Vermont Joint Owners ("VJO") contract.
The  Settlement  Order paves the way for restoration of the Company's investment
grade  status  (See "Retail Rate Cases" and "Liquidity and Capital Resources" in
this  section)and  gives the Company an opportunity to  earn its allowed rate of
return  during  2001,  or  approximately  $1.96  per  share.  During  2000,  the
Company  lost $1.25 per share of common stock, compared with a loss per share of
$0.79 in 1999 and a loss per share of $0.80 in 1998.  The 2000 loss represents a
negative  return on average common equity of 7.1 percent.  The return on average
common equity was negative 4.0 percent in 1999 and negative 3.8 percent in 1998.
The  loss  from continuing operations was $0.06 per share in 2000, compared with
earnings  of  $0.57  per  share  in  1999  and  a loss of $0.40 in 1998. Certain
subsidiary  operations, classified as discontinued in 1999, lost $1.19 per share
in 2000, compared with a loss of $1.36 per share in 1999 and a loss of $0.40 per
share  in  1998.
     The  consolidated loss in 2000 was greater than the prior year consolidated
loss  as  a result of the VPSB Settlement Order that disallowed recovery of $3.2
million  or $0.35 per share in regulatory litigation costs and from higher power
supply  costs  that were not recovered in rates.  Power supply expense increased
$30.2  million in 2000, outpacing revenue growth of $26.3 million and reductions
in  depreciation  and  amortization  expense  of  $0.9  million.

     The  1999  improvement  in results from continuing operations was primarily
due  to  three  factors:
*     retail  operating  revenues  increased  by $15.1 million, reflecting a 5.5
percent  temporary rate increase that went into effect on December 15, 1998, and
a  3.9 percent increase in sales to commercial and industrial customers in 1999;
*     operating  costs  were  $3.7  million  lower  in 1999 due to the Company's
termination  of  its corporate headquarters lease, reduced costs associated with
the  Company's  headquarters  facilities  and  lower  payroll expense reflecting
mid-year  reductions  in  the  number  of  employees;  and
*     results  for  1998  reflected pretax charges of $9.8 million in disallowed
Hydro-Quebec  power costs for both 1998 and 1999, compared with disallowed power
costs  of  $7.5  million  for  2000  recorded  in  1999.

     The  1999  earnings  improvement  was  partially  offset  by:
*     a  $4.3 million increase in the capacity costs in 1999 associated with our
long-term  Hydro-Quebec  power  supply  contract;
*     an increase in the costs of short-term power following the deregulation of
energy  markets  in  New  England, as well as an increase in  our costs to serve
increased  local  loads  and an increase of approximately $5.4 million to supply
power  to  meet  contractual  obligations  under  the  Company's  December  1997
sell-back  agreement  with  Hydro-Quebec;  and
*     a  $1.9 million increase in capacity costs associated with a contract with
Vermont  Yankee  Nuclear  Power  Corporation  ("Vermont  Yankee").

     The  Company's  discontinued  operations lost $1.19 in 2000 compared with a
loss  of  $1.36  in  1999.  During  1999, the Company discontinued operations of
Mountain  Energy,  Inc.  ("MEI"),  a  subsidiary  of the Company that invests in
wastewater,  energy  efficiency  and  generation  businesses.  The  loss in 2000
reflects  the  sale  of  most  of  MEI's remaining energy assets and the current
estimated  costs  of  winding  down MEI's wastewater businesses.  During January
2001,  MEI  changed  its  name  to  Northern  Water  Resources,  Inc.  ("NWR").

FUTURE  OUTLOOK

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

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

     These  competitive  pressures  have  led the Company and other utilities to
offer, from time to time, special discounts or service packages to certain large
customers.
     In  certain states across the country, including all the New England states
except Vermont, legislation has been enacted to allow retail customers to choose
their  electricity  suppliers, with incumbent utilities required to deliver that
electricity  over  their  transmission  and  distribution systems (also known as
retail  wheeling).  Increased  pressure  in  the  electric  utility industry may
restrict  the  Company's  ability  to charge energy prices sufficient to recover
embedded costs, such as the cost of purchased power obligations or of generation
facilities  owned  by  the Company.  The amount by which such costs might exceed
market  prices  is  commonly  referred  to  as  stranded  costs.
     Regulatory  and  legislative  authorities  at the federal level and in some
states,  including  Vermont  where  legislation  has  not  been  enacted,  are
considering  whether,  when  and  how  to facilitate competition for electricity
sales  at  the  wholesale  and  retail  levels.  Recent  difficulties  in  some
regulatory  jurisdictions,  such as California, have dampened any immediate push
towards  deregulation  in  Vermont.  However, in the future, the Vermont General
Assembly through legislation, or the VPSB through a subsequent report, action or
proceeding,  may  allow  customers  to  choose their electric supplier.  If this
happens  without  providing  for  recovery of a significant portion of the costs
associated  with  our  power  supply  obligations  and  other costs of providing
vertically  integrated service, the Company's franchise, including our operating
results,  cash flows and ability to pay dividends at the current level, would be
adversely  affected.

ITEM  7A.  RISK  FACTORS-The  major  risk  factors  for the Company arising from
electric  industry  restructuring, including risks pertaining to the recovery of
stranded  costs,  are:
*     regulatory  and  legal  decisions;
*     cost  and  amount  of  default  service  responsibility;
*     the  market  price  of  power;  and
*     the  amount  of  market  share  retained  by  the  Company.

     There  can  be  no  assurance  that any potential future restructuring plan
ordered by the VPSB, the courts, or through legislation will include a mechanism
that  would  allow  for  full  recovery of our stranded costs and include a fair
return  on  those  costs  as  they  are being recovered.  If laws are enacted or
regulatory  decisions  are  made  that  do  not offer an adequate opportunity to
recover  stranded  costs,  we  believe  we  have  compelling  legal arguments to
challenge  such  laws  or  decisions.
     The  largest category of our potential stranded costs is future costs under
long-term  power  purchase  contracts,  which,  based  on current forecasts, are
above-market.  The magnitude of our stranded costs is largely dependent upon the
future  market price of power.  We have discussed various market price scenarios
with  interested  parties  for  the  purpose  of  identifying  stranded  costs.
Preliminary  market price assumptions, which are likely to change, have resulted
in  estimates  of  the  Company's stranded costs of between $74 million and $162
million.  We  intend  to  aggressively  pursue  mitigation  efforts  in order to
minimize  the  amount  and  maximize  the  recovery  of  these  costs.
     If  retail  competition  is implemented in Vermont, we cannot  predict what
the  impact  would  be  on  the  Company's  revenues  from  electricity  sales.
Historically,  electric  utility  rates  have  been based on a utility's cost of
service.  As  a  result,  electric  utilities  are subject to certain accounting
standards  that  apply  only  to  regulated  businesses.  Statement of Financial
Accounting  Standards  Number  71,  ("SFAS  71"),  Accounting for the Effects of
Certain  Types  of  Regulation,  allows  regulated  entities,  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 established approximately $47.5
million  of  net  regulatory  assets  and  liabilities  under  SFAS  71.
     The  Company  currently  complies  with  the provisions of SFAS 71.  In the
event  the Company determines that it no longer meets the criteria for following
SFAS  71,  the  accounting  impact would be an extraordinary, non-cash charge to
operations of an amount that would be material.  Factors that could give rise to
the  discontinuance  of  SFAS  71  include:
*     deregulation;
*     a  change  in  the  regulator's  approach to setting rates from cost-based
regulation  to  another  form  of  regulation;
*     increasing competition that limits our ability to sell utility services or
products  at  rates  that  will  recover  costs;  and
*     regulatory  actions  that  limit  rate  relief  to a level insufficient to
recover  costs.
     Under  Statement  of  Financial  Accounting  Standards Number 5 ("SFAS 5"),
Accounting  for  Contingencies,  the  enactment  of restructuring legislation or
issuance  of  a regulatory order containing provisions that do not allow for the
recovery  of  above-market power costs would require the Company to estimate and
record  losses immediately, on an undiscounted basis, for any above-market power
purchase  contracts  and other costs which are probable of not being recoverable
from  customers,  to  the  extent  that  those  costs  are  estimable.
     We  are  unable to predict what form future  legislation, if passed,  or an
order  if  issued, will take, and we cannot predict if or to what extent SFAS 71
will continue to be applicable in the future.  In addition, members of the staff
of  the  Securities and Exchange Commission have raised questions concerning the
continued  applicability  of  SFAS 71 to certain other electric utilities facing
restructuring.
          We  cannot  predict  whether  restructuring legislation enacted by the
Vermont  General Assembly or any subsequent report or actions of, or proceedings
before,  the  VPSB or the Vermont General Assembly would have a material adverse
effect on our operations, financial condition or credit ratings.  The failure to
recover  a  significant  portion  of our purchased power costs, or to retain and
attract  customers  in  a  competitive environment, would likely have a material
adverse  effect on our business, including our operating results, cash flows and
ability  to  pay  dividends  at  current  levels.
     Inherent  in  our  market  risk  sensitive instruments and positions is the
potential  loss  arising  from  adverse  changes  in  our  commodity  prices.
Restructuring  of  the  wholesale  market  for electricity has brought increased
price  volatility  to  our  power  supply  markets.
     The  price of electricity is subject to fluctuations resulting from changes
in  supply and demand. To reduce price risk caused by these market fluctuations,
we  have  established a policy to hedge (through the utilization of derivatives)
our  supply  and  related  purchase  and  sales  commitments,  as  well  as  our
anticipated  purchase  and  sales.  Because  the  commodities  covered  by these
derivatives  are  substantially  the  same commodities that the Company buys and
sells  in  the  physical  market,  no  special  correlation  studies  other than
monitoring  the  degree  of convergence between the derivative and cash markets,
are  deemed  necessary.  Changes  in  market  value  of  derivatives have a high
correlation  to  the  price  changes  of  the  hedged  commodities.
     A  sensitivity  analysis has been prepared to estimate the  exposure to the
market  price  risk  of  our  electricity  commodity  positions.  Our  daily net
commodity  position  consists  of  purchased  electric capacity. The table below
presents  market  risk  estimated  as the potential loss in fair value resulting
from  a  hypothetical  ten percent adverse change in prices.  Actual results may
differ  materially  from  the  table.

<TABLE>
<CAPTION>

Commodity Price Risk         At December 31, 2000

                          Fair Value     Market Risk
                        ---------------  ------------
                        (in thousands)
<S>                     <C>              <C>
Highest long position.  $       173,741  $     17,374

Highest short position  $       201,608  $     20,161

Average short position  $        27,867  $      2,787
</TABLE>



     Risk  factors associated with the discontinuation of MEI operations include
the  outcome  of  warranty litigation, and future cash requirements necessary to
minimize  costs  of  winding down wastewater operations.  Several municipalities
using  wastewater treatment equipment provided by Micronair, LLC, a wholly owned
subsidiary  of  MEI,  have commenced or threatened litigation against Micronair.
The ultimate loss remains subject to the disposition of remaining MEI assets and
liabilities,  and  could  exceed  the  amounts  recorded.

UNREGULATED  BUSINESSES
     In  2000,  we  significantly  reduced  our  investment  in  unregulated
businesses,  continuing  the  process  we began in June 1999, when we decided to
sell  or  otherwise dispose of the assets of MEI, and report its results as loss
from  operations  of  a  discontinued  segment.  MEI,  which  invested in energy
generation,  energy  efficiency  and  waste  water treatment projects, lost $6.5
million  in  2000,  compared with a loss of $7.3 million in 1999.  The 2000 loss
results  primarily  from  provisions  to  recognize present and estimated future
losses  from  the  sale  of  MEI's  remaining  businesses, including anticipated
operating  losses.
          Green  Mountain  Resources,  Inc. ("GMRI") was formed in April 1996 to
explore  opportunities  in  the  emerging  competitive retail energy market.  In
2000,  GMRI  earned  $19,000 compared with earnings of $583,000 in 1999.  GMRI's
earnings  in  1999  were  primarily due to the sale of its remaining interest in
Green  Mountain  Energy  Resources  ending  operations  for  this  subsidiary.
     The  Company's  unregulated rental water heater business earned $498,000 in
2000,  essentially  unchanged from 1999's net income of $500,000.  Both 2000 and
1999  results  contributed  earnings  of  $0.09  per  share  to  the  Company's
consolidated  results.

RESULTS  OF  OPERATIONS
OPERATING  REVENUES  AND  MWH  SALES-Operating revenues and megawatthour ("MWh")
sales  for  the  years  ended  2000,  1999  and  1998  consisted  of:

<TABLE>
<CAPTION>


                                               Years ended December 31,
                                      2000                1999        1998
                            -------------------------  ----------  ----------
<S>                         <C>                        <C>         <C>
   (dollars in thousands)
 Operating Revenues
     Retail. . . . . . . .  $                 188,849  $  179,997  $  164,855
     Sales for Resale. . .                     85,428      68,305      16,529
     Other . . . . . . . .                      3,049       2,746       2,920
                            -------------------------  ----------  ----------
 Total Operating Revenues.  $                 277,326  $  251,048  $  184,304
                            =========================  ==========  ==========

 MWH Sales-Retail. . . . .                  1,947,857   1,900,188   1,839,522
 MWH Sales for Resale. . .                  2,575,657   2,172,849     543,846
                            -------------------------  ----------  ----------
 Total MWH Sales . . . . .                  4,523,514   4,073,037   2,383,368
                            =========================  ==========  ==========
</TABLE>

<TABLE>
<CAPTION>

 Average  Number  of  Customers

                                          Years ended December 31,
                                         2000             1999    1998
                               ------------------------  ------  ------
<S>                            <C>                       <C>     <C>
    Residential . . . . . . .                    72,424  71,515  71,301
    Commercial and Industrial                    12,769  12,461  12,193
    Other . . . . . . . . . .                        65      66      70
                               ------------------------  ------  ------
 Total Number of Customers. .                    85,258  84,042  83,564
                               ========================  ======  ======
</TABLE>






Differences  in  operating  revenues  were  due  to  changes  in  the following:

<TABLE>
<CAPTION>


 Change in Operating Revenues     1999 to   1998 to

                                   2000     1999
                                  -------  -------
   (In thousands)
<S>                               <C>      <C>
 Retail Rates. . . . . . . . . .  $ 4,230  $ 9,395
 Retail Sales Volume . . . . . .    4,622    5,747
 Resales and Other Revenues. . .   17,426   51,602
                                  -------  -------
 Increase in Operating Revenues.  $26,278  $66,744
                                  =======  =======
</TABLE>

In 2000, total electricity sales increased 11.1 percent due principally to sales
for  resale  executed  pursuant to the Morgan Stanley Capital Group, Inc. ("MS")
agreement,  described  in  more  detail  below  under the headings "Power Supply
Expense"  and  "Power  Contract Commitments". Total operating revenues increased
$26.3  million  or  10.5  percent  primarily  for  the same reason. Total retail
revenues  increased  $8.9  million  or  4.9  percent  in  2000 primarily due to:
*     a 3.0 percent retail rate increase that went into effect January 2000; and
*     a  2.6 percent increase in sales of electricity to both our commercial and
industrial  and  our  residential  customers  resulting  primarily from customer
growth  and  load  growth  for  our  largest  customer.

     In  1999, total electricity sales increased 70.9 percent due principally to
sales  for  resale  executed  pursuant  to  the  MS  agreement.  Total operating
revenues  increased  $66.7  million or 36.2 percent in 1999 for the same reason.
Total  retail  revenues increased $15.1 million or 9.2 percent in 1999 primarily
due  to:
*     a  5.5  percent  retail  rate  increase  for  service rendered on or after
December  15,  1998;
*     a  3.9  percent  increase  in  sales  of electricity to our commercial and
industrial  customers  resulting  from  customer growth and increased use of air
conditioning  during  the  spring  and  summer  months;  and
*     a 3.3 percent increase in sales of electricity to residential customers, a
result  of  customer  growth  and  a  warmer  than  normal  summer.
     International  Business  Machines  ("IBM"),  the  Company's  single largest
customer,  operates  manufacturing  facilities in Essex Junction, Vermont. IBM's
electricity  requirements for its main plant and an adjacent plant accounted for
11.2,  11.8, and 14.7 percent of the Company's total operating revenues in 2000,
1999,  and  1998, respectively, and 16.5, 16.4 and 17.1 percent of the Company's
retail  operating  revenues  in  2000,  1999,  and 1998, respectively.  No other
retail  customer accounted for more than one percent of the Company's revenue in
any  year.
     Since  1995,  the  Company  has  had  agreements  with  IBM with respect to
electricity  sales above agreed-upon base-load levels.  On December 8, 2000, the
VPSB  approved  a  new  three-year agreement between the Company and IBM, ending
December 31, 2003. The price of power for the renewal period of the agreement is
above  our  marginal  costs  of  providing  incremental  service  to  IBM.

POWER  SUPPLY  EXPENSES-Our inability to recover our power supply costs has been
the  primary  reason for the poor performance of the Company's common stock over
the  past  three  years.  The Settlement Order removes this obstacle by allowing
the  Company  rate  recovery  of  its  estimated  power  supply  costs for 2001.
Furthermore,  the  Settlement Order allows the Company to use approximately $6.0
million  in rate levelization cash flow to achieve its allowed rate of return in
2001  and  2002,  and, together with the extension of our power supply agreement
with  MS,  provides  us an opportunity to recover our power supply costs in 2002
without further rate relief (See "Power Supply Commitments", "Retail Rate Cases"
and  "Risk  Factors"  in  this  section).
     Power  supply  expenses  constituted  79.4, 75.4, and 67.7 percent of total
operating  expenses  for  the  years  2000,  1999, and 1998, respectively. Power
supply  expenses  increased  by  $30.2 million or 16.5 percent in 2000 and $62.2
million or 51.4 percent in 1999. The increase in power supply expenses from 1999
to  2000  resulted  from  the  following:
*     a  $20.0 million increase from power purchased for resale, primarily under
a  power  supply agreement discussed below, whereby we buy power from MS that is
sufficient  to  serve  pre-established load requirements at a pre-defined price;
*     a  $7.7  million  increase  in  energy  costs  arising from a power supply
arrangement  with  Hydro-Quebec,  discussed  below,  whereby Hydro-Quebec has an
option  to  purchase  energy at prices that were below market replacement costs;
*     the costs to serve increased retail sales of electricity of 2.8 percent in
2000  and  higher  unit  power  supply  costs;  and
*     a  $3.6  million  increase in capacity costs associated with our long-term
Hydro-Quebec  power  supply  contract.

     These  amounts were partially offset by a reduction in 2000 of $9.7 million
in  losses  accrued  for  the  Hydro-Quebec  power  cost disallowance under past
regulatory  rulings.  Results  for 1999 reflected pretax charges of $2.2 million
in  disallowed  Hydro-Quebec  power costs, compared with the amortization during
2000 of accrued power expense of $7.5 million for 2000 that had been recorded in
1999.     The  power  supply  costs  of  Company-owned generation increased 74.8
percent  or  $4.2  million  in  2000 due to purchases by MS under a power supply
agreement  discussed  below  and  because  units  were  dispatched  for  system
reliability  requirements  due  to  the  unavailability  of certain transmission
facilities.  Power  supply  expenses  increased by $62.2 million or 51.4 percent
from  1998  to  1999.  The  increase  in power supply expenses from 1998 to 1999
resulted  from  the  following:
*     a  $57.0  million  increase  reflecting  the  power  purchase  and  supply
agreement  discussed  below,  whereby we buy power from MS that is sufficient to
serve  pre-established  load  requirements  at  a  pre-defined  price;
*     a  $4.3 million increase in the capacity costs in 1999 associated with our
long-term  Hydro-Quebec  power  supply  contract;
*     an increase in the costs of short-term power following the deregulation of
wholesale  energy markets in New England, as well as an increase in our costs to
serve  increased local loads and to supply power to meet contractual obligations
under  the  Company's December 1997 sell-back arrangement with Hydro-Quebec (net
cost  approximately  $5.4  million);  and
*     a  $1.9  million  increase  in  Vermont  Yankee  capacity  costs.

     These  amounts  were  partially  offset  by  a reduction of $2.3 million in
losses  accrued  for the Hydro-Quebec power cost disallowance.  Results for 1998
reflected  pretax charges of $9.8 million in disallowed Hydro-Quebec power costs
for both 1998 and 1999, compared with disallowed power costs of $7.5 million for
2000  recorded  in  1999.
     The  power  supply costs of Company-owned generation decreased 13.0 percent
in  1999  due  to the severe 1998 ice storm in New England that caused increased
usage  in  that  year  of  peak  generation  resources to replace power that was
unavailable  from  Hydro-Quebec.
          An Independent System Operator in New England ("ISO") replaced the New
England  Power  Pool  ("NEPOOL")  effective  May  1,  1999.  The  ISO works as a
clearinghouse  for  purchasers and sellers of electricity in the new deregulated
wholesale  markets.  Sellers  place  bids  for  the  sale of their generation or
purchased  power  resources  and  if demand is high enough the output from those
resources  is  sold.
     We must purchase electricity to meet customer demand during periods of high
usage  and  to  replace  energy repurchased by Hydro-Quebec under an arrangement
negotiated  in  1997.  Our  costs  to serve demand during periods of warmer than
normal  temperatures  in summer months and to replace such energy repurchases by
Hydro-Quebec  rose  substantially  after  the  wholesale  power  markets  became
deregulated,  which  caused  much  greater  volatility  in  spot  prices  for
electricity.  The  cost  of  securing  future  power  supplies  has  also  risen
substantially  in  tandem  with  higher  summer  power supply costs. The Company
cannot  predict  the duration or the extent to which future prices will continue
to  trade  above  historical  levels  of  cost.  If  the new markets continue to
experience  the  volatility  evident during 1999 and 2000, our earnings and cash
flow  could  be  adversely  impacted  by  a  material  amount.

POWER  CONTRACT  COMMITMENTS-  On  February 11, 1999, we entered into a contract
with  MS  as  a result of our power requirements solicitation in 1998.  A master
power  purchase  and sales agreement ("PPSA") defines the general contract terms
under  which  the  parties  may transact.  The sales under the PPSA commenced on
February  12,  1999  and  will  terminate  after  all  obligations  under  each
transaction entered into by MS and the Company has been fulfilled.  The PPSA has
been noticed to the VPSB and filed with the Federal Energy Regulatory Commission
("FERC").  In  January  2001, the PPSA was modified and extended to December 31,
2003.
     The  PPSA  provides us with a means of managing price risks associated with
changing  fossil  fuel prices. On a daily basis, and at MS's discretion, we sell
power  to  MS from either (i) all or part of our portfolio of power resources at
predefined  operating  and  pricing  parameters  or  (ii)  any  power  resources
available  to  us,  provided  that  sales  of  power  from  sources  other  than
Company-owned  generation  comply  with  the  predefined  operating  and pricing
parameters.   MS  then  sells  to us, at a predefined price, power sufficient to
serve  pre-established load requirements.  MS is also responsible for scheduling
supply  resources.  We  remain  responsible  for  resource  performance  and
availability.  MS  provides  no  coverage against major unscheduled outages. The
Company  and  MS  have  agreed  to the protocols that are used to schedule power
sales  and  purchases and to secure necessary transmission. We estimate that the
Company  saved approximately $4.8 million during 2000 over what our energy costs
would  have  been  absent  the PPSA due to our avoiding significant increases in
2000  fossil  fuel  prices.
     During  1994,  we  negotiated an arrangement with Hydro-Quebec that reduced
the  cost  under  our  1987  contract  with  Hydro-Quebec over the November 1995
through  October  1999  period  (the  "July  1994  Agreement").
     As  part  of  the  July  1994 Agreement, we were obligated to purchase $4.0
million  (in  1994  dollars)  worth  of  research  and  development  work  from
Hydro-Quebec  over  a  four-year period (which has since been extended to 2001),
and  made  a  $6.5  million  (in  1994 dollars) payment to Hydro-Quebec in 1995.
Hydro-Quebec retains the right to curtail annual energy deliveries by 10 percent
up to five times, over the 2000 to 2015 period, if documented drought conditions
exist  in  Qu  bec.
     During  the first year of the July 1994 Agreement (the period from November
1995  through  October  1996), the average cost per kilowatt-hour of Schedules B
and  C3  combined  was cut from 6.4 to 4.2 cents per kilowatt-hour, a 34 percent
(or  $16  million)  cost  reduction.  Over the period from November 1996 through
December 2000 and accounting for the payments to Hydro-Quebec, the combined unit
costs  will  be  lowered  from 6.5 to 5.9 cents per kilowatt-hour, reducing unit
costs  by  10  percent  and  saving  $20.7  million  in  nominal  terms.
     Under  a  power  supply  arrangement  executed in January 1996 ("9601"), we
received  payments from Hydro-Quebec of $3.0 million in 1996 and $1.1 million in
1997.  Under  9601  we are required to shift up to 40 megawatts of deliveries to
an  alternate  transmission  path,  and  use  the  associated  portion  of  the
NEPOOL/Hydro-Quebec  interconnection facilities to purchase power for the period
from  September 1996 through June 2001 at prices that vary based upon conditions
in  effect when the purchases are made.  9601 also provides for minimum payments
by the Company to Hydro-Quebec for periods in which power is not purchased under
the  arrangement.  9601  allows  Hydro-Quebec  to  curtail  deliveries of energy
should  it  need  to  use  certain  resources  to  supplement  available supply.
Hydro-Quebec did curtail deliveries in the fourth quarter of 2000.  Although our
level of future benefits will depend on various factors, including market prices
and availability of energy from HQ, we estimate that 9601 has provided a benefit
of  approximately $3.0 million on a net present value basis through December 31,
2000.
     Under  a  separate  arrangement  executed  on  December  5,  1997 ("9701"),
Hydro-Quebec  paid  $8.0  million  to  the  Company in 1997.  In return for this
payment, we provided Hydro-Quebec options for the purchase of power.  Commencing
April 1, 1998 and effective through the term of the 1987 Contract, which ends in
2015,  Hydro-Quebec  may  purchase  up  to  52,500 MWh ("option A") on an annual
basis, at the 1987 Contract energy prices, which are substantially below current
market  prices.  The  cumulative  amount  of  energy that may be purchased under
option  A  shall  not  exceed  950,000  MWh
     Over  the  same  period,  Hydro-Quebec may exercise an option to purchase a
total  of  600,000  MWh  ("option  B")  at the 1987 Contract energy price. Under
option  B, Hydro-Quebec may purchase no more than 200,000 MWh in any year. As of
December  31, 2000, Hydro-Quebec had purchased or called to purchase 349,000 MWh
under  option  B,  including  calls  for  January  and  February  of  2001.
     In  2000,  Hydro-Quebec  exercised  option  A  and  option  B,  calling for
deliveries  to third parties at a net cost to the Company of approximately $14.0
million (including the cost of January and February, 2001 calls, and the cost of
related  financial  positions), which was due to higher energy replacement costs
incurred  by  the  Company.  Approximately $6.6 million of the $14.0 million net
9701  costs  were  recovered  in  rates  on  an  annual  basis.
     In  1999, Hydro-Quebec called for deliveries to third parties at a net cost
of  approximately  $6.3  million.  Hydro-Quebec's  option  to  curtail  energy
deliveries  pursuant  to the July 1994 Agreement can be exercised in addition to
these  purchase  options.
     The  VPSB,  in  the Settlement Order said, "The record does not demonstrate
that  any  other New England utility foresaw the extent and degree of volatility
that  has  developed  in  the  New  England wholesale power markets. Absent that
volatility,  the  97-01  Agreement  would  not  have  had  adverse  effects." In
conjunction  with  the  Settlement  Order,  Hydro-Quebec  committed  to  the
Department,  that  it  would  not  call any energy under option B of 9701 during
2002.
     In  1999, the Company and the other Vermont Joint Owners who are parties to
the  Hydro-Quebec  contract  initiated  an  arbitration  against  Hydro-Quebec,
pursuant  to  the  1987  Contract  terms,  to  determine  whether Hydro-Quebec's
suspension  of  deliveries of power to Vermont during and after the January 1998
ice  storm evidenced a default by Hydro-Quebec under the terms of that contract.
Hydro-Quebec maintains that the "force majeure" (superior or irreversible force)
provision  in  the 1987 Contract applies, which could excuse its non-delivery of
power  under  these  circumstances.  Arbitration  of  the  dispute  may  lead to
remedies  having  a material impact on our contractual obligation, including the
possibility  that  the  1987  Contract  be  declared  terminated  or  void.  If
arbitration  results in a cash payment, it will first be applied to a regulatory
asset  of  $4.7  million  for arbitration litigation costs. The Settlement Order
provides  that  the  Company  will  not earn a return on these litigation costs,
unless  the  case  results in lower power supply costs for ratepayers.  Hearings
have  concluded  and  a  decision is expected in April 2001.  If the contract is
declared  terminated  or  void,  the Company would have to replace a substantial
amount  of  its  power  needs  at  terms  which could materially exceed the 1987
Contract  price  for  2001.  The  Company  believes  that  it  could  contract
replacement  power  at  costs  below  the  long term costs of the 1987 Contract.

OTHER  OPERATING  EXPENSES-  Other  operating expenses increased $0.1 million in
2000.  The  increase  is  primarily  due to a $3.2 million charge for disallowed
regulatory  litigation  costs,  ordered  by  the  VPSB as part of the Settlement
Order.  The increase was offset by a $3.3 million decrease in administrative and
general  expense caused by the Company's reorganization efforts that reduced the
size  of  the  workforce  and  lowered  building  occupancy  costs.

     Other  operating  expenses  decreased $3.7 million or 17.4 percent in 1999.
The  decrease  resulted  from:
*     a $1.9 million estimated loss in 1998 to recognize the cost of terminating
the  Company's corporate headquarters operating lease.  The facilities were sold
in  April  1999;
*     a $1.4 million reduction in administrative and general salaries related to
a  workforce  reduction  plan;
*     the elimination in 1999 of a regulatory liability of $1.2 million relating
to  the  Company's  former  corporate  headquarters;  and
*     reductions in lease expense and facility carrying costs resulting from the
disposal  of  the  former  headquarters.
     These  savings  were  partially  offset by increased costs of approximately
$1.8  million  associated  with  the  Company's  reorganization.
TRANSMISSION  EXPENSES-Transmission  expenses  increased  $1.5  million  or 14.0
percent  in  2000  primarily  due to congestion charges that reflect the lack of
adequate  transmission  or  generation  capacity in certain locations within New
England. These charges are allocated to all ISO New England members. The Company
is  unable  to  predict  the  magnitude  or duration of future congestion charge
allocation,  but amounts could be material. Transmission expenses increased $1.4
million or 15.0 percent in 1999 due to costs associated with the creation of the
ISO  as the clearing house for power trades in New England and due to refunds in
1998  from  Central Vermont Public Service Corp.  and New England Power Company.
     A  FERC  ruling  in  December  2000  required ISO New England to revise its
installed  capability  ("ICAP") deficiency charge of $0.17 per kw month to $8.75
per kw month retroactive to August 1, 2000. On January 10, 2001, FERC stayed its
order  "to  ensure  that  bills  for past periods will not be assessed until the
Commission  has  considered  the  pending  requests  for  rehearing,  which,  if
successful,  would  then  require extensive refunds and surcharges." On March 6,
2001,  FERC  issued  an Order on Rehearing in which it partly reversed itself on
the ICAP charge.  Although the Commission first concluded that a $8.75 charge is
reasonable  and  that the charge would remain in place until the ISO supports an
acceptable  superseding proposal, the Commission then concluded that reinstating
the  $8.75  would have a large cost impact.  As a result, the $0.17 per kW month
charge  was  reinstated from August 1, 2000 until April 1, 2001.  The Commission
allowed  the  $8.75  charge  to  become  effective  on  April  1, 2001 until the
effective  date  of any superseding charge the Commission might accept. On March
16,  2001,  an  ISO  New  England participant filed a request for re-hearing the
FERC's March 6, 2001 Order on Rehearing.  The request asks for a reversal of the
lowered  ICAP charge for the period from August 1, 2000 until April 1, 2001.  If
the  lowered  ICAP  charge  is increased to $8.75 per kw month, then the Company
would be required to pay ISO New England approximately $1.4 million.  Management
cannot  determine  the  ultimate  impact  of  the  request  at  this  time.
     In  2000,  FERC  issued  a  separate  order  ("Order  2000")  requiring all
utilities  to  file  plans  for  the  formation  and  administration of regional
transmission  organizations  ("RTO").  In  January  2001,  the Company and other
Vermont  transmission  owning companies filed in compliance with Order 2000. The
Vermont  companies  support  the  Petition  for Declaratory Order by various New
England transmission owning companies, with reservations. The Vermont companies'
principal  concerns  relate  to:
*     whether a New England RTO ("NERTO") will include all non-Pool Transmission
Facilities  in  the  NERTO  Tariff  on  a  rolled  in  basis;
*     whether  Highgate  and  Phase  I/Phase  II transmission facilities will be
included  in  the  Tariff  without  a  separate  transmission  levy;
*     whether  NERTO  will  continue  the  transition  to  a  single  regional
transmission  rate;  and
*     the  percentage  of equity that transmission owners may acquire in the new
organization.
     The  Company  is  unable to estimate how these issues will be resolved, but
the  impact  could  be  material.

MAINTENANCE EXPENSES-Maintenance expenses decreased $0.1 million  or 1.4 percent
in  2000 due to changes in scheduled maintenance. Maintenance expenses increased
$1.5  million  or  29.6  percent  in  1999, reflecting increased expenditures on
right-of-way  maintenance  programs.

DEPRECIATION  AND  AMORTIZATION-     Depreciation  and  amortization  expenses
decreased  $0.9 million or 5.5 percent in 2000 due to reductions in amortization
of  demand  side  management  costs that were only partially offset by increased
depreciation of utility plant in service. In 1999, depreciation and amortization
were  at  similar  levels  compared  with  that  of  1998.
INCOME  TAXES-Income  tax  amounts  decreased for 2000 due to an increase in the
Company's  taxable  loss.  Income  taxes decreased for 1999 due to a decrease in
taxable  income.

OTHER  INCOME-     Other  income  decreased  $0.7  million in 2000 due to a $0.6
million  gain  on the 1999 sale of GMER.  Other income increased $1.9 million in
1999,  due  to  the 1999 gain on the sale of the Company's remaining interest in
GMER  discussed  previously  under  "Unregulated Businesses", and a $0.9 million
write-off  in  1998  for  disallowed  costs  at  our  Searsburg  wind  project.

INTEREST  CHARGES-Interest expense increased $0.1 million or 1.0 percent in 2000
due  to  increases  in  short-term  debt  and  rising  interest  rates that were
partially  offset  by  reductions  in long-term debt. Interest expense decreased
$0.7  million  or  8.7  percent  in  1999, consistent with reductions in average
long-term  and  short-term  debt  outstanding  during  the  year.

DIVIDENDS  ON  PREFERRED  STOCK-     Dividends  on  preferred  stock  decreased
$141,000,  or  12.2  percent  in 2000 due to repurchases of preferred stock.  In
1999,  the  dividends on preferred stock also decreased $141,000 or 10.9 percent
for  the  same  reason.

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

PINE  STREET  BARGE CANAL SITE-The Federal Comprehensive Environmental Response,
Compensation,  and  Liability  Act ("CERCLA"), commonly known as the "Superfund"
law, generally imposes strict, joint and several liability, regardless of fault,
for  remediation  of  property  contaminated with hazardous substances.  We have
previously  been notified by the Environmental Protection Agency ("EPA") that we
are  one  of several potentially responsible parties ("PRPs") for cleanup of the
Pine  Street  Barge  Canal site in Burlington, Vermont, where coal tar and other
industrial  materials  were  deposited.
     In September 1999, we negotiated a final settlement with the United States,
the  State  of Vermont (the "State"), and other parties to a Consent Decree that
covers  claims  with respect to the site and implementation of the selected site
cleanup  remedy.  In  November 1999, the Consent Decree was filed in the federal
district  court.  The  Consent  Decree addresses claims by the EPA for past Pine
Street  Barge  Canal  site  costs, natural resource damage claims and claims for
past  and  future  oversight  costs.  The  Consent  Decree also provides for the
design  and  implementation  of  response  actions  at  the  site.
     As  of December 31, 2000, our total expenditures related to the Pine Street
Barge  Canal  site  since  1982 were approximately $23.5 million.  This includes
amounts  not  recovered  in  rates,  amounts recovered in rates, and amounts for
which  rate  recovery  has  been sought but which are presently awaiting further
VPSB  action.  The  bulk  of  these expenditures consisted of transaction costs.
Transaction  costs  include  legal  and  consulting  costs  associated  with the
Company's  opposition to the EPA's earlier proposals for a more expensive remedy
at  the  site, litigation and related costs necessary to obtain settlements with
insurers  and  other  PRPs  to  provide  amounts  required  to fund the clean up
("remediation  costs"),  and to address liability claims at the site.  A smaller
amount of past expenditures was for site-related response costs, including costs
incurred  pursuant  to  EPA  and  State orders that resulted in funding response
activities  at  the site, and to reimbursing the EPA and the State for oversight
and  related  response  costs.  The EPA and the State have asserted and affirmed
that  all  costs related to these orders are appropriate costs of response under
CERCLA  for  which  the  Company  and  other  PRPs  were  legally  responsible.
     We  estimate  that  we  have recovered or secured, or will recover, through
settlements  of  litigation  claims  against insurers and other parties, amounts
that  exceed  estimated  future  remediation  costs,  future  federal  and state
government  oversight  costs and past EPA response costs.  We currently estimate
our  unrecovered  transaction  costs  mentioned  above,  which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $12.4 million over the next 33
years.  The  estimated  liability is not discounted, and it is possible that our
estimate  of  future  costs  could  change  by  a material amount.  We also have
recorded  an offsetting regulatory asset and we believe that it is probable that
we  will  receive  future  revenues  to  recover  these  costs.
     Through  rate  cases  filed  in  1991,  1993, 1994, and 1995, we sought and
received  recovery  for  ongoing  expenses associated with the Pine Street Barge
Canal  site.    While  reserving  the  right  to  argue  in the future about the
appropriateness of full rate recovery of the site-related costs, the Company and
the  Department,  and  as applicable, other parties, reached agreements in these
cases  that  the  full  amount of the site-related costs reflected in those rate
cases  should  be  recovered  in  rates.
     We  proposed  in  our  rate  filing  made  on  June 16, 1997 recovery of an
additional  $3.0 million in such expenditures. In an Order in that case released
March  2,  1998,  the VPSB suspended the amortization of expenditures associated
with  the Pine Street Barge Canal site pending further proceedings.  Although it
did  not  eliminate  the  rate  base deferral of these expenditures, or make any
specific  order in this regard, the VPSB indicated that it was inclined to agree
with  other parties in the case that the ultimate costs associated with the Pine
Street  Barge Canal site, taking into account recoveries from insurance carriers
and  other  PRPs,  should  be  shared  between customers and shareholders of the
Company.  In  response  to  our  Motion for Reconsideration, the VPSB on June 8,
1998  stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
The Settlement Order released January 23, 2001 did not change the status of Pine
Street  cost  recovery.

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

RATES

RETAIL  RATE CASES- On March 2, 1998, the VPSB released its Order dated February
27,  1998  in  the  then  pending  rate  case  (the "1997 rate case").  The VPSB
authorized  us  to  increase  our rates by 3.61 percent, which gave us increased
annual  revenues  of  $5.6 million. The VPSB Order denied us the right to charge
customers  $5.48  million  of  the  annual  costs  for power purchased under our
contract  with  Hydro-Quebec.  The  VPSB  denied recovery of these costs for the
following  reasons:

*     The  VPSB claimed that we had acted imprudently by committing to the power
contract  with  Hydro-Quebec  in  August 1991 (the imprudence disallowance); and
*     To  the  extent  that the costs of power to be purchased from Hydro-Quebec
were  higher  than  current  estimates  of  market  prices  for power during the
contract  term,  after  accounting for the imprudence disallowance, the contract
power  was  decreed  not  "used  and  useful".

     We  appealed the VPSB's ruling in the 1997 rate case to the Vermont Supreme
Court.
     On  May  8,  1998,  we filed a request with the VPSB to increase our retail
rates  by  12.93 percent due to higher power costs, the cost of the January 1998
ice  storm,  and  investments in new plant and equipment (the "1998 rate case").
          On  November  18,  1998,  by  Memorandum of Understanding ("MOU"), the
Company, the Department and IBM agreed to stay rate proceedings in the 1998 rate
case  until  or after September 1, 1999, or such earlier date as the parties may
later  agree  to  or the VPSB may order.  The agreement to suspend our 1998 rate
case  delayed the date of a final decision on the 1998 rate case to December 15,
1999,  and we recognized an additional loss of $5.25 million in the last quarter
of  1998  representing  the effect of the continued disallowance of Hydro-Quebec
costs  through  December  15, 1999. The MOU provided for a 5.5 percent temporary
rate  increase,  to  produce  $8.9  million  in  annualized  additional revenue,
effective  with service rendered December 15, 1998.  An additional surcharge was
permitted,  without  further VPSB order, in order to produce additional revenues
necessary  to  provide the Company with the capacity to finance 1999 Pine Street
Barge Canal site expenditures.  The MOU was approved by the VPSB on December 11,
1998. The MOU did not provide for any specific disallowance of power costs under
our  purchase  power  contract with Hydro-Quebec.  Issues respecting recovery of
such  power  costs  were  preserved  for  future  proceedings.
     The stay and suspension of the 1998 rate case and the temporary rate levels
agreed  to  in the MOU were designed to allow us to continue to provide adequate
and  efficient  service  to  our  customers  while we sought mitigation of power
supply  costs.
      On September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments  to the MOU that the Company had entered into with the Department and
IBM.  The  two  amendments  continued the stay of proceedings until September 1,
2000,  with  a  final  decision  expected  by December 31, 2000.  The amendments
maintained  the  other  features  of  the original MOU, and the second amendment
provided for a temporary rate increase of 3 percent, in addition to the previous
temporary rate level, to become effective as of January 1, 2000.     The Company
reached  a  final settlement agreement with the Department in the 1998 rate case
during  November  2000.  The  final  settlement agreement contains the following
provisions:

*     A rate increase of 3.42 percent above existing rates, beginning with bills
rendered  January 23, 2001, and prior temporary rate increases became permanent;
*     Rates  set  at levels that recover the Company's Hydro-Quebec VJO contract
costs,  effectively  ending  the  regulatory  disallowances  experienced  by the
Company  over  the  past  three  years;
*     The  Company  agrees  not  to  seek any further increase in electric rates
prior  to  April  2002 (effective in bills rendered January 2003) unless certain
substantially  adverse  conditions  arise,  including  a  provision  allowing  a
request  for  additional rate relief if power supply costs increase in excess of
$3.75  million  over  forecasted  levels;
*     The  Company agreed to write off approximately $3.2 million in unrecovered
rate  case  litigation  costs,  and  to  freeze  its  dividend  rate  until  it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
*     Seasonal  rates  will  be  eliminated  in April 2001, which is expected to
generate  approximately $6.0 million in additional cash flow in 2001 that can be
utilized  to  offset  increased  costs  during  2001,  2002  and  2003;
*     The  Company  agrees  to consult extensively with the Department regarding
capital  spending commitments for upgrading our electric distribution system and
to  adopt  customer  care and reliability performance standards, in a first step
toward  possible  development  of  performance-based  rate-making;  and
*     The  Company  agrees  to  withdraw its Vermont Supreme Court appeal of the
VPSB's  Order  in  the  1997  rate  case.

     On  January  23,  2001, the VPSB approved the Company's settlement with the
Department,  with  two  additional  conditions:
*     The  VPSB  Order  requires  the Company and customers to 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;  and
*     The  second  condition  restricts  Company  investments  in  non-utility
operations.


LIQUIDITY  AND  CAPITAL  RESOURCES
CONSTRUCTION-Our  capital  requirements  result  from  the  need  to  construct
facilities  or  to  invest  in  programs to meet anticipated customer demand for
electric service.  Capital expenditures over the past three years and forecasted
for  2001  are  as  follows:










<TABLE>
<CAPTION>


             Generation     Transmission   Distribution   Conservation   Other*    Total
           ---------------  -------------  -------------  -------------  -------  -------
                                         (In thousands)
Actual:
---------
<S>        <C>              <C>            <C>            <C>            <C>      <C>
1998. . .  $           543  $         751  $       6,063  $       1,244  $ 4,568  $13,169
1999. . .              210            144          5,930          1,943    9,039   17,266
2000. . .            2,195            931          7,169             **    3,955   14,250
Forecast:
---------
2001. . .  $         2,830  $       2,060  $       8,540             **  $ 2,320  $15,750
</TABLE>

*  Other  includes  $6.1 million in 1999, $1.3 million in 2000, and $1.9 million
in  2001  for  the  Pine  Street  Barge  Canal  Site.
**A  state-wide Energy Efficiency Utility set up by the VPSB in 1999 manages all
energy  efficiency  programs, receiving funds the Company bills to its customers
as  a  separate  charge.

DIVIDEND  POLICY-  The  annual dividend rate was $0.55 per share at December 31,
2000.
     The  Settlement  Order  limits the dividend rate at its current level until
short  term  credit  facilities  are  replaced  with  long  term  debt or equity
financing.  Retained  earnings  at  December  31,  2001  were approximately $0.5
million.  The  Company  anticipates substantial improvement in retained earnings
during  2001,  beginning with the first quarter, and believes it will be able to
maintain  the  current  dividend rate. If retained earnings were eliminated, the
Company  would  not be able to declare a dividend under its Restated Articles of
Association.

FINANCING  AND  CAPITALIZATION-Internally-generated funds provided approximately
59  percent  of  requirements  for  2000,  1999  and  1998  combined.
Internally-generated  funds,  after  payment  of  dividends,  provide  capital
requirements  for  construction,  sinking  funds  and  other  requirements.   We
anticipate  that for 2001, internally generated funds will provide approximately
90  percent  of  total  capital  requirements  for  regulated  operations.
     At  December  31, 2000, our capitalization consisted of 49.3 percent common
equity,  43.8  percent  long-term  debt  and  6.9  percent  preferred  equity.
     On  June  21,  2000,  we renewed a $15.0 million revolving credit agreement
with  Fleet  National  Bank  and  Citizens  Bank  of  Massachusetts  (the "Fleet
Agreement").  The Fleet Agreement is for a period of 364 days and will expire on
June  20, 2001.  At December 31, 2000, there was $0.5 million outstanding on the
Fleet  Agreement.  The Fleet Agreement is secured by granting the banks a second
priority  mortgage,  lien  and security interest in the collateral pledged under
the  Company's  first  mortgage  bond  indenture.
     On  September  20,  2000,  we  established a $15.0 million revolving credit
agreement  with  KeyBank  National  Association ("KeyBank").  The agreement will
expire  on  September  19,  2001.  Pursuant  to  a  one year power supply option
agreement  between  the  Company  and  Energy East Corporation ("EE"), EE made a
payment  of  $15.0  million to the Company.  In exchange, the Company gave EE an
option to purchase energy from certain wholly owned production facilities, for a
period  not to exceed 15 years, if the funds are not returned to EE upon request
after  September 2001.  The Company was required to invest the funds provided by
EE  in  a certificate of deposit at KeyBank pledged by the Company to secure the
repayment  of the Keybank revolving credit facility. At December 31, 2000, there
was  $15.0  million  outstanding  on  the  KeyBank  line  of  credit.
     The Company anticipates that it will secure financing that replaces some or
all  of  its  expiring facilities during 2001.  The Settlement Order will likely
permit  restoration  of  the  Company's  investment  grade debt rating, allowing
arrangement  of  such  financing  as  the  Company  needs  during  2001.
     The  credit  ratings  of  the  Company's  securities  are:
<TABLE>
<CAPTION>

                            Fitch  Moody's  Standard & Poor's
                           -------- -------  -----------------
<S>                         <C>      <C>                <C>
First mortgage bonds . . .  BB+      Baa2               BBB
Unsecured medium term debt  BB-       --                 --
Preferred stock. . . . . .  B+       baa3               BB
</TABLE>
On  March  5,  2001,  Moody's  Investors  Service  upgraded  the Company's first
mortgage  bond  rating  to  Baa2  from Ba1, and upgraded the Company's preferred
stock rating to baa3 from ba3.  The rating action reflected Moody's earnings and
cash  flow  expectations  for  the  Company  following  the  Settlement  Order.
     On  August  25,  2000, Fitch (formerly Duff & Phelps) downgraded the credit
ratings  of  the Company to below investment grade and maintained the ratings on
Rating  Watch-Negative.  Since the Settlement Order, Fitch and Standard & Poor's
have  favorably  changed their outlook relative to the ratings direction for the
Company,  moving  us  from  Rating  Watch-Negative and Credit Watch- Negative to
Rating  Watch-Positive  and  Credit  Watch-Developing,  respectively.

NUCLEAR  DECOMMISSIONING-The  staff  of  the  SEC has questioned certain current
accounting practices of the electric utility industry regarding the recognition,
measurement  and  classification of decommissioning costs for nuclear generating
units  in  financial  statements.  In response to these questions, the Financial
Accounting  Standards  Board had agreed to review the accounting for closure and
removal  costs,  including  decommissioning.  We  do not believe that changes in
such  accounting,  if  required,  would have an adverse effect on the results of
operations  due  to  our  current  and future ability to recover decommissioning
costs  through  rates.

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




















39

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                                         40
    For  the  Years  Ended  December  31,  2000,  1999,  and  1998

Consolidated  Statements  of  Cash  Flows For the                             41
    Years  Ended  December  31,  2000,  1999,  and  1998

Consolidated  Balance  Sheets  as  of                                         42
    December  31,  2000  and  1999

Consolidated  Capitalization  Data  as  of                                    44
    December  31,  2000  and  1999

Notes  to  Consolidated  Financial  Statements                                45

Quarterly  Financial  Information                                           68

Report  of  Independent  Public  Accountants                                  69

Schedules

For  the  Years  Ended  December  31,  2000,  1999,  and  1998:

    II  Valuation  and  Qualifying  Accounts  and Reserves                    70

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

Consent  and  Report  of  Independent  Public  Accountants

             Arthur  Andersen  LLP                                          71


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,

                                                                                  2000       1999       1998
                                                                                ---------  ---------  ---------
(In thousands, except per share data)
<S>                                                                             <C>        <C>        <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $277,326   $251,048   $184,304
OPERATING EXPENSES
  Power Supply
    Vermont Yankee Nuclear Power Corporation . . . . . . . . . . . . . . . . .    34,813     34,987     32,910
    Company-owned generation . . . . . . . . . . . . . . . . . . . . . . . . .     9,756      5,582      6,412
    Purchases from others. . . . . . . . . . . . . . . . . . . . . . . . . . .   168,947    142,699     81,706
  Other operating. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    17,644     17,582     21,291
  Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    12,258     10,800      9,389
  Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     6,633      6,728      5,190
  Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . .    15,304     16,187     16,059
  Taxes other than income. . . . . . . . . . . . . . . . . . . . . . . . . . .     7,402      7,295      7,242
  Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      (691)     1,242     (1,367)
                                                                                ---------  ---------  ---------
    Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . .   272,066    243,102    178,832
                                                                                ---------  ---------  ---------
      OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . .     5,260      7,946      5,472
                                                                                ---------  ---------  ---------

OTHER INCOME
  Equity in earnings of affiliates and non-utility operations. . . . . . . . .     2,495      2,919      2,058
  Allowance for equity funds used during construction. . . . . . . . . . . . .       284        134        104
  Other income (deductions), net . . . . . . . . . . . . . . . . . . . . . . .       (73)       400       (549)
                                                                                ---------  ---------  ---------
    Total other income . . . . . . . . . . . . . . . . . . . . . . . . . . . .     2,706      3,453      1,613
                                                                                ---------  ---------  ---------
      INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . .     7,966     11,399      7,085
                                                                                ---------  ---------  ---------
INTEREST CHARGES
  Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     6,499      6,716      6,991
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       986        558      1,016
  Allowance for borrowed funds used during construction. . . . . . . . . . . .      (228)       (91)      (131)
                                                                                ---------  ---------  ---------
    Total interest charges . . . . . . . . . . . . . . . . . . . . . . . . . .     7,257      7,183      7,876
                                                                                ---------  ---------  ---------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND
  DISCONTINUED OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . .       709      4,216       (791)
Dividends on preferred stock . . . . . . . . . . . . . . . . . . . . . . . . .     1,014      1,155      1,296
                                                                                ---------  ---------  ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS . . . . . . . . . . . . . . . . . . .      (305)     3,061     (2,087)
Net loss from discontinued segment operations, net of applicable income taxes.         -       (603)    (2,086)
Loss on disposal, including provisions for
  operating losses during phaseout period, net of applicable income taxes. . .    (6,549)    (6,676)         -
                                                                                ---------  ---------  ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . . . . . . . . . .  $ (6,854)  $ (4,218)  $ (4,173)
                                                                                =========  =========  =========
COMMON STOCK DATA
Basic and diluted earnings (loss) per share from discontinued operations . . .  $  (1.19)  $  (1.36)  $  (0.40)
Basic and diluted earnings (loss) per share from continuing operations . . . .     (0.06)      0.57      (0.40)
                                                                                ---------  ---------  ---------
Basic and diluted earnings (loss) per share. . . . . . . . . . . . . . . . . .  $  (1.25)  $  (0.79)  $  (0.80)
                                                                                =========  =========  =========
Cash dividends declared per share. . . . . . . . . . . . . . . . . . . . . . .  $   0.55   $   0.55   $   0.96
Weighted average shares outstanding. . . . . . . . . . . . . . . . . . . . . .     5,491      5,361      5,243

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . . . . . . . . . .  $ 10,344   $ 17,508   $ 26,717
Net Income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    (5,840)    (3,063)    (2,877)
                                                                                ---------  ---------  ---------
                                                                                   4,504     14,445     23,840
                                                                                ---------  ---------  ---------
Cash dividends-redeemable cumulative preferred stock . . . . . . . . . . . . .     1,014      1,155      1,296
Cash dividends-common stock. . . . . . . . . . . . . . . . . . . . . . . . . .     2,997      2,946      5,036
                                                                                ---------  ---------  ---------
                                                                                   4,011      4,101      6,332
                                                                                ---------  ---------  ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . . . . . . . . . .  $    493   $ 10,344   $ 17,508
                                                                                =========  =========  =========
</TABLE>


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



<TABLE>
<CAPTION>


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

                                                                  2000          1999      1998
                                                             ---------------  --------  ---------
OPERATING ACTIVITIES:                                        (In thousands)
<S>                                                          <C>              <C>       <C>
Net  Loss . . . . . . . . . . . . . . . . . . . . . . . . .  $       (5,840)  $(3,063)   ($2,877)
Adjustments to reconcile net loss to net cash
  provided by operating activities:
  Depreciation and amortization . . . . . . . . . . . . . .          15,304    16,187     16,059
  Dividends from associated companies less equity income. .             (26)      169        812
  Allowance for funds used during construction. . . . . . .            (512)     (224)      (235)
  Amortization of purchased power costs . . . . . . . . . .           5,575     5,725      6,405
  Deferred income taxes . . . . . . . . . . . . . . . . . .             443     1,812       (112)
  Loss on discontinued segment operations . . . . . . . . .           6,549     6,676          -
  Deferred purchased power costs. . . . . . . . . . . . . .          (6,692)   (6,590)    (7,830)
  Accrued purchase power contract option call . . . . . . .           8,276         -          -
  Deferred arbitration costs. . . . . . . . . . . . . . . .          (3,184)   (1,684)         -
  Amortization of investment tax credits. . . . . . . . . .            (282)     (282)      (282)
  Provision for chargeoff of deferred regulatory asset. . .           3,229         -          0
  Environmental and conservation expenditures . . . . . . .          (2,073)   (8,048)     1,177
  Changes in:
    Accounts receivable . . . . . . . . . . . . . . . . . .          (3,862)      474     (1,611)
    Accrued utility revenues. . . . . . . . . . . . . . . .            (125)     (358)      (105)
    Fuel, materials and supplies. . . . . . . . . . . . . .            (766)     (150)       122
    Prepayments and other current assets. . . . . . . . . .            (165)    4,009       (983)
    Accounts payable. . . . . . . . . . . . . . . . . . . .           3,004       665     (1,893)
    Accrued income taxes payable and receivable . . . . . .            (372)   (1,611)    (2,473)
    Other current liabilities . . . . . . . . . . . . . . .          (7,341)    1,722      3,229
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .            (180)     (324)       536
                                                             ---------------  --------  ---------
  Net cash provided by continuing operations. . . . . . . .          10,959    15,105      9,939
  Net change in discontinued segment. . . . . . . . . . . .             245      (138)         -
                                                             ---------------  --------  ---------
  Net cash provided by operating activities . . . . . . . .          11,204    14,967      9,939

INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . .         (13,853)   (9,174)   (10,900)
Proceeds from sale of subsdiaries . . . . . . . . . . . . .           6,000         -     11,500
Investment in nonutility property . . . . . . . . . . . . .            (187)     (190)    (1,442)
                                                             ---------------  --------  ---------
  Net cash used in investing activities . . . . . . . . . .          (8,040)   (9,364)      (842)
                                                             ---------------  --------  ---------

FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . .           1,250     1,054      1,587
Investment in certificate of deposit, pledged for revolver.         (15,437)        -          -
Power supply option obligation. . . . . . . . . . . . . . .          15,419         -          -
Short-term debt, net. . . . . . . . . . . . . . . . . . . .           7,600       900      4,384
Cash dividends. . . . . . . . . . . . . . . . . . . . . . .          (4,011)   (4,101)    (6,332)
Reduction in preferred stock. . . . . . . . . . . . . . . .          (1,640)   (1,650)    (1,650)
Reduction in long-term debt . . . . . . . . . . . . . . . .          (6,700)   (1,700)    (6,767)
                                                             ---------------  --------  ---------

  Net cash used in financing activities . . . . . . . . . .          (3,519)   (5,497)    (8,778)
                                                             ---------------  --------  ---------
Net increase(decrease) in cash and cash equivalents . . . .            (355)      106        319

Cash and cash equivalents at beginning of period. . . . . .             696       590        271
                                                             ---------------  --------  ---------

Cash and cash equivalents at end of period. . . . . . . . .  $          341   $   696   $    590
                                                             ===============  ========  =========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
  Interest (net of amounts capitalized) . . . . . . . . . .  $        7,185   $ 7,034   $  7,857
  Income taxes, net . . . . . . . . . . . . . . . . . . . .           1,191       997      2,285
</TABLE>


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


<TABLE>
<CAPTION>



GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                           AT DECEMBER 31,

                                                    2000      1999
                                                  --------  --------
(In thousands)
<S>                                               <C>       <C>
ASSETS
UTILITY PLANT
  Utility plant, at original cost. . . . . . . .  $291,107  $283,917
  Less accumulated depreciation. . . . . . . . .   110,273   102,854
                                                  --------  --------
  Net utility plant. . . . . . . . . . . . . . .   180,834   181,063
  Property under capital lease . . . . . . . . .     6,449     7,038
  Construction work in progress. . . . . . . . .     7,389     4,795
                                                  --------  --------
    Total utility plant, net . . . . . . . . . .   194,672   192,896
                                                  --------  --------
OTHER INVESTMENTS
  Associated companies, at equity. . . . . . . .    14,373    14,545
  Other investments. . . . . . . . . . . . . . .     6,357     6,120
                                                  --------  --------
    Total other investments. . . . . . . . . . .    20,730    20,665
                                                  --------  --------
CURRENT ASSETS
  Cash and cash equivalents. . . . . . . . . . .       341       656
  Certficate of deposit, pledged as collateral .    15,437         -
  Accounts receivable, customers and others,
  less allowance for doubtful accounts
    of $463, and 398 . . . . . . . . . . . . . .    22,365    18,503
  Accrued utility revenues . . . . . . . . . . .     7,093     6,969
  Fuel, materials and supplies, at average cost.     4,056     3,290
  Prepayments. . . . . . . . . . . . . . . . . .     2,525     2,197
  Income tax receivable. . . . . . . . . . . . .     1,613     1,241
  Other. . . . . . . . . . . . . . . . . . . . .       222       382
                                                  --------  --------
    Total current assets . . . . . . . . . . . .    53,652    33,238
                                                  --------  --------
DEFERRED CHARGES
  Demand side management programs. . . . . . . .     6,358     7,640
  Purchased power costs. . . . . . . . . . . . .    11,789     7,435
  Pine Street Barge Canal. . . . . . . . . . . .    12,370     8,700
  Other. . . . . . . . . . . . . . . . . . . . .    15,519    19,521
                                                  --------  --------
    Total deferred charges . . . . . . . . . . .    46,036    43,296
                                                  --------  --------

NON-UTILITY
  Cash and cash equivalents. . . . . . . . . . .         -        40
  Other current assets . . . . . . . . . . . . .         8         8
  Property and equipment . . . . . . . . . . . .       252       253
  Business segment held for disposal . . . . . .         -     9,477
  Other assets . . . . . . . . . . . . . . . . .     1,258     1,321
                                                  --------  --------
    Total non-utility assets . . . . . . . . . .     1,518    11,099
                                                  --------  --------

TOTAL ASSETS . . . . . . . . . . . . . . . . . .  $316,608  $301,194
                                                  ========  ========
</TABLE>


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






<TABLE>
<CAPTION>


GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  BALANCE  SHEETS
                                           AT DECEMBER 31,

                                                      2000       1999
                                                    ---------  ---------
(In thousands except share data)
<S>                                                 <C>        <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
  Common stock equity
  Common stock, $3.33 1/3 par value,
  authorized 10,000,000 shares (issued
  5,582,552, and 5,425,571). . . . . . . . . . . .  $ 18,608   $ 18,085
  Additional paid-in capital . . . . . . . . . . .    73,321     72,594
  Retained earnings. . . . . . . . . . . . . . . .       493     10,344
  Treasury stock, at cost (15,856 shares). . . . .      (378)      (378)
                                                    ---------  ---------
    Total common stock equity. . . . . . . . . . .    92,044    100,645
  Redeemable cumulative preferred stock. . . . . .    12,560     12,795
  Long-term debt, less current maturities. . . . .    72,100     81,800
                                                    ---------  ---------
    Total capitalization . . . . . . . . . . . . .   176,704    195,240
                                                    ---------  ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . .     6,449      7,038
                                                    ---------  ---------
CURRENT LIABILITIES
  Current maturities of preferred stock. . . . . .       235      1,640
  Current maturities of long-term debt . . . . . .     9,700      6,700
  Short-term debt. . . . . . . . . . . . . . . . .    15,500      7,900
  Accounts payable, trade and accrued liabilities.     7,755      6,684
  Accounts payable to associated companies . . . .     8,510      6,577
  Dividends declared . . . . . . . . . . . . . . .       229        285
  Customer deposits. . . . . . . . . . . . . . . .       696        361
  Accrued purchased power option call. . . . . . .     8,276          -
  Interest accrued . . . . . . . . . . . . . . . .     1,150      1,169
  Power supply option obligation . . . . . . . . .    15,419          -
  Other. . . . . . . . . . . . . . . . . . . . . .       874      8,475
                                                    ---------  ---------
    Total current liabilities. . . . . . . . . . .    68,344     39,791
                                                    ---------  ---------
DEFERRED CREDITS
  Accumulated deferred income taxes. . . . . . . .    25,644     25,201
  Unamortized investment tax credits . . . . . . .     3,695      3,978
  Pine Street Barge Canal site cleanup . . . . . .    11,554      8,815
  Other. . . . . . . . . . . . . . . . . . . . . .    20,901     21,131
                                                    ---------  ---------
    Total deferred credits . . . . . . . . . . . .    61,794     59,125
                                                    ---------  ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
  Liabilities of discontinued segment, net . . . .     3,317          -
                                                    ---------  ---------
    Total non-utility liabilities. . . . . . . . .     3,317          -
                                                    ---------  ---------

TOTAL CAPITALIZATION AND LIABILITIES . . . . . . .  $316,608   $301,194
                                                    =========  =========

</TABLE>


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


<TABLE>
<CAPTION>

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

                                    AUTHORIZED    2000       1999      2000    1999
                                   ------------ ----------  --------- ------  ------
(In thousands)
<S>                                 <C>         <C>        <C>        <C>     <C>
 CAPITAL STOCK
Common Stock, $3.33 1/3 par value.  10,000,000  5,582,552  5,425,571  18,608  $18,085
                                                                      ======  =======
</TABLE>



<TABLE>
<CAPTION>
                                                                 OUTSTANDING

            AUTHORIZED                      ISSUED         2000     1999     2000     1999
--------------------------------------  ---------------  --------  -------  -------  ------
            Shares                      (In thousands)
--------------------------------------
<S>                                     <C>              <C>       <C>      <C>      <C>     <C>
REDEEMABLE CUMULATIVE PREFERRED STOCK,
  $100 PAR VALUE
    4.75%, Class B, redeemable at
      $101 per share . . . . . . . . .           15,000    15,000    1,450    1,800     145  $   180
    7%, Class C, redeemable at
      $101 per share . . . . . . . . .           15,000    15,000    3,300    3,750     330      375
    9.375%, Class D, Series 1,
      redeemable at $101 per share . .           40,000    40,000    3,200    4,800     320      480
    8.625%, Class D, Series 3,
      redeemable at $100916 per share.           70,000    70,000        0   14,000       0    1,400
    7.32%, Class E, Series 1 . . . . .          200,000   120,000  120,000  120,000  12,000   12,000
                                                                                     ------  -------
TOTAL PREFERRED STOCK. . . . . . . . .                                      $        12,795  $ 14,435
                                                                              ===============  ========
</TABLE>







<TABLE>
<CAPTION>


                                                                    2000     1999
                                                                   -------  -------
(In thousands)
<S>                                                                <C>      <C>
LONG-TERM DEBT
FIRST MORTGAGE BONDS
  5.71% Series due 2000 . . . . . . . . . . . . . . . . . . . . .  $     -  $ 5,000
  6.21% Series due 2001 . . . . . . . . . . . . . . . . . . . . .    8,000    8,000
  6.29% Series due 2002 . . . . . . . . . . . . . . . . . . . . .    8,000    8,000
  6.41% Series due 2003 . . . . . . . . . . . . . . . . . . . . .    8,000    8,000
  10.0% Series due 2004 - Cash sinking fund, $1,700,000 annually.    6,800    8,500
  7.05% Series due 2006 . . . . . . . . . . . . . . . . . . . . .    4,000    4,000
  7.18% Series due 2006 . . . . . . . . . . . . . . . . . . . . .   10,000   10,000
  6.7% Series due 2018. . . . . . . . . . . . . . . . . . . . . .   15,000   15,000
  9.64% Series due 2020 . . . . . . . . . . . . . . . . . . . . .    9,000    9,000
  8.65% Series due 2022 - Cash sinking fund, commences 2012 . . .   13,000   13,000
                                                                   -------  -------
Total Long-term Debt Outstanding. . . . . . . . . . . . . . . . .   81,800   88,500
  Less Current Maturities (due within one year) . . . . . . . . .    9,700    6,700
                                                                   -------  -------
TOTAL LONG-TERM DEBT, NET . . . . . . . . . . . . . . . . . . . .  $72,100  $81,800
                                                                   =======  =======
</TABLE>

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


Notes  to  Consolidated  Financial  Statements

A.  SIGNIFICANT  ACCOUNTING  POLICIES

     1.  Organization  and  Basis  of  Presentation.  Green  Mountain  Power
Corporation (the Company) is an investor-owned electric services company located
in  Vermont  that serves approximately one-quarter of Vermont's population.  The
most  significant  portion  of  the  Company's  net income is generated from its
regulated  electric  utility  operation,  which purchases and generates electric
power and distributes it to approximately 86,000 retail and wholesale customers.
At  December  31, 2000, the Company's primary subsidiary investment was Mountain
Energy, Inc. ("MEI"), which had invested in energy generation, energy efficiency
and  wastewater  treatment  projects  across  the  United  States.  In 1999, the
Company  decided to sell or dispose of the assets of MEI, and report its results
as  income  (loss)  from  operations of a discontinued segment.  MEI changed its
name  to  Northern  Water Resources, Inc. ("NWR") in January 2001.  In 1998, the
Company  sold  the assets of its wholly owned subsidiary, Green Mountain Propane
Gas  Company ("GMPG").  The Company's remaining wholly-owned subsidiaries, which
are  not  regulated by the Vermont Public Service Board ("VPSB" or "the Board"),
are  Green  Mountain Resources, Inc. ("GMRI"), which sold its remaining interest
in  Green  Mountain  Energy Resources in 1999 and is currently inactive, and GMP
Real  Estate Corporation.  The results of these subsidiaries, excluding MEI, 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 these
subsidiaries  is  as  follows:

<TABLE>
<CAPTION>

                           For the years ended December 31,

                 2000    1999    1998
                ------  ------  ------
(In thousands)
<S>             <C>     <C>     <C>
Revenue. . . .  $1,034  $1,286  $2,876
Expense. . . .     495     184   2,857
                ------  ------  ------
Net Income . .  $  539  $1,102  $   19
                ======  ======  ======
</TABLE>




The  Company  carries  its  investments in various associated companies, Vermont
Yankee  Nuclear  Power  Corporation  ("Vermont  Yankee"), Vermont Electric Power
Company,  Inc.  ("VELCO"),  New  England Hydro-Transmission Corporation, and New
England  Hydro-Transmission  Electric  Company  using  the  equity  method  of
accounting.  The  Company's  share  of  the  net  earnings  or  losses  of these
companies  is  also  included  in  the  Other Income section of the Consolidated
Statements  of  Income.  See  Note  B  and  Note  L  for additional information.

     2.  Regulatory  Accounting.  The  Company's  utility  operations, including
accounting  records,  rates,  operations  and  certain  other  practices  of its
electric  utility  business,  are  subject  to  the  regulatory authority of the
Federal  Energy  Regulatory  Commission  (FERC)  and  the  VPSB.
          The  accompanying  consolidated  financial  statements  conform  to
generally  accepted  accounting  principles  applicable  to  rate-regulated
enterprises  in  accordance  with  Statement  of  Financial Accounting Standards
("SFAS")  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.  Conditions that
could  give  rise  to  the  discontinuance  of  SFAS  71  include (1) increasing
competition  that restricts the Company's ability to establish prices to recover
specific  costs,  and  (2)  a  change  in  the  manner in which rates are set by
regulators  from  cost-based  regulation  to another form of regulation.  In the
event  that  the Company no longer meets the criteria under SFAS 71, the Company
would  be  required to write off related regulatory assets and liabilities.  The
Company  continues  to  believe, based on current regulatory circumstances, that
the  use of regulatory accounting under SFAS 71 remains appropriate and that its
regulatory  assets are probable of recovery.  Regulatory entities that influence
the Company include the VPSB, the Vermont Department of Public Service ("DPS" or
the  "Department"),  and  FERC,  among other federal, state and local regulatory
agencies.
          3.  Impairment. The Company is required to evaluate long-lived assets,
including  regulatory  assets,  for  potential  impairment.  Assets  that are no
longer probable of recovery through future revenues would be revalued based upon
future  cash  flows.  Regulatory  assets are charged to expense in the period in
which  they are no longer probable of future recovery.  As of December 31, 2000,
based  upon  the  regulatory  environment  within  which  the  Company currently
operates, the Company does not believe that an impairment loss need be recorded.
Competitive  influences or regulatory developments may impact this status in the
future.
          4.  Utility  Plant.  The  cost  of  plant  additions  includes  all
construction-related  direct  labor  and  materials,  as  well  as  indirect
construction  costs,  including  the  cost  of  money ("Allowance for Funds Used
During  Construction"  or "AFUDC").  As part of the rate agreement with the DPS,
the  Company  discontinued  recording  AFUDC on construction work in progress in
January  2001.  The  costs  of  renewals  and improvements of property units are
capitalized.  The  costs  of  maintenance,  repairs  and  replacements  of minor
property  items  are  charged  to  maintenance  expense.  The  costs of units of
property  removed from service, net of removal costs and salvage, are charged to
accumulated  depreciation  over  the  estimated  service  life  of  the  units.

     5.  Depreciation.  The  Company  provides  for  depreciation  using  the
straight-line  method  based on the cost and estimated remaining service life of
the  depreciable  property outstanding at the beginning of the year and adjusted
for  salvage  value  and  cost  of  removal  of  the  property.
          The  annual  depreciation  provision  was approximately 3.5 percent of
total  depreciable  property  at  the  beginning  of  2000,  3.3  percent at the
beginning  of  1999  and  3.4  percent  at  the  beginning  of  1998.

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

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

     8.  Deferred  Charges.  In  a manner consistent with authorized or expected
ratemaking  treatment,  the  Company  defers  and  amortizes certain replacement
power,  maintenance  and  other costs associated with the Vermont Yankee Nuclear
Power  Corporation's  generation  plant.  In  addition,  the Company accrues and
amortizes  other  replacement power expenses to reflect more accurately its cost
of  service  to  better  match  revenues and expenses consistent with regulatory
treatment.  The  Company  also  defers  and  amortizes costs associated with its
investment  in  the  demand  side  management  program.
     Other  deferred charges totaled $15.5 million and $19.5 million at December
31,  2000  and  1999  respectively,  consisting of regulatory deferrals of storm
damages,  rights-of-way maintenance, other employee benefits, preliminary survey
and  investigation  charges,  transmission  interconnection  charges and various
other  projects  and  deferrals.

     9.  Earnings  Per  Share.  Earnings  per  share  are  based on the weighted
average number   of common and common stock equivalent shares outstanding during
each  year.  The  Company  established an stock incentive plan for all employees
during the year ended December 31, 2000, and granted 334,900 options exercisable
over  vesting  schedules  of  between  one  and  four  years.  Since the Company
experienced  a  net  loss in the year 2000, basic and diluted earnings per share
are  the  same.

     10.  Major  Customers.  The  Company  had  one  major retail customer, IBM,
metered  at  two  locations,  that accounted for 11.2 percent, 11.8 percent, and
14.7  percent  of  total  operating revenues, and 16.5 percent, 16.4 percent and
17.1  percent of the Company's retail operating revenues in 2000, 1999 and 1998,
respectively.  IBM's  percent  of  total  revenues  in  2000 decreased due to an
increase in total operating revenues as a result of sales for resale pursuant to
the Morgan Stanley Capital Group, Inc. ("MS") agreement.  See Note K for further
information  regarding  the  MS  agreement.

     11.  Fair  Value of Financial Instruments.   The present value of the first
mortgage  bonds  and preferred stock outstanding, if refinanced using prevailing
market  rates  of  interest,  would  decrease  from  the balances outstanding at
December  31,  2000  by  approximately  4.6  percent.  In  the  event  of such a
refinancing,  there  would  be  no  gain  or  loss,  because  under  established
regulatory  precedent,  any such difference would be reflected in rates and have
no  effect  upon  income.

     12. Deferred Credits.  At December 31, 2000, the Company had other deferred
credits  and  long-term liabilities of $32.4 million, consisting of reserves for
damage  claims and environmental liabilities, and accruals for employee benefits
compared  with  a  balance  of  $30.4  million  at  December  31,  1999.

     13.  Use  of  Estimates.  The  preparation  of  financial  statements  in
conformity  with  generally  accepted  accounting principles requires the use of
estimates  and assumptions that affect assets and liabilities, the disclosure of
contingent  assets  and  liabilities, and revenues and expenses.  Actual results
could  differ  from  those  estimates.

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

          15.  New  Accounting  Standards.   In  June  1998,  the  Financial
Accounting  Standards  Board  issued Statement of Financial Accounting Standards
No.  133,  Accounting for Derivative Instruments and Hedging Activities, amended
by  Statement  No.  137,  Accounting  for  Derivative  Instruments  and  Hedging
Activities  -  Deferral  of  the  Effective  Date  of FASB Statement No. 133 and
Statement 138, Accounting for Certain Derivatives and Certain Hedging Activities
(collectively  "SFAS  133").
          SFAS 133 establishes accounting and reporting standards requiring that
derivative  instruments  (including  certain  derivative instruments embedded in
other  contracts)  be  recorded  in  the  balance  sheet as either an asset or a
liability  and  measured at their 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.  Special accounting for qualifying hedges
allows  a  derivative's gains and losses to offset related results on the hedged
item  in  the  income  statement, and requires that a company formally document,
designate,  and  assess  the  effectiveness  of  transactions that receive hedge
accounting.   SFAS  133 is effective for the Company beginning the first quarter
of  2001  and must be applied to derivative instruments and embedded derivatives
that  were  issued,  acquired,  or substantively modified on or after January 1,
1998  or  January  1,  1999  (as  elected  by  the  Company).
          We  have  not  yet  quantified all effects of adopting SFAS 133 on our
financial  statements.  However,  a  discussion  of  the  Company's  material
derivative obligations follows and includes estimates of the fair values of each
derivative.  The  Company  has  sought  an  accounting  order  from  the VPSB to
determine  regulatory  treatment for recording derivatives at fair market value.
We  believe  it  is  probable  that  the  VPSB will order that the Company defer
recognition  of  any  earnings  or other comprehensive income effect relating to
future  periods  caused by application of SFAS 133.  We expect the VPSB to issue
the  accounting  order  prior  to  reporting  our  first  quarter  results,  and
consequently  do  not  anticipate  SFAS  133  to  cause  earnings  volatility.
          If  the  VPSB  issues such an order, and if a derivative instrument is
terminated  early  because  it  is  probable  that  a  transaction or forecasted
transaction will not occur, any gain or loss will be recognized immediately.  If
such derivative is terminated for other economic reasons, any gain or loss as of
the termination date is deferred and recorded when the associated transaction or
forecasted  transaction  affects earnings. For derivatives held to maturity, the
income  statement  impact  of derivatives would be recognized in the period that
the  derivative  is  sold  or  matures.
          If  the  VPSB does not issue an order or issues an order that does not
require deferral of the earnings impacts resulting from application of SFAS 133,
management  estimates  that  adoption  would result in earnings/loss recognition
equivalent  to  the  fair  values of the respective assets/liabilities disclosed
below,  as  adjusted  by  future  changes  in  estimates.
          The  Company has a contract with MS used to hedge against increases in
fossil  fuel prices. MS purchases the majority of Company power supply resources
at index (fossil fuel resources) or specified (i.e. contracted resources) prices
and then sells to us at a fixed rate to serve pre-established load requirements.
This  contract  allows  management  to  fix the cost of much of its power supply
requirements,  subject  to  power  resource availability and other risks. The MS
contract  is  a  derivative under SFAS 133 and is effective through December 31,
2003.  Management's current estimate of the fair value of the future net benefit
(cost)  of  this  arrangement  is  between  $7.2  million  and  ($14.0) million.
          We  also  sometimes use future contracts to hedge forecasted wholesale
sales of electric power, including material sales commitments as discussed under
Note  K.  We currently have an arrangement with Hydro-Quebec that grants them an
option  to call power at prices below current and estimated future market rates.
This  arrangement  is  a derivative and is effective through 2016.  Management's
current  estimate  of the fair value of the future net cost for this arrangement
is  between  $24.5  and  $29.5  million.

B.  INVESTMENTS  IN  ASSOCIATED  COMPANIES

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

<TABLE>
<CAPTION>

                                        PERCENT     INVESTMENT IN EQUITY
                                     OWNERSHIP AT      AT DECEMBER 31,

                                  DECEMBER 31,2000     2000     1999
          -----------------------------------------  --------  -------
(IN THOUSANDS)
<S>                                        <C>       <C>      <C>
VELCO-common. . . . . . . . . . . . . . .    29.50%  $ 1,916  $1,839
VELCO-preferred . . . . . . . . . . . . .    30.00%      540     690
                                                     -------  ------
Total VELCO . . . . . . . . . . . . . .          .    2,456     2,529

Vermont Yankee- Common. . . . . . . . . .    17.88%    9,713   9,641
New England Hydro Transmission-Common . .     3.18%      827     911
New England Hydro Transmission Electric-
    Common. . . . . . . . . . . . . . . .     3.18%    1,377   1,464
                                                     -------  ------
          Total investment in associated companies.  $14,373 $14,545
                                                    ========  =======
</TABLE>

     Undistributed earnings in associated companies totaled $908,000 at December
31,  2000.

     VELCO.  VELCO  is  a  corporation  engaged  in the transmission of electric
power  within  the  State  of  Vermont.  VELCO  has  entered  into  transmission
agreements  with  the  State  of Vermont and other electric utilities, and under
these  agreements, VELCO bills all costs, including interest on debt and a fixed
return  on  equity,  to  the State and others using VELCO's transmission system.
The  Company's  purchases of transmission services from VELCO were $9.7 million,
$7.9  million, and $7.1 million for the years 2000, 1999 and 1998, respectively.
Pursuant  to VELCO's Amended Articles of Association, the Company is entitled to
approximately 30 percent of the dividends distributed by VELCO.  The Company has
recorded  its  equity in earnings on this basis and also is obligated to provide
its  proportionate  share  of  the  equity capital requirements of VELCO through
continuing  purchases  of  its  common  stock,  if  necessary.

<TABLE>
<CAPTION>

Summarized  financial  information  for  VELCO  is  as  follows:
                                   AT AND FOR THE YEARS ENDED
                                         DECEMBER  31,

                                  2000     1999     1998
                                 -------  -------  -------
                                      (In thousands)
<S>                              <C>      <C>      <C>
Company's equity in net income.  $   395  $   357  $   338
                                 =======  =======  =======
Total assets. . . . . . . . . .  $82,123  $67,294  $67,658
Less:
Liabilities and long-term debt.   73,874   58,731   58,690
                                 -------  -------  -------
Net assets. . . . . . . . . . .  $ 8,249  $ 8,563  $ 8,968
                                 =======  =======  =======

Company's equity in net assets.  $ 2,456  $ 2,529  $ 2,657
                                 =======  =======  =======
</TABLE>



Vermont  Yankee.  The  Company  is responsible for approximately 17.9 percent of
Vermont  Yankee's  expenses of operations, including costs of equity capital and
estimated  costs  of  decommissioning, and is entitled to a similar share of the
power  output  of  the nuclear plant, which has a net capacity of 531 megawatts.
Vermont Yankee's current estimate of decommissioning costs is approximately $430
million,  using  the  1993  FERC approved escalation rate of 5.4%, of which $247
million has been funded.  At December 31, 2000, the Company's portion of the net
unfunded  liability  was $33 million, which it expects will be recovered through
rates  over  Vermont Yankee's remaining operating life.  As a sponsor of Vermont
Yankee,  the  Company  also  is  obligated  to  provide  20  percent  of capital
requirements not obtained by outside sources.  During 2000, the Company incurred
$27.8  million  in  Vermont  Yankee annual capacity charges, which included $2.4
million for interest charges.  The Company's share of Vermont Yankee's long-term
debt  at  December  31,  2000  was  $17.1  million.
          On  October  15,  1999,  the  owners  of  Vermont Yankee Nuclear Power
Corporation  accepted  a  bid from AmerGen Energy Company for the Vermont Yankee
generating  plant, intending to complete the sale before December 2000.  AmerGen
and  the  DPS  then  negotiated  a  revised  offer  in November 2000,  which was
subsequently  dismissed  as insufficient by the VPSB in February 2001.   Entergy
Nuclear Inc. has also made an offer, and two other companies have indicated they
would  participate  in  an  auction, if held.  The plant is likely to be sold at
auction,  the  terms  and  conditions  of  which  are  unknown  at  this  time.
               The  Price-Anderson  Act currently limits public liability from a
single  incident  at  a nuclear power plant to $9.5 billion.  Any damages beyond
$9.5  billion  are  indemnified  under  the  Price-Anderson  Act, but subject to
congressional  approval.  The  first  $200  million of liability coverage is the
maximum  provided  by  private  insurance.  The  Secondary  Financial Protection
Program  is  a  retrospective insurance plan providing additional coverage up to
$9.3  billion  per  incident by assessing each of the 106 reactor units that are
currently  subject to the Program in the United States a total of $88.1 million,
limited  to a maximum assessment of $10 million per incident per nuclear unit in
any  one  year.  The maximum assessment is adjusted at least every five years to
reflect  inflationary  changes.
          The  above insurance covers all workers employed at nuclear facilities
for  bodily  injury  claims.  Vermont  Yankee retains a potential obligation for
retrospective  adjustments  due to past operations of several smaller facilities
that  did  not  join the above insurance program.  These exposures will cease to
exist  no  later than December 31, 2007.  Vermont Yankee's maximum retrospective
obligation  remains  at  $3.1  million.     Insurance  has  been  purchased from
Nuclear  Electric  Insurance  Limited  ("NEIL")  to  cover the costs of property
damage,  decontamination  or  premature decommissioning resulting from a nuclear
incident.  All  companies  insured  with  NEIL  are  subject  to  retroactive
assessments  if  losses  exceed  the  accumulated  funds available.  The maximum
potential  assessment against Vermont Yankee with respect to NEIL losses arising
during  the current policy year is $8.1 million.  Vermont Yankee's liability for
the  retrospective premium adjustment for any policy year ceases six years after
the  end  of  that  policy  year  unless  prior  demand  has  been  made.


<TABLE>
<CAPTION>

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

                                            2000      1999      1998
                                          --------  --------  --------
(In thousands)
<S>                                       <C>       <C>       <C>
Earnings:
  Operating revenues . . . . . . . . . .  $178,294  $208,812  $195,249
  Net income applicable to common stock.     6,583     6,471     7,125
  Company's equity in net income . . . .  $  1,177  $  1,165  $  1,267
                                          ========  ========  ========
Total assets . . . . . . . . . . . . . .  $706,984  $685,292  $635,874
Less:
  Liabilities and long-term debt . . . .   652,663   631,365   581,231
                                          --------  --------  --------
Net Assets . . . . . . . . . . . . . . .  $ 54,321  $ 53,927  $ 54,643
                                          ========  ========  ========
Company's equity in net assets . . . . .  $  9,713  $  9,641  $  9,759
                                          ========  ========  ========
</TABLE>
C.  COMMON  STOCK  EQUITY

          The  Company maintains a Dividend Reinvestment and Stock Purchase Plan
("DRIP")  under  which 456,554 shares were reserved and unissued at December 31,
2000.  The  Company also funds an Employee Savings and Investment Plan ("ESIP").
At  December 31, 2000, there were 174,263 shares reserved and unissued under the
ESIP.
     During  2000, the Company's Board of Directors, with subsequent approval of
the  Company's  common shareholders, established a  stock incentive plan.  Under
this  plan,  options  for  up  to 500,000 shares may be granted to any employee,
officer,  consultant,  contractor or Director providing services to the Company.
Outstanding  options  become exercisable at between one and four years after the
grant  date  and  remain  exercisable  until  10  years  from  the  grant  date.
          As  permitted  by Statement of Financial Accounting Standards No. 123,
"Accounting  for  Stock-Based Compensation,"("SFAS 123") the Company has elected
to  follow Accounting Principles Board Opinion No. 25 ("APB 25") "Accounting for
Stock  Issued  to  Employees", and related interpretations in accounting for its
employee  stock  options.  Under  APB  25, because the exercise price equals the
market  price  of  the  underlying  stock  on the date of grant, no compensation
expense  is  recorded.
          Disclosure  of proforma information regarding  net income and earnings
per  share  is  required  by SFAS 123.  The information presented below has been
determined  as if the Company accounted for its employee stock options under the
fair  value method of that statement.  The fair values of the options granted in
2000  are  $2.03  per  share.  They  were  estimated at the grant date using the
Black-Scholes  option-pricing  model  with  the  following  weighted  average
assumptions:
<TABLE>
<CAPTION>

Assumptions

                            2000
                           ------
<S>                        <C>
Risk-free interest rate .   6.05%
Expected life in years. .      7
Expected stock volatility  30.58%
Dividend yield. . . . . .   4.50%
</TABLE>
Proforma net earnings loss per share and a summary of options outstanding are as
follows:
<TABLE>
<CAPTION>

Proforma  net  income  (loss)

                             2000
                            -------
<S>                         <C>
Net income (loss)per share
  As reported. . . . . . .  $(1.25)
  Pro-forma. . . . . . . .  $(1.25)
Diluted earnings per share
  As reported. . . . . . .  $(1.25)
  Pro-forma. . . . . . . .  $(1.25)
</TABLE>
<TABLE>
<CAPTION>


                         Weighted
                         Average
                         Options   Price
                         --------  ------
<S>                      <C>       <C>
Outstanding at 12/31/99         -  $    -
Granted . . . . . . . .   334,900    7.90
Exercised . . . . . . .         -       -
Forfeited . . . . . . .     3,400    7.90
Outstanding at 12/31/00   331,500  $ 7.90
                         ========  ======
</TABLE>
No  options  granted  in 2000 became exercisable in 2000.  The pro-forma amounts
may  not  be representative of future disclosures since the estimated fair value
of  stock options is amortized to expense over the vesting period and additional
options  may  be  granted in future years.  For 2000, the number of total shares
after  giving  effect to anti-dilutive common stock equivalents does not change.
     The  following  summarizes  the  plan's  stock  options  outstanding:
<TABLE>
<CAPTION>


      Weighted
       average   Outstanding   Remaining
        Plan      exercise      options    Contractual
        year        price     at 12/31/00     Life
      ---------  -----------  -----------  -----------
<S>   <C>        <C>          <C>          <C>
2000  $    7.90      331,500    9.6 years
</TABLE>






During  2000,  the  Compensation Program for Officers and Certain Key Management
personnel,  that  authorized  payment of cash, restricted and unrestricted stock
grants based on corporate performance was replaced with the stock incentive plan
discussed  above.   Approximately 2000 restricted shares, issued during 1996 and
1997,  remained  unvested  under  this  program.












<TABLE>
<CAPTION>

 Changes  in  common  stock  equity  for  the  years  ended  December  31,  1998,  1999  and  2000  are  as  follows:

                                           COMMON STOCK         PAID-IN       RETAINED       TREASURY STOCK     STOCK
                                                                                            ----------------
                                    SHARES           AMOUNT     CAPITAL        EARNINGS      SHARES   AMOUNT    EQUITY
                            ----------------------  ---------  ----------  ----------------  ------  --------  ---------
                            (Dollars in thousands)
<S>                         <C>                     <C>        <C>         <C>               <C>     <C>       <C>
BALANCE, DECEMBER 31, 1997              5,195,432   $ 17,318   $  70,720   $        26,717   15,856  $  (378)  $114,377
                            ----------------------  ---------  ----------  ----------------  ------  --------  ---------
Common Stock Issuance:
  DRIP . . . . . . . . . .                 88,004        293         928                 -        -        -      1,221
  ESIP . . . . . . . . . .                 36,391        121         427                 -        -        -        548
  Compensation Program:. .                      -
     Restricted Shares . .                 (6,531)       (21)       (161)                -        -        -       (182)
Net Loss . . . . . . . . .                      -          -           -            (2,877)       -        -     (2,877)
Cash Dividends . . . . . .                      -
  Common Stock . . . . . .                      -          -           -            (5,036)       -        -     (5,036)
  Preferred Stock:
  $4.75 per share. . . . .                      -          -           -               (12)       -        -        (12)
  $7.00 per share. . . . .                      -          -           -               (32)       -        -        (32)
  $9.375 per share . . . .                      -          -           -               (72)       -        -        (72)
  $8.625 per share . . . .                      -          -           -              (302)       -        -       (302)
  $7.32 per share. . . . .                      -          -           -              (878)       -        -       (878)
                            ----------------------  ---------  ----------  ----------------  ------  --------  ---------
BALANCE, DECEMBER 31, 1998              5,313,296   $ 17,711   $  71,914   $        17,508   15,856  $  (378)  $106,755
                            ----------------------  ---------  ----------  ----------------  ------  --------  ---------
Common Stock Issuance:
  DRIP . . . . . . . . . .                 67,525        225         418                 -        -        -        643
  ESIP . . . . . . . . . .                 48,277        161         345                 -        -        -        506
  Compensation Program:
     Restricted Shares . .                 (3,527)       (12)        (83)                -        -        -        (95)
Net Loss . . . . . . . . .                      -          -           -            (3,063)       -        -     (3,063)
Cash Dividends
  Common Stock . . . . . .                      -          -           -            (2,946)       -        -     (2,946)
  Preferred Stock:
  $4.75 per share. . . . .                      -          -           -               (10)       -        -        (10)
  $7.00 per share. . . . .                      -          -           -               (29)       -        -        (29)
  $9.375 per share . . . .                      -          -           -               (57)       -        -        (57)
  $8.625 per share . . . .                      -          -           -              (181)       -        -       (181)
  $7.32 per share. . . . .                      -          -           -              (878)       -        -       (878)
                            ----------------------  ---------  ----------  ----------------  ------  --------  ---------
BALANCE, DECEMBER 31, 1999              5,425,571   $ 18,085   $  72,594   $        10,344   15,856  $  (378)  $100,645
                            ----------------------  ---------  ----------  ----------------  ------  --------  ---------
Common Stock Issuance:
  DRIP . . . . . . . . . .                 73,859        246         363                 -        -        -        609
  ESIP . . . . . . . . . .                 83,931        280         401                 -        -        -        681
  Compensation Program:
     Restricted Shares . .                   (809)        (3)        (37)                -        -        -        (40)
Net Loss . . . . . . . . .                      -          -           -            (5,840)       -        -     (5,840)
Cash Dividends
  Common Stock . . . . . .                      -          -           -            (2,997)       -        -     (2,997)
  Preferred Stock:
  $4.75 per share. . . . .                      -          -           -                (8)       -        -         (8)
  $7.00 per share. . . . .                      -          -           -               (26)       -        -        (26)
  $9.375 per share . . . .                      -          -           -               (42)       -        -        (42)
  $8.625 per share . . . .                      -          -           -               (60)       -        -        (60)
  $7.32 per share. . . . .                      -          -           -              (878)       -        -       (878)
                            ----------------------  ---------  ----------  ----------------  ------  --------  ---------
BALANCE, DECEMBER 31, 2000              5,582,552   $ 18,608   $  73,321   $           493   15,856  $  (378)  $ 92,044
                            ======================  =========  ==========  ================  ======  ========  =========
</TABLE>
Dividend Restrictions.  Certain restrictions on the payment of cash dividends on
common  stock  are  contained  in the Company's indentures relating to long-term
debt and in the Restated Articles of Association.  Under the most restrictive of
such  provisions,  approximately  $0.5 million of retained earnings were free of
restrictions  at  December  31,  2000.
     The  properties  of  the  Company  include  several  hydroelectric projects
licensed under the Federal Power Act, with license expiration dates ranging from
2001  to  2025.  At  December  31,  2000,  $161,000 of retained deficit had been
appropriated as excess earnings on hydroelectric projects as required by Section
10(d)  of  the  Federal  Power  Act.

D.  PREFERRED  STOCK

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

          Certain  classes  of preferred stock are subject to annual purchase or
sinking  fund  requirements.  The  sinking fund requirements are mandatory.  The
purchase  fund  requirements  are mandatory, but holders may elect not to accept
the  purchase  offer.  The  redemption  or  purchase  price  to  satisfy  these
requirements  may  not exceed $100 per share plus accrued dividends.  All shares
redeemed or purchased in connection with these requirements must be canceled and
may  not be reissued.  The annual purchase and sinking fund requirements for the
year  2001  for  certain  classes  of  preferred  stock  are  as  follows:

<TABLE>
<CAPTION>
                              Purchase and Sinking Fund
                                        Shares  to
        Class                Due dates   Retire
<C>     <S>                  <C>         <C>

4.750%    Class B . . . . .  December 1     300
7.000%    Class C . . . . .  December 1     450
9.375%    Class D, Series 1  December 1   1,600
</TABLE>
Under  the  Restated  Articles  of Association relating to Redeemable Cumulative
Preferred  Stock,  the  annual  aggregate  amount  of  purchase and sinking fund
requirements  for  the  next  five  years  are  $235,000 each for 2001 and 2002,
$75,000  each  for  2003  and  2004,  $70,000  for 2005 and $105,000 thereafter.
          Certain classes of preferred stock are redeemable at the option of the
Company  or,  in the case of voluntary liquidation, at various prices on various
dates.  The prices include the par value of the issue plus any accrued dividends
and  a  redemption premium.  The redemption premium for Class B, C and D, Series
1,  is  $1.00  per  share.

E.  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 7.6
percent  and  7.5  percent  at  December  31,  2000 and 1999, respectively.  The
annual  sinking  fund  requirements  (excluding amounts that may be satisfied by
property  additions)  and long-term debt maturities for the next five years are:


<TABLE>
<CAPTION>

          Sinking
           Fund        Maturities   Total
      ---------------  -----------  ------
      (In thousands)
<S>   <C>              <C>          <C>

2001  $         1,700  $     8,000  $9,700
2002            1,700        8,000   9,700
2003            1,700        8,000   9,700
2004            1,700                1,700
2005            1,700                1,700
</TABLE>

F.  SHORT-TERM  DEBT

          The  Company  has  a  revolving  credit agreement with Fleet Financial
Services  and  Citizens  Bank  of  Massachusetts  (the "Fleet agreement") in the
amount  of  $15.0  million,  with  borrowings  outstanding  of $500,000 and $7.9
million  at  December  31,  2000,  and  1999  respectively.  The  364-day  Fleet
agreement  expires  June 2001.  The weighted average interest rate on short-term
borrowings  outstanding  at  December  31,  2000  and  December 31, 1999 was 9.5
percent and 9.0 percent, respectively.  There was no non-utility short-term debt
outstanding  at  December  31,  2000.
          The  Fleet  agreement  requires  the Company to certify on a quarterly
basis  that  it  has  not suffered a "material adverse change".  Similarly, as a
condition  to  further  borrowings,  the  Company must certify that no event has
occurred or failed to occur that has had or would reasonably be expected to have
a  materially  adverse  effect  on  the  Company  since  the  date  of the  last
borrowing  under  this  agreement.   The  Fleet  agreement allows the Company to
continue  to  borrow  until  such  time  that:
*     a  "material  adverse  effect"  has  occurred;  or
*     the Company no longer complies with all other provisions of the agreement,
in  which  case  further  borrowing  will  not  be  permitted;  or
*     there  has  been  a "material adverse change", in which case the banks may
declare  the  Company  in  default.
     Terms  also  call  in part for a second priority mortgage lien and security
interest  in  the  collateral  pledged  under the first mortgage bond indenture.
     On  September  20,  2000,  we  established a $15.0 million revolving credit
agreement  ("KeyBank  agreement") with KeyBank National Association ("KeyBank").
The  KeyBank  agreement is for a period of 364 days and will expire on September
19,  2001.  Pursuant  to  a  one  year power supply option agreement between the
Company  and  Energy East Corporation ("EE"), EE made a payment of $15.0 million
to  the  Company.  In exchange, the Company gave EE an option to purchase energy
from  certain  wholly owned production facilities, for a period not to exceed 15
years,  if  the  funds are not returned to EE upon request after September 2001.
The  Company was required to invest the funds provided by EE in a certificate of
deposit  at  KeyBank  pledged  by  the  Company  to  secure  the  repayment  of
indebtedness  issued  under  the Keybank agreement.  At December 31, 2000, there
was  $15.0  million  outstanding  on  the  KeyBank  Agreement.
     The Company anticipates that it will secure financing that replaces some or
all  of  its expiring facilities during 2001. The VPSB Order of January 23, 2001
(the  "Settlement  Order")  will  likely  permit  restoration  of  the Company's
investment  grade  debt  ratings,  allowing arrangement of such financing as the
Company needs during 2001.  On March 5, 2001, Moody's Investors Service upgraded
the  Company's  first  mortgage  bond  rating to Baa2 from Ba1, and upgraded the
Company's  preferred stock rating to baa3 from ba3.  The rating action reflected
Moody's  earnings  and  cash  flow  expectations  for  the Company following the
Settlement  Order.

G.  INCOME  TAXES

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

          The regulatory tax assets and liabilities represent taxes that will be
collected  from or returned to customers through rates in future periods.  As of
December  31,  2000  and  1999,  the  net  regulatory assets were $1,908,000 and
$1,805,000,  respectively,  and  included  in  other  deferred  charges  on  the
Company's  consolidated  balance  sheets.
          The  temporary  differences  which  gave  rise to the net deferred tax
liability  at  December  31,  2000  and  December  31,  1999,  were  as follows:
<TABLE>
<CAPTION>

                   AT  DECEMBER  31,

                                        2000     1999
                                       -------  -------
(In thousands)
<S>                                    <C>      <C>
DEFERRED TAX ASSETS
Contributions in aid of construction.  $10,018  $ 9,056
Deferred compensation and
     postretirement benefits. . . . .    4,122    3,372
Self insurance and other reserves . .        -    3,664
Other . . . . . . . . . . . . . . . .    1,958    1,183
                                       -------  -------
                                       $16,098  $17,275
                                       -------  -------

DEFERRED TAX LIABILITIES
Property related. . . . . . . . . . .  $38,648  $37,921
Demand side management. . . . . . . .    1,810    2,328
Deferred purchased power costs. . . .       84    2,202
Pine Street reserve . . . . . . . . .      571       25
Other . . . . . . . . . . . . . . . .      629        -
                                       -------  -------
                                       $41,742  $42,476
                                       -------  -------
  Net accumulated deferred income
    tax liability . . . . . . . . . .  $25,644  $25,201
                                       =======  =======
</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  period:
<TABLE>
<CAPTION>

                       YEARS  ENDED  DECEMBER  31,

                                       2000    1999    1998
                                       -----  ------  ------
(In thousands)
<S>                                    <C>    <C>     <C>
Net change in deferred income tax . .  $ 443  $1,812  $(112)
  liability
Change in income tax related
  regulatory assets and liabilities .    184     176    510
Change in alternative minimum
  tax credit. . . . . . . . . . . . .      -       -    (70)
                                       -----  ------  ------
Deferred income tax expense (benefit)  $ 627  $1,988  $ 328
                                       =====  ======  ======
</TABLE>




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

                  YEARS  ENDED  DECEMBER  31,

                                  2000     1999      1998
                                --------  -------  --------
(In thousands)
<S>                             <C>       <C>      <C>
Current federal income taxes .  $  (786)  $ (339)  $(1,047)
Current state income taxes . .     (249)    (125)     (366)
                                --------  -------  --------
Total current income taxes . .   (1,035)    (464)   (1,413)
Deferred federal income taxes.      461    1,479       219
Deferred state income taxes. .      166      509       109
                                --------  -------  --------
Total deferred income taxes. .      627    1,988       328
Investment tax credits-net . .     (283)    (282)     (282)
                                --------  -------  --------
Income tax provision (benefit)  $  (691)  $1,242   $(1,367)
                                ========  =======  ========
</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,

                                                 2000      1999      1998
                                               --------  --------  --------
(In thousands)
<S>                                            <C>       <C>       <C>
Income (loss) before income taxes and
  preferred dividends . . . . . . . . . . . .  $(6,531)  $(1,821)  $(4,244)
Federal statutory rate. . . . . . . . . . . .     34.0%     34.0%     34.0%
Computed "expected" federal income
  taxes . . . . . . . . . . . . . . . . . . .   (2,221)     (619)   (1,443)
Increase (decrease) in taxes resulting from:
Tax versus book depreciation. . . . . . . . .       83        92       153
Dividends received and paid credit. . . . . .     (435)     (485)     (480)
AFUDC-equity funds. . . . . . . . . . . . . .      (33)       (5)      (36)
Amortization of ITC . . . . . . . . . . . . .     (282)     (282)     (282)
State tax (benefit) . . . . . . . . . . . . .      (83)      383      (256)
Excess deferred taxes . . . . . . . . . . . .      (60)      (60)      (60)
Tax attributable to subsidiaries. . . . . . .    2,213     2,271       845
Other . . . . . . . . . . . . . . . . . . . .      127       (53)      192
                                               --------  --------  --------
Total federal and state income tax (benefit).  $  (691)  $ 1,242   $(1,367)
                                               ========  ========  ========
Effective combined federal and state
  income tax rate . . . . . . . . . . . . . .     10.6%   (68.2%)     32.2%
</TABLE>
Non-Utility.  The  Company's  non-utility  subsidiaries,  excluding  MEI,  had
accumulated  deferred  income  taxes  of  approximately  $2,000 on their balance
sheets  at  December  31, 2000, attributable to depreciation timing differences.
          The  components  of the provision for the income tax expense (benefit)
for  the  non-utility  operations  are:

<TABLE>
<CAPTION>


                                            YEARS ENDED DECEMBER 31,
                                        2000             1999    1998
                              -------------------------  -----  ------
<S>                           <C>                        <C>    <C>
    (In thousands)
State income taxes . . . . .  $                       7  $  99  $(281)
Federal income taxes . . . .                         21    310   (202)
                              -------------------------  -----  ------
Income tax expense (benefit)  $                      28  $ 409  $(483)
                              =========================  =====  ======
</TABLE>

     The  effective  combined  federal  and  state  income  tax  rates  for  the
continuing  non-utility  operations  were  34.0  percent, 34.0 percent, and 32.6
percent,  for  the  years  ended December 31, 2000, 1999 and 1998, respectively.
See  Note  L  for  income tax information on the discontinued operations of MEI.

H.  PENSION  AND  RETIREMENT  PLANS.

     The  Company  has a defined benefit pension plan covering substantially all
of  its employees.  The retirement benefits are based on the employees' level of
compensation and length of service.  The Company's policy is to fund all accrued
pension  costs.  The Company records annual expense and accounts for its pension
plan  in  accordance  with  Statement  of Financial Accounting Standards No. 87,
Employers'  Accounting  for  Pensions.  The Company provides certain health care
benefits  for retired employees and their dependents.  Employees become eligible
for  these  benefits  if  they reach normal retirement age while working for the
Company.  The Company accrues the cost of these benefits during the service life
of  covered  employees.  The  pension  plan  assets  consist  primarily  of cash
equivalent  funds,  fixed  income  securities  and  equity  securities.
          Accrued  postretirement health care expenses are recovered in rates to
the  extent  those expenses are funded.  In order to maximize the tax-deductible
contributions  that  are  allowed under IRS regulations, the Company amended its
pension  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,  2000  and  1999.

<TABLE>
<CAPTION>

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

                                                      2000      1999       2000      1999
                                                    --------  ---------  --------  --------
(In thousands)
Change in projected benefit obligation:
<S>                                                 <C>       <C>        <C>       <C>
Projected benefit obligation as of prior year end.  $22,444   $ 30,860   $11,955   $12,552
Service cost . . . . . . . . . . . . . . . . . . .      655        620       216       240
Interest cost. . . . . . . . . . . . . . . . . . .    1,658      1,780     1,049       855
Special termination benefit. . . . . . . . . . . .        -      5,385         -     1,446
Change in actuarial assumptions. . . . . . . . . .        -          -     2,328    (1,372)
Settlements. . . . . . . . . . . . . . . . . . . .        -     (9,527)        -         -
Actuarial (gain) loss. . . . . . . . . . . . . . .      513     (2,080)       73       (70)
Benefits paid. . . . . . . . . . . . . . . . . . .   (1,938)    (4,312)     (674)     (864)
Curtailment. . . . . . . . . . . . . . . . . . . .        -       (282)        -      (832)
                                                    --------  ---------  --------  --------
Projected benefit obligation as of year end. . . .  $23,332   $ 22,444   $14,947   $11,955
                                                    ========  =========  ========  ========

Change in plan assets:
Fair value of plan assets as of prior year end . .  $31,477   $ 38,030   $11,062   $ 9,735
Contribution . . . . . . . . . . . . . . . . . . .        -          -         -         -
Actual return on plan assets . . . . . . . . . . .   (1,779)     7,286      (118)    1,327
Benefits paid. . . . . . . . . . . . . . . . . . .   (1,938)   (13,839)        -         -
                                                    --------  ---------  --------  --------
Fair value of plan assets as of year end . . . . .  $27,760   $ 31,477   $10,944   $11,062
                                                    ========  =========  ========  ========

Funded status as of year end . . . . . . . . . . .  $ 4,428   $  9,032   $(4,003)  $  (893)
Unrecognized transition obligation (asset) . . . .     (406)      (571)    3,936     4,264
Unrecognized prior service cost. . . . . . . . . .      766        887      (577)     (635)
Unrecognized net actuarial gain. . . . . . . . . .   (6,848)   (12,193)     (130)   (3,589)
                                                    --------  ---------  --------  --------
Accrued benefits at year end . . . . . . . . . . .  $(2,060)  $ (2,845)  $  (774)  $  (853)
                                                    ========  =========  ========  ========
</TABLE>
 The  Company  also  has  a  supplemental  pension  plan  for certain employees.
Pension  costs  for  the  years  ended  December  31,  2000, 1999, and 1998 were
$346,000,  $556,000,  and $397,000, 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

                                                  2000      1999      1998     2000     1999    1998
                                                --------  --------  --------  -------  ------  ------
(In thousands)
<S>                                             <C>       <C>       <C>       <C>      <C>     <C>
Service cost . . . . . . . . . . . . . . . . .  $   655   $   620   $   787   $  216   $ 240   $ 282
Interest cost. . . . . . . . . . . . . . . . .    1,658     1,780     2,043    1,049     855     799
Expected return on plan assets . . . . . . . .   (2,580)   (2,721)   (3,081)    (940)   (834)   (671)
Amortization of transition asset . . . . . . .     (164)     (196)     (228)       -       -       -
Amortization of net gain from earlier periods.        -         -         -        -       -       -
Amortization of prior service cost . . . . . .      121       128       134      (58)    (60)    (61)
Amortization of the transition obligation. . .        -         -         -      328     340     351
Recognized net actuarial gain. . . . . . . . .     (474)     (196)     (195)       -     (19)      -
Special termination benefit. . . . . . . . . .        -     3,122     2,026        -     888      27
Regulatory deferral. . . . . . . . . . . . . .        -    (3,122)   (2,026)       -    (888)    (27)
                                                --------  --------  --------  -------  ------  ------
            Net periodic benefit cost. . . . .  $  (784)  $  (585)  $  (540)  $  595   $ 522   $ 700
                                                ========  ========  ========  =======  ======  ======
</TABLE>
     Assumptions  used to determine postretirement benefit costs and the related
benefit  obligation  were:

<TABLE>
<CAPTION>

                                             For the years ended December 31,
                                          Pension benefits   Other Post-retirement Benefits
                                              ------------------------------

                                              2000   1999   2000   1999
                                              -----  -----  -----  -----
<S>                                           <C>    <C>    <C>    <C>
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . .  7.50%  6.75%  7.50%  7.50%
Expected return on plan assets . . . . . . .  9.00%  9.00%  8.50%  8.50%
Rate of compensation increase. . . . . . . .  4.50%  4.00%     -      -
Medical inflation. . . . . . . . . . . . . .     -      -   6.00%  5.30%
</TABLE>

     For  measurement  purposes,  a 6 percent annual rate of increase in the per
capita  cost  of  covered medical benefits was assumed for 2000 and later years.
The  health  care  cost  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, 2000 by $1.9 million and
the  total  of  the  service  and  interest  cost  components  of  net  periodic
postretirement  cost  for  the  year  ended  December  31,  2000  by  $200,000.
Decreasing  the  trend  rate  by one percentage point for all future years would
decrease  the accumulated postretirement benefit obligation at December 31, 2000
by  $1.5  million,  and the total of the service and interest cost components of
net  periodic  postretirement  cost  for  2000  by  $157,000.
     In 1999, the Company deferred special termination pension benefit
costs  of  $3,122,000  due  to  an  early  retirement program and other employee
separation  activities.  Curtailment  and  settlement  gains of $2.3 million are
included  in  the  special  termination  pension  benefit  cost.     The special
termination  benefit  recorded in 1998 resulted from the early retirement option
offered  to  employees  in  1998.  Also  in  1999,  the Company deferred special
termination  postretirement benefit costs of $888,000 due to an early retirement
program.  Management  believes  that  the  amounts  deferred  are  probable  of
recovery.

I.     COMMITMENTS  AND  CONTINGENCIES

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

   2.  ENVIRONMENTAL MATTERS.  The electric industry typically uses or generates
a  range  of potentially hazardous products in its operations.  The Company must
meet  various  land,  water,  air  and aesthetic requirements as administered by
local,  state  and  federal  regulatory  agencies.  We  believe  that  we are in
substantial  compliance  with  those  requirements,  and  that  there  are  no
outstanding  material complaints about our compliance with present environmental
protection regulations, except for developments related to the Pine Street Barge
Canal  site.  The  Company  maintains an environmental compliance and monitoring
program  that  includes  employee  training,  regular  inspection  of  Company
facilities,  research  and  development  projects,  waste  handling  and  spill
prevention  procedures  and  other  activities.
          Pine Street Barge Canal Site.  The Federal Comprehensive Environmental
Response,  Compensation,  and  Liability  Act  ("CERCLA"), commonly known as the
"Superfund"  law,  generally  imposes  strict,  joint  and  several  liability,
regardless  of  fault,  for  remediation of property contaminated with hazardous
substances.  The  Company  has  been  notified  by  the Environmental Protection
Agency  ("EPA")  that  it  is  one  of  several  potentially responsible parties
("PRPs") for cleanup of the Pine Street Barge Canal site in Burlington, Vermont,
where  coal  tar  and  other  industrial  materials  were  deposited.
          In  September  1999,  we negotiated a final settlement with the United
States,  the  State of Vermont, and other parties over terms of a Consent Decree
that  covers  claims addressed in the earlier negotiations and implementation of
the  selected  remedy.  In  November  1999,  the Consent Decree was filed in the
federal district court.  The Consent Decree addresses claims by the EPA for past
Pine  Street  Barge  Canal site costs, natural resource damage claims and claims
for  past  and future oversight costs.  The Consent Decree also provides for the
design  and  implementation  of  response  actions  at  the  site.
          As  of  December 31, 2000, the Company's total expenditures related to
the  Pine  Street  Barge Canal site since 1982 were approximately $23.5 million.
This  includes those amounts not recovered in rates, amounts recovered in rates,
and  amounts  for  which  rate  recovery has been sought but which are presently
awaiting  further  VPSB  action.  The  bulk  of  these expenditures consisted of
transaction  costs.  Transaction  costs  include  legal  and  consulting  costs
associated  with the Company's opposition to the EPA's earlier, and more costly,
proposals  for  the  site,  as well as litigation and related costs necessary to
obtain  settlements with insurers and other PRP's to provide amounts required to
fund  the  clean  up  (remediation costs) and to address liability claims at the
site.  A  smaller  amount  of  past  expenditures  was for site-related response
costs,  including  costs  incurred  pursuant  to  the  EPA and State orders that
resulted  in funding response activities at the site, and to reimbursing the EPA
and  the  State for oversight and related response costs.  The EPA and the State
have  asserted  and  affirmed  that  all  costs  related  to  these  orders  are
appropriate  costs of response under CERCLA for which the Company and other PRPs
were  legally  responsible.
          We  estimate  that  we  have  recovered  or  secured, or will recover,
through  settlements  of  litigation  claims against insurers and other parties,
amounts that exceed estimated future remediation costs, future federal and state
government  oversight  costs and past EPA response costs.  We currently estimate
our  unrecovered  transaction  costs  mentioned  above,  which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $12.4 million over the next 33
years.  The  estimated  liability is not discounted, and it is possible that our
estimate  of  future  costs  could  change  by  a material amount.  We also have
recorded  an offsetting regulatory asset and we believe that it is probable that
we  will  receive  future  revenues to recover these costs.  Although it did not
eliminate  the  rate  base  deferral of these expenditures, or make any specific
order  in  this  regard,  the  VPSB indicated that it was inclined to agree with
other  parties  in  the  case  that  the ultimate costs associated with the Pine
Street  Barge Canal site, taking into account recoveries from insurance carriers
and  other  PRPs,  should  be  shared  between customers and shareholders of the
Company.  In  response  to  our  Motion for Reconsideration, the VPSB on June 8,
1998  stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
The  VPSB  Order  released  January 23, 2001 regarding the Company's 1998 retail
rate  request  did  not  change  the  status  of  Pine  Street  cost  recovery.

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

     3.  OPERATING  LEASES.  The  Company  terminated an operating lease for its
corporate  headquarters  building and two of its service center buildings in the
first  quarter  of  1999.  During  1998,  the  Company  recorded  a  loss  of
approximately  $1.9  million  before  applicable  income  taxes  to  reflect the
probable  loss  resulting from this transaction.  The Company sold its corporate
headquarters  building  in  1999,  but  retained  ownership  of  the two service
centers.

     4.  JOINTLY-OWNED FACILITIES.  The Company has joint-ownership interests in
electric  generating  and  transmission  facilities  at  December  31,  2000, as
follows:
<TABLE>
<CAPTION>

                         Ownership     Share of     Utility     Accumulated

                          Interest   Capacity        Plant       Depreciation
                          ---------  ---------  ---------------  -------------
                           (In %)    (In MWh)   (In thousands)
<S>                       <C>        <C>        <C>              <C>
Highgate . . . . . . . .       33.8       67.6  $        10,299  $       4,118
McNeil . . . . . . . . .       11.0        5.9            8,866          4,484
Stony Brook (No. 1). . .        8.8         31           10,339          7,636
Wyman (No. 4). . . . . .        1.1        6.8            1,980          1,192
Metallic Neutral Return.       59.4          -  $         1,563  $         619
</TABLE>


Metallic  Neutral  Return  is  a  neutral  conductor  for  NEPOOL/Hydro-Quebec
Interconnection


     The  Company's  share  of expenses for these facilities is reflected in the
Consolidated  Statements  of  Income.  Each participant in these facilities must
provide  its  own  financing.

   5.  RATE  MATTERS.

RETAIL  RATE CASES- On March 2, 1998, the VPSB released its Order dated February
27,  1998 in the then pending rate case.  The VPSB authorized us to increase our
rates  by 3.61 percent, which gave us increased annual revenues of $5.6 million.
The  VPSB  Order  denied  us  the right to charge customers $5.48 million of the
annual costs for power purchased under our contract with Hydro-Quebec.  The VPSB
denied  recovery  of  these  costs  for  the  following  reasons:

*     the  VPSB claimed that we had acted imprudently by committing to the power
contract  with  Hydro-Quebec  in  August 1991 (the imprudence disallowance); and
*     to  the  extent  that the costs of power to be purchased from Hydro-Quebec
were  then  higher  than current estimates of market prices for power during the
contract  term,  after  accounting for the imprudence disallowance, the contract
power  was  not  "used  and  useful".

          On  May  8,  1998,  we  filed  a request with the VPSB to increase our
retail rates by 12.93 percent due to higher power costs, the cost of the January
1998  ice  storm,  and  investments  in  new  plant  and  equipment.
               On November 18, 1998, by Memorandum of Understanding ("MOU"), the
Company, the Department and IBM agreed to stay rate proceedings in the 1998 rate
case  until  or after September 1, 1999, or such earlier date as the parties may
later  agree  to  or the VPSB may order.  The agreement to suspend our 1998 rate
case  delayed the date of a final decision on the 1998 rate case to December 15,
1999,  and we recognized an additional loss of $5.25 million in the last quarter
of  1998  representing  the effect of the continued disallowance of Hydro-Quebec
costs  through  December  15, 1999. The MOU provided for a 5.5% temporary retail
rate  increase,  to  produce  $8.9  million  in  annualized  additional revenue,
effective  with service rendered December 15, 1998.  An additional surcharge was
permitted,  without  further VPSB order, in order to produce additional revenues
necessary  to  provide the Company with the capacity to finance 1999 Pine Street
Barge Canal site expenditures.  The MOU was approved by the VPSB on December 11,
1998. The MOU did not provide for any specific disallowance of power costs under
our  purchase  power  contract with Hydro-Quebec.  Issues respecting recovery of
such  power  costs  were  preserved  for  future  proceedings.
     The  stay  and  suspension of this pending rate case and the temporary rate
levels  agreed  to  in  the MOU were designed to allow us to continue to provide
adequate  and  efficient  service to our customers while we sought mitigation of
power  supply  costs.
     On  September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments  to the MOU that the Company had entered into with the Department and
IBM.  The  two  amendments  continued the stay of proceedings until September 1,
2000,  with  a  final  decision  expected  by December 31, 2000.  The amendments
maintained  the  other  features  of  the original MOU, and the second amendment
provided  for  a  temporary rate increase of 3 percent, in addition to the prior
temporary  rate  level,  to  become  effective  as  of  January  1,  2000.
The  Company  reached  a final settlement agreement with the VDPS in the pending
rate  case  during  November  2000.  The final settlement agreement contains the
following  provisions:

*     A rate increase of 3.42 percent above existing rates, beginning with bills
rendered  January 23, 2001, and prior temporary rate increases became permanent;
*     Rates  set  at  levels  that  recover  the Company's Hydro-Quebec contract
costs,  effectively  ending  the  regulatory  disallowances  experienced  by the
Company  over  the  past  three  years;
*     The  Company  agrees  not  to  seek any further increase in electric rates
prior  to  April  2002 (effective in bills rendered January 2003) unless certain
substantially  adverse  conditions  arise,  including  a  provision  allowing  a
request  for  rate  relief  if  power  supply  costs increase in excess of $3.75
million  over  forecasted  levels;
*     The  Company agrees to write off approximately $3.2 million in unrecovered
rate  case  litigation  costs,  and  to  freeze  its  dividend  rate  until  it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
*     Seasonal  rates  will  be  eliminated  in April 2001, which is expected to
generate  approximately $6.0 million in cash flow that can be utilized to offset
increased  costs  during  2001,  2002  and  2003;  and
*     The  Company  agrees to consult extensively with the DPS regarding capital
spending commitments for upgrading our electric distribution system and to adopt
customer  care  and  reliability  performance  standards, in a first step toward
possible  development  of  performance-based  rate-making.

     On  January  23,  2001, the VPSB approved the Company's settlement with the
Department,  with  two  additional  conditions:
*     The  Settlement  Order requires the Company and customers to share equally
any premium above book value realized by the Company, subject to an $8.0 million
limit  on the customers' share, in any future merger, acquisition or asset sale;
and
*     The  second  condition  restricts  Company  investments  in  non-utility
operations.


     6.  TRANSMISSION.  A  FERC ruling in December 2000 required ISO New England
to  revise  its  installed capability ("ICAP") deficiency charge of $0.17 per kw
month  to $8.75 per kw month retroactive to August 1, 2000. On January 10, 2001,
the  FERC suspended its order "to ensure that bills for past periods will not be
assessed until the Commission has considered the pending requests for rehearing,
which,  if  successful,  would  then  require extensive refunds and surcharges".
Numerous  requests for rehearing challenging the imposition of the new rate have
been filed by New England utilities and state commissions.  If the FERC does not
change  its  initial  order  as a result of the rehearings, the Company would be
required  to  pay  ISO  New  England approximately $1.4 million related to 2000.
Management  does  not  believe  that  the  retroactive  application  of the ICAP
revision  is  probable.

     7.  DEFERRED  CHARGES  NOT INCLUDED IN RATE BASE.  The Company has incurred
and deferred approximately $3.0 million in costs for tree trimming, storm damage
and  federal  regulatory commission work of which $2.8 million will be amortized
over  five years ending in December 2005.  Currently, the Company amortizes such
costs  based  on  historical  averages  and does not receive a return on amounts
deferred.  Management expects to seek and receive ratemaking treatment for these
costs  in  future  filings.
          The  Settlement  Order  directed  the  Company  to  write-off deferred
charges applicable to the state regulatory commission of $3.2 million as part of
the rate case agreement with the DPS.  The charge is included in other operating
expense for the year ended December 31, 2000.  The Settlement Order requires the
remaining  balance  and  future  expenditures  of deferred regulatory commission
charges  be  amortized  over  seven  years.

     8.  OTHER  LEGAL  MATTERS.  The  Company  is  involved  in  legal  and
administrative proceedings in the normal course of business and does not believe
that  the  ultimate  outcome of these proceedings will have a material effect on
the  financial  position  or  the  results  of  operations  of  the  Company.

J.     OBLIGATIONS  UNDER  TRANSMISSION  INTERCONNECTION  SUPPORT  AGREEMENT

          Agreements  executed in 1985 among the Company, VELCO and other NEPOOL
members  and  Hydro-Quebec  provided  for  the  construction of the second phase
(Phase  II)  of the interconnection between the New England electric systems and
that  of  Hydro-Quebec.  Phase  II  expands  the  Phase  I  facilities  from 690
megawatts to 2,000 megawatts and provides for transmission of Hydro-Quebec power
from  the  Phase  I  terminal  in  northern  New  Hampshire  to  Sandy  Pond,
Massachusetts.  Construction  of Phase II commenced in 1988 and was completed in
late  1990.  The Company is entitled to 3.2 percent of the Phase II power-supply
benefits.  Total  construction  costs  for  Phase  II  were  approximately  $487
million.  The  New  England participants, including the Company, have contracted
to  pay  monthly  their  proportionate  share of the total cost of constructing,
owning  and  operating  the  Phase II facilities, including capital costs.  As a
supporting participant, the Company must make support payments under thirty-year
agreements.  These  support  agreements  meet  the  capital  lease  accounting
requirements  under  SFAS  13.  At  December  31, 2000, the present value of the
Company's  obligation  is  approximately  $6.4  million.

          Projected  future  minimum  payments  under  the  Phase  II  support
agreements  are  as  follows:

<TABLE>
<CAPTION>



                      YEAR ENDING DECEMBER 31,
                     --------------------------
                           (In thousands)
<S>                  <C>
2001. . . . . . . .  $                      430
2002. . . . . . . .                         430
2003. . . . . . . .                         430
2004. . . . . . . .                         430
2005. . . . . . . .                         430
Total for 2006-2020                       4,299
    Total . . . . .  $                    6,449
                     ==========================
</TABLE>

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

K.     LONG-TERM  POWER  PURCHASES

     1.  Unit  Purchases.  Under  long-term  contracts  with  various  electric
utilities  in  the  region, the Company is purchasing certain percentages of the
electrical  output  of  production  plants  constructed  and  financed  by those
utilities.  Such  contracts  obligate  the Company to pay certain minimum annual
amounts representing the Company's proportionate share of fixed costs, including
debt  service  requirements  whether or not the production plants are operating.
The  cost  of  power obtained under such long-term contracts, including payments
required when a production plant is not operating, is reflected as "Power Supply
Expenses"  in  the  accompanying  Consolidated  Statements  of  Income.
          Information  (including estimates for the Company's portion of certain
minimum  costs and ascribed long-term debt) with regard to significant purchased
power  contracts  of  this  type  in  effect  during  2000  follows:


<TABLE>
<CAPTION>

                                                           STONY     VERMONT

                                                           BROOK      YANKEE
                                                 ----------------------  ----------
                                                         (Dollars in thousands)
<S>                                                           <C>         <C>
Plant capacity. . . . . . . . . .                           352.0 MW   531.0 MW
Company's share of output                                       4.40%    17.90%
Contract period                                                   (1)       (2)
Company's annual share of:
  Interest                                                 $     189   $ 2,397
  Other debt service                                             347
  Other capacity                                                 497    25,401
                                                           ----------  --------
Total annual capacity                                      $   1,033   $27,798
                                                           ==========  ========

Company's share of long-term debt                          $   3,194   $17,181
</TABLE>

(1)  Life  of  plant  estimated  to  be  1981  -  2006.
(2)  License  for  plant  operations  expires  in  2012.


     2.  Hydro-Quebec System Power Purchase and Sale Commitments.  Under various
contracts,  the  details  of which are described in the table below, the Company
purchases  capacity  and  associated energy produced by the Hydro-Quebec system.
Such  contracts obligate the Company to pay certain fixed capacity costs whether
or  not  energy  purchases  above a minimum level set forth in the contracts are
made.  Such  minimum  energy  purchases  must be made whether or not other, less
expensive  energy  sources  might be available.  These contracts are intended to
complement  the  other  components  in the Company's power supply to achieve the
most  economic  power-supply  mix  reasonably  available.
          The  Company's  current  purchases  pursuant  to  the  contract  with
Hydro-Quebec  entered  into December 4, 1987 (the 1987 Contract) are as follows:
(1)  Schedule  B  --  68  megawatts of firm capacity and associated energy to be
delivered  at  the  Highgate  interconnection  for  twenty  years  beginning  in
September  1995;  and  (2)  Schedule  C3  --  46  megawatts of firm capacity and
associated  energy  to  be delivered at interconnections to be determined at any
time  for  20  years,  which  began  in  November  1995.
          During  1994,  the Company negotiated an arrangement with Hydro-Quebec
that reduces the cost impacts associated with the purchase of Schedules B and C3
under the 1987 Contract, over the November 1995 through October 1999 period (the
July  1994  Agreement).  Under the July 1994 Agreement, the Company, in essence,
will  take  delivery of the amounts of energy as specified in the 1987 Contract,
but  the  associated  fixed  costs  will  be  significantly  reduced  from those
specified  in  the  1987  Contract.
          As part of the July 1994 Agreement, we were obligated to purchase $4.0
million  (in  1994  dollars)  worth  of  research  and  development  work  from
Hydro-Quebec  over  a period ending October 1999(which has since been extended),
and  made  an  additional  $6.5  million  (plus  accrued  interest)  payment  to
Hydro-Quebec  in  1995.  Hydro-Quebec retains the right to curtail annual energy
deliveries  by  10  percent  up  to five times, over the 2000 to 2015 period, if
documented  drought  conditions  exist in Quebec.  The period for completing the
research  and  development  purchase  was  subsequently  extended to March 2001.
          During  the  first  year  of  the July 1994 Agreement (the period from
November  1995  through  October  1996),  the  average cost per kilowatt-hour of
Schedules  B  and C3 combined was cut from 6.4 to 4.2 cents per kilowatt-hour, a
34  percent (or $16 million) cost reduction.  Over the period from November 1996
through  December  2000  and  accounting  for  the payments to Hydro-Quebec, the
combined  unit  costs  will  be lowered from 6.5 to 5.9 cents per kilowatt-hour,
reducing  unit  costs  by  10 percent and saving $20.7 million in nominal terms.
          All of the Company's contracts with Hydro-Quebec call for the delivery
of  system  power  and  are  not  related  to  any  particular facilities in the
Hydro-Quebec  system.  Consequently,  there  are  no  identifiable  debt-service
charges  associated  with  any  particular  Hydro-Quebec  facility  that  can be
distinguished  from  the  overall  charges  paid  under  the  contracts.
          A  summary  of  the  Hydro-Quebec  contracts  through  the  July  1994
Agreement,  including  historic  and  projected charges for the years indicated,
follows:
<TABLE>
<CAPTION>















                                                                  THE 1987 CONTRACT

                                                                   SCHEDULE B   SCHEDULE C3
                                                                 ------------- -------------
                                                             (Dollars in thousands except per KWh)
<S>                       <C>                                    <C>            <C>      <C>      <C>
Capacity acquired                                                       68 MW            46 MW
Contract period. . . . .                                            1995-2015          1995-2015
Minimum energy purchase.                                               75%                 75%
(annual load factor)

Annual energy charge . .                                  2000   $     10,471             $ 7,105
  estimated. . . . . . .                             2001-2015         13,506         *    9,320    *

Annual capacity charge .                                  2000         16,850             11,727
  estimated. . . . . . .                             2001-2015         16,686         *   11,523    *

Average cost per KWh . .                                  2000   $      0.068            $ 0.069
  estimated. . . . . . .                             2001-2015   $      0.070        **  $ 0.070   **
</TABLE>

*Estimated  average
**Estimated  average  in  nominal  dollars  levelized  over the period indicated
Includes  amortization  of  payments to Hydro-Quebec for the July 1994 Agreement

          Under  a  1996  arrangement  (the  "9601 arrangement"), the Company is
required  to  shift  up  to  40  megawatts  of  its  Schedule C3 to an alternate
transmission  path  and  use  the  associated portion of the NEPOOL/Hydro-Quebec
interconnection  facilities to purchase power for the period from September 1996
through  June  2001 at prices that vary based upon conditions in effect when the
purchases  were  made.   The 9601 arrangement also provides for minimum payments
by  the  Company to Hydro-Quebec for the periods in which power is not purchased
under  the  arrangement.  The  9601  arrangement  allows Hydro-Quebec to curtail
energy  deliveries  should  it  need  to  use  certain  resources  to supplement
available  supply.  During  the  last  three  months  of  2000, Hydro-Quebec did
curtail  energy  deliveries.  Although the level of benefits to the Company will
depend  on various factors, the Company estimates that the 9601 arrangement will
provide  a  benefit  of approximately $3.0 million on a net present value basis.
          Under  a  separate  agreement  executed on December 5, 1997 (the "9701
arrangement"), Hydro-Quebec provided a payment of $8.0 million to the Company in
1997.  In return for this payment, the Company  provided Hydro-Quebec an ongoing
option  for  the  purchase  of  power.  Commencing  April 1, 1998, and effective
through  October  2015,  Hydro-Quebec  can  exercise an option to purchase up to
52,500  MWh  ("option  A")  on  an annual basis, at energy prices established in
accordance  with  the 1987 Contract.   The cumulative amount of energy purchased
under the 9701 arrangement shall not exceed 950,000 MWh.   Hydro-Quebec's option
to  curtail  energy  deliveries  pursuant  to  the  July  1994  Agreement may be
exercised  in  addition  to  these  purchase  options.
          Over the same period, Hydro-Quebec can exercise an option on an annual
basis  to  purchase  a  total  of  600,000 MWh ("option B") at the 1987 Contract
energy  price.  Hydro-Quebec  can purchase no more than 200,000 MWh in any given
contract  year  ending  October  31.  As  of December 31, 2000, Hydro-Quebec had
purchased  or called to purchase 349,000 MWh under option B, including calls for
January  and  February  of  2001.
          In  2000, Hydro-Quebec called for deliveries to third parties at a net
cost  to  the  Company of approximately $14.0 million (including the cost of the
January  and February 2001 calls and related financial positions), which was due
to  higher  energy  replacement  costs.  Approximately  $6.6 million of the 9701
arrangement  costs  are  recovered  currently  in rates on an annual basis.  The
VPSB,  in  the  Settlement Order said, "The record does not demonstrate that any
other  New  England utility foresaw the extent and degree of volatility that has
developed  in  the  New England wholesale power markets. Absent that volatility,
the  97-01  Agreement  would not have had adverse effects."  In conjunction with
the  Settlement  Order, Hydro-Quebec committed to the DPS that it would not call
any  energy  under  option  B  of  the  9701  arrangement during 2002.  In 1999,
Hydro-Quebec called for deliveries to third parties at a net cost to the Company
of  approximately $6.3 million.  The Company's estimate of the fair value of the
future  net cost for the 9701 arrangement, which is dependent upon the timing of
any  exercise of options, and the market price for replacement power, is between
$24.5  and  $29.5  million.  Future estimates could change by a material amount.
          In  1999,  the Company and the other Vermont Joint Owners (VJO) of the
Hydro-Quebec contract initiated an arbitration against Hydro-Quebec, pursuant to
the  1987  Contract  terms, to determine whether the suspension of deliveries of
power to Vermont during and after the January 1998 ice storm evidenced a default
by  Hydro-Quebec  under the terms of the contract.   Hydro-Quebec maintains that
the  "force  majeure"  (superior  or  irreversible  force) provision in the 1987
Contract  applies,  which  could  excuse  its  non-delivery of power under these
circumstances.  Arbitration  of  the  dispute  may  lead  to  remedies  having a
material  impact  on  our contractual obligation, including the possibility that
the  1987  Contract be declared terminated or void.  If arbitration results in a
cash payment, it will first be applied to a regulatory asset of $4.7 million for
arbitration  litigation  costs.  If  the 1987 Contract is declared terminated or
void,  the Company would have to replace a substantial amount of its power needs
at  terms  which  could materially exceed the 1987 Contract price for 2001.  The
Company believes that it could contract replacement power at costs substantially
below  the  long term costs of the 1987 Contract.  The Settlement Order provides
that  the  Company  will not earn a return on these litigation costs, unless the
case results in lower power supply costs for ratepayers.  A decision is expected
in  this  arbitration  in  April  2001.

     3.  Morgan  Stanley  Agreement  - On February 11, 1999, the Company entered
into  a contract with Morgan Stanley Capital Group, Inc. (MS).  In January 2001,
the  MS  contract  was modified and extended to December 31, 2003.  The contract
provides us a means of managing price risks associated with changing fossil fuel
prices.  On  a  daily basis, and at MS's discretion, the Company will sell power
to  MS  from  either  (i)  all  or  part  of our portfolio of power resources at
predefined  operating  and  pricing  parameters  or  (ii)  any  power  resources
available  to  the Company, provided that sales of power from sources other than
Company-owned  generation  comply  with  the  predefined  operating  and pricing
parameters.   MS  then  sells  to us, at a predefined price, power sufficient to
serve  pre-established load requirements.  MS is also responsible for scheduling
supply  resources.  The Company remains responsible for resource performance and
availability.  MS  provides  no  coverage  against  major  unscheduled  outages.

     L.  DISCONTINUED  OPERATIONS.
          The Company has decided to sell or otherwise dispose of the operations
and  assets  of  MEI,  which  owns  and  invests  in  energy  generation, energy
efficiency,  and  wastewater  treatment  projects.  MEI  has  been reported as a
separate  segment  in  1998  and prior years, and appeared as a separate "Equity
investment  in energy related business" caption in the nonutility section of the
consolidated  balance  sheet.  Results of operations were previously included in
the section Other Income in the consolidating statements of income.  In 1999 and
2000,  assets  and  liabilities  are  presented net in the nonutility section as
"Business  segment  held  for disposal", or "Liability of discontinued segment".
The  provisions  for  loss  from  discontinued  operations  reflect management's
current  estimate.  Risk  factors  associated  with  the  discontinuation of MEI
operations  include  the  outcome  of  warranty  litigation,  and  future  cash
requirements  necessary to minimize costs of winding down wastewater operations.
Several  municipalities  using  wastewater treatment equipment have commenced or
threatened  litigation.  The ultimate loss remains subject to the disposition of
remaining  assets  and  liabilities, and could exceed the amounts recorded.  The
following  illustrates  the results and financial statement impact of MEI during
and  at  the  periods  shown:
<TABLE>
<CAPTION>



                                        2000      1999      1998
                                      --------  --------  --------
(In thousands except per share)
<S>                                   <C>       <C>       <C>
Revenues . . . . . . . . . . . . . .  $ 1,546   $ 2,296   $ 2,092
                                      --------  --------  --------
Net income (loss) operations . . . .  $     -   $  (603)  $(2,086)
Provisions for loss on disposal and
  future operating losses. . . . . .   (6,549)   (6,676)        -
Net income (loss). . . . . . . . . .  $(6,549)  $(7,279)  $(2,086)
                                      ========  ========  ========
Net income (loss) per share. . . . .  $ (1.19)  $ (1.36)  $ (0.40)
</TABLE>
Income  taxes  for  MEI for the years ended December 31, 2000, 1999 and 1998 are
summarized  as:

<TABLE>
<CAPTION>

          YEARS  ENDED  DECEMBER  31,

                                2000      1999      1998
                              --------  --------  --------
(In thousands)
<S>                           <C>       <C>       <C>
State income taxes . . . . .  $(1,064)  $  (281)  $  (222)
Federal income taxes . . . .   (3,349)   (1,371)   (1,130)
Investment tax credits . . .        -         -      (111)
                              --------  --------  --------
Income tax expense (benefit)  $(4,413)  $(1,652)  $(1,463)
                              ========  ========  ========
</TABLE>

M.  QUARTERLY  FINANCIAL  INFORMATION  (UNAUDITED)

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




<TABLE>
<CAPTION>

                                           2000  Quarter  ended

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



<TABLE>
<CAPTION>
                                           1999  Quarter  ended

                                                MARCH      JUNE     SEPTEMBER    DECEMBER     TOTAL
                                               --------  --------  -----------  ----------  ---------
(Amounts in thousands except per share data)
<S>                                            <C>       <C>       <C>          <C>         <C>
Operating revenues. . . . . . . . . . . . . .  $59,018   $59,535   $   68,478   $  64,017   $251,048
Operating income. . . . . . . . . . . . . . .    3,906       977        1,412       1,651      7,946
Net income (loss) from continuing operations.  $ 3,170   $  (412)  $     (115)  $     418   $  3,061
Net loss from
 discontinued operations. . . . . . . . . . .     (522)      (81)      (4,592)     (2,084)    (7,279)
Net Income (loss) applicable to common stock.  $ 2,648   $  (493)  $   (4,707)  $  (1,666)  $ (4,218)
                                               ========  ========  ===========  ==========  =========
Earnings (loss) per average share from:
Continuing operations . . . . . . . . . . . .  $  0.60   $ (0.08)  $    (0.02)  $    0.07   $   0.57
Discontinued operations . . . . . . . . . . .    (0.10)    (0.02)       (0.85)      (0.39)     (1.36)
Basic and diluted . . . . . . . . . . . . . .  $  0.50   $ (0.10)  $    (0.88)  $   (0.31)  $  (0.79)
                                               ========  ========  ===========  ==========  =========
Weighted average common shares outstanding. .    5,318     5,344        5,374       5,291      5,361
</TABLE>


<TABLE>
<CAPTION>

                                           1998  Quarter  ended

                                                MARCH      JUNE     SEPTEMBER    DECEMBER     TOTAL
                                               --------  --------  -----------  ----------  ---------
(Amounts in thousands except per share data)
<S>                                            <C>       <C>       <C>          <C>         <C>
Operating revenues. . . . . . . . . . . . . .  $46,932   $43,733   $   47,984   $  45,655   $184,304
Operating income. . . . . . . . . . . . . . .      316     2,811        3,147        (802)     5,472
Net income (loss) from continuing operations.  $(2,648)  $ 1,286   $    1,811   $  (2,536)  $ (2,087)
Net loss from
discontinued operations . . . . . . . . . . .     (757)     (355)        (178)       (796)    (2,086)
Net income (loss) applicable to common stock.  $(3,405)  $   931   $    1,633   $  (3,332)  $ (4,173)
                                               ========  ========  ===========  ==========  =========
Earnings (loss) per average share from:
Continuing operations . . . . . . . . . . . .  $ (0.51)  $  0.25   $     0.34   $   (0.48)  $  (0.40)
Discontinued operations . . . . . . . . . . .    (0.15)    (0.06)       (0.03)      (0.16)     (0.40)
Basic and diluted . . . . . . . . . . . . . .  $ (0.66)  $  0.18   $     0.31   $   (0.63)  $  (0.80)
                                               ========  ========  ===========  ==========  =========
Weighted average common shares outstanding. .    5,196     5,222        5,261       5,291      5,243
</TABLE>


69





                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
                    ----------------------------------------


To  the  Board  of  Directors  of
   Green  Mountain  Power  Corporation:

We  have  audited  the accompanying consolidated balance sheets and consolidated
capitalization  data of Green Mountain Power Corporation (a Vermont corporation)
and  its  subsidiaries  as  of  December  31,  2000  and  1999,  and the related
consolidated statements of income, retained earnings, and cash flows for each of
the  three  years  in  the  period  ended  December  31,  2000.  These financial
statements  are  the  responsibility  of  the  Company's  management.  Our
responsibility  is  to express an opinion on these financial statements based on
our  audit.

We conducted our audits in accordance with auditing standards generally accepted
in  the  United  States.  Those  standards  require that we plan and perform the
audit  to obtain reasonable assurance about whether the financial statements are
free  of  material  misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.  An
audit  also  includes  assessing  the accounting principles used and significant
estimates  made  by  management,  as  well  as  evaluating the overall financial
statement  presentation.  We  believe that our audits provide a reasonable basis
for  our  opinion.

In  our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Green Mountain Power
Corporation  and  its  subsidiaries  as  of  December 31, 2000 and 1999, and the
consolidated  results  of  its  operations  and cash flows for each of the three
years  in  the  period  ended  December  31, 2000, in conformity with accounting
principles  generally  accepted  in  the  United  States.





/s/  Arthur  Anderson
Boston,  Massachusetts
February  2,  2001


<TABLE>
<CAPTION>
Schedule  II
GREEN  MOUNTAIN  POWER  CORPORATION
VALUATION  AND  QUALIFYING  ACCOUNTS  AND  RESERVES
For  the  Years  Ended  December  31,  2000,  1999,  and  1998
                           Balance at       Additions         Additions     Balance at
                          Beginning of      Charged to       Charged to       End of
                             Period      Cost & Expenses   Other Accounts   Deductions     Period
                          -------------  ----------------  ---------------  -----------  -----------
<S>                       <C>            <C>               <C>              <C>          <C>
Injuries and Damages (1)
2000 . . . . . . . . . .  $  10,129,130  $        111,667  $     3,193,383  $    51,467  $13,382,713
1999 . . . . . . . . . .      7,898,785           100,000        3,814,874    1,684,529   10,129,130
1998 . . . . . . . . . .        663,785         2,735,000        5,000,000      500,000    7,898,785
Bad Debt Reserve
2000 . . . . . . . . . .        390,495            35,395                -            -      425,890
1999 . . . . . . . . . .        400,000           261,697           12,762      283,964      390,495
1998(2). . . . . . . . .        493,405           393,949           83,299      570,653      400,000
</TABLE>


(1)  Includes  Pine  Street  Barge  Canal  reserves
(2)  Includes  non-utility  bad  debt  reserve.




71

                                                                  Exhibit 23-a-1

                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
                    -----------------------------------------





As independent public accountants, we hereby consent to the incorporation of our
reports  dated  February  2,  2001 included in this Form 10-K into the Company's
previously  filed  Registration  Statements  on Form S-3, File Nos. 33-58411 and
33-59383,  and  into  the  Company's previously filed Registration Statements on
Form  S-8, File Nos. 33-58413 and 33-60511.  It should be noted that we have not
performed  any audit procedures subsequent to December 31, 2000 or performed any
audit  procedures  subsequent  to  the  date  of  our  report.




Boston,  Massachusetts
March  21,  2001                              /s/  Arthur  Andersen  LLP






                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
                    ----------------------------------------





We  have  audited, in accordance with generally accepted auditing standards, the
consolidated  financial  statements of Green Mountain Power Corporation included
in this Form 10-K and have issued our report thereon dated February 2, 2001. Our
audit  was  made  for  the  purpose of forming an opinion on the basic financial
statements  taken  as  a whole. The schedule listed in the accompanying index to
consolidated  financial  statements  and  schedules is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic consolidated financial statements. This schedule has been subjected to
the auditing procedures applied in the audit of the basic consolidated financial
statements,  and  in  our  opinion, fairly states, in all material respects, the
financial  data  required  to  be  set  forth  therein  in relation to the basic
consolidated  financial  statements  taken  as  a  whole.




Boston,  Massachusetts
February  2,  2001                         /s/  Arthur  Andersen  LLP




72


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

     None


                                    PART III

ITEMS  10,  11,  12  &  13

     Certain  information  regarding  executive  officers called for by Item 10,
"Directors  and  Executive  Officers  of the Registrant," is furnished under the
caption,  "Executive  Officers"  in  Item 1 of Part I of this Report.  The other
information  called  for by Item 10, as well as that called for by Items 11, 12,
and  13,  "Executive  Compensation,"  "Security  Ownership of Certain Beneficial
Owners  and  Management"  and  "Certain Relationships and Related Transactions,"
will  be  set  forth  under  the  captions  "Election  of  Directors,"  Board
Compensation,  Other  Relationship,  Meetings  and  Committees,  "Section  16(a)
Beneficial  Ownership  Reporting  Compliance,"  "Executive  Compensation,"
Compensation  Committee  Report  on  Executive Compensation, Performance Graphs,
"Pension  Plan  Information"  and  "Securities  Ownership  of Certain Beneficial
Owners  and  Management" in the Company's definitive proxy statement relating to
its annual meeting of stockholders to be held on May 17, 2001.  Such information
is  incorporated  herein  by  reference.  Such  proxy  statement pertains to the
election  of  directors  and  other matters.  Definitive proxy materials will be
filed  with the Securities and Exchange Commission pursuant to Regulation 14A in
March  2001.


                                     PART IV

ITEM  14.  EXHIBITS,  FINANCIAL  STATEMENT  SCHEDULES  AND  REPORTS  ON
          FORM  8-K
Item  14(a)1.  Financial  Statements and Schedules. The financial statements and
financial  statement  schedules  of  the  Company  are  listed  on  the Index to
financial  statements  set  forth  in  Item  8  hereof.

Item  14(b)     The  following  filings on Form 8-K were filed by the company on
the  topics  and  dates  indicated:
November  13, 2000 announced the negotiation of a final rate settlement with the
Vermont  Department  of  Public  Service.
November  15,  2000  announced  a  revised offer for the purchase of the Vermont
Yankee  nuclear  generating  plant  was  accepted by Vermont Yankee from AmerGen
Energy  Company.
January  5,  2001  announced  continued  mediation  with  Local  300  of  the
International  Brotherhood  of Electrical Workers, which had gone on strike that
week  resulting  in  the  need  for  a  federal  mediator.
January  23, 2001 announced the Vermont Public Service Board Order approving the
rate  case  settlement  between the Company and the Vermont Department of Public
Service,  allowing  a  3.42  percent  increase  in  electric  rates,  and making
permanent  the  two  prior  temporary  rate  increases.
January  26,  2001  announced  Local  300  of  the  International Brotherhood of
Electrical Workers voted to end the strike and ratify the new proposed contract,
which  included  a  provision  for  a  second  shift  crew.
February  14,  2001  announced the Vermont Public Service Board Order Dismissing
Petition  in  Docket Number 6300, in which the Board determined that the revised
offer  by  AmerGen  Energy  Company for the purchase of Vermont Yankee's nuclear
generating  plant  did  not  reflect  the  fair  market  value of the plant, and
dismissed  the  petition  for  approval.
March 6, 2001 announced the credit rating upgrade by Moody's Investor Service of
the  Company's  first  mortgage  bonds  from Ba1 to Baa2, and the upgrade of the
Company's  preferred  stock  from  ba3  to  baa3.

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



<TABLE>
<CAPTION>

ITEM  14(A)3  AND  ITEM  14(C).  EXHIBITS          SEC  DOCKET

                                                       INCORPORATED BY
                                                         REFERENCE OR
DESCRIPTION                                                EXHIBIT       PAGE FILED HEREWITH
-----------------------------------------------------  ----------------  --------------------
<S>                                                    <C>               <C>                   <C>
Restated Articles of Association, as certified. . . .               3-a  Form 10-K 1993
June 6, 1991.                                                                        (1-8291)
Amendment to 3-a above, dated as of May 20, 1993. . .             3-a-1  Form 10-K 1993
                                                                                                    (1-8291)
Amendment to 3-a above, dated as of October 11, 1996.             3-a-2  Form 10-Q Sept.
                                                                                               1996 (1-8291)
By-laws of the Company, as amended. . . . . . . . . .               3-b  Form 10-K 1996
February 10, 1997.                                                                   (1-8291)
Indenture of First Mortgage and Deed of Trust . . . .               4-b              2-27300
dated as of February 1, 1955.
First Supplemental Indenture dated as of. . . . . . .             4-b-2              2-75293
April 1, 1961.
Second Supplemental Indenture dated as of . . . . . .             4-b-3              2-75293
January 1, 1966.
Third Supplemental Indenture dated as of. . . . . . .             4-b-4              2-75293
July 1, 1968.
Fourth Supplemental Indenture dated as of . . . . . .             4-b-5              2-75293
October 1, 1969.
Fifth Supplemental Indenture dated as of. . . . . . .             4-b-6              2-75293
December 1, 1973.
Seventh Supplemental Indenture dated as . . . . . . .             4-a-7              2-99643
August 1, 1976.
Eighth Supplemental Indenture dated as of . . . . . .             4-a-8              2-99643
December 1, 1979.
Ninth Supplemental Indenture dated as of. . . . . . .             4-b-9              2-99643
July 15, 1985.
Tenth Supplemental Indenture dated as of. . . . . . .            4-b-10  Form 10-K 1989
June 15, 1989.                                                                       (1-8291)
Eleventh Supplemental Indenture dated as of . . . . .            4-b-11  Form 10-Q Sept.
September 1, 1990.                                                              1990 (1-8291)
Twelfth Supplemental Indentrue dated as of. . . . . .            4-b-12  Form 10-K 1991
March 1, 1992.                                                                       (1-8291)
Thirteenth Supplemental Indenture dated as of . . . .            4-b-13  Form 10-K 1991
March 1, 1992.                                                                       (1-8291)
Fourteenth Supplemental Indenture dated as of . . . .            4-b-14  Form 10-K 1993
November 1, 1993.                                                                    (1-8291)
Fifteenth Supplemental Indenture dated as of. . . . .            4-b-15  Form 10-K 1993
November 1, 1993.                                                                    (1-8291)
Sixteenth Supplemental Indenture dated as of. . . . .            4-b-16  Form 10-K 1995
December 1, 1995.                                                                    (1-8291)
Revised form of Indenture as filed as an Exhibit. . .            4-b-17  Form 10-Q Sept.
to Registration Statement No. 33-59383.                                         1995 (1-8291)
Credit Agreement by and among Green Mountain Power. .            4-b-18  Form 10-K 1997
The Bank of Nova Scotia, State Street Bank and                                       (1-8291)
Trust Company, Fleet National Bank, and Fleet
National Bank, as Agent
Amendment to Exhibit 4-b-18 . . . . . . . . . . . . .         4-b-18(a)  Form 10-Q Sept.
                                                                                               1998 (1-8291)
Form of Insurance Policy issued by Pacific. . . . . .              10-a              33-8146
Insurance Company, with respect to
indemnification of Directors and Officers.
Firm Power Contract dated September 16, 1958, . . . .              13-b              2-27300
between the Company and the State of Vermont
and supplements  thereto dated September 19,
1958; November 15, 1958;  October 1, 1960 and
February 1, 1964.
Power Contract, dated February 1, 1968, between . . .              13-d              2-34346
the Company and Vermont Yankee Nuclear Power
Corporation.
Amendment, dated June 1, 1972, to Power Contract. . .            13-f-1              2-49697
between the Company and Vermont Yankee Nuclear
Power Corporation.
Amendment, dated April 15, 1983, to Power . . . . . .         10-b-3(a)              33-8164
Contract between the Company and Vermont
Yankee Nuclear Power Corporation.
Additional Power Contract, dated. . . . . . . . . . .         10-b-3(b)              33-8164
February 1, 1984,between the Company and
Vermont Yankee Nuclear Power Corporation.
Capital Funds Agreement, dated February 1,. . . . . .              13-e              2-34346
1968, between the Company and Vermont
Yankee Nuclear Power Corporation.
Amendment, dated March 12, 1968, to Capital . . . . .              13-f              2-34346
Funds Agreement between the Company and
Vermont Yankee Nuclear Power Corporation.
Guarantee Agreement, dated November 5, 1981,. . . . .            10-b-6              2-75293
of the Company for its proportionate share
of the obligations of Vermont Yankee Nuclear
Power Corporation under a $40 million loan
arrangement.
Three-Party Power Agreement among the Company,. . . .              13-i              2-49697
VELCO and Central Vermont Public Service
Corporation dated November 21, 1969.
Amendment to Exhibit 10-b-7, dated June 1, 1981.. . .            10-b-8              2-75293
Three-Party Transmission Agreement among the. . . . .              13-j              2-49697
Company, VELCO and Central Vermont Public
Service Corporation, dated November 21, 1969.
Amendment to Exhibit 10-b-9, dated June 1, 1981.. . .           10-b-10              2-75293
Agreement with Central Maine Power Company et                                           5.16        2-52900
al, to enter into joint ownership of Wyman
plant, dated November 1, 1974.
New England Power Pool Agreement as amended to                                           4.8        2-55385
November 1, 1975.
Bulk Power Transmission Contract between the. . . . .              13-v              2-49697
Company and VELCO dated June 1, 1968.
Amendment to Exhibit 10-b-16, dated June 1, 1970. . .            13-v-i              2-49697
Power Sales Agreement, dated August 2, 1976, as . . .           10-b-20              33-8164
amended October 1, 1977, and related
Transmission Agreement, with the Massachusetts
Municipal Wholesale Electric Company.
Agreement dated October 1, 1977, for Joint. . . . . .           10-b-21              33-8164
Ownership, Construction and Operation of the
MMWEC Phase I  Intermediate Units, dated
October 1, 1977.
Contract dated February 1, 1980, providing for. . . .           10-b-28              33-8164
the sale of firm power and energy by the Power
Authority of the State of New York to the
Vermont Public Service Board.
Bulk Power Purchase Contract dated April 7, . . . . .           10-b-32              2-75293
1976, between VELCO and the Company.
Agreement amending New England Power Pool . . . . . .           10-b-33              33-8164
Agreement dated as of December 1, 1981,
providing for use of  transmission inter-
connection between New England and
Hydro-Qubec.
Phase I Transmission Line Support Agreement . . . . .           10-b-34              33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
VETCO and participating New England utilities
for construction, use and support of Vermont
facilities of transmission interconnection
between New England and Hydro-Qubec.
Phase I Terminal Facility Support Agreement . . . . .           10-b-35              33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
New England Electric Transmission Corporation
and participating New England utilities for
construction, use and support of New Hampshire
facilities of transmission interconnection
between New England and Hydro-Qubec.
Agreement with respect to use of Quebec . . . . . . .           10-b-36              33-8164
Interconnection dated as of December 1, 1981,
among participating New England utilities
for use of transmission interconnection
between New England and Hydro-Qubec.
Vermont Participation Agreement for Quebec. . . . . .           10-b-39              33-8164
Interconnection dated as of July 15, 1982,
between VELCO and participating Vermont
utilities for allocation of VELCO's rights
and obligations as a participating New
England utility in the transmission inter-
connection between New England and Hydro-Qubec.
Vermont Electric Transmission Company, Inc. . . . . .           10-b-40              33-8164
Capital Funds Agreement dated as of July 15,
1982, between VETCO and VELCO for VELCO to
provide capital to VETCO for construction of
the Vermont facilities of the transmission
inter-connection between New England and
Hydro-Qubec.
VETCO Capital Funds Support Agreement dated as. . . .           10-b-41              33-8164
of July 15, 1982, between VELCO and participating
Vermont utilities for allocation of VELCO's
obligation to VETCO under the Capital Funds
Agreement.
Energy Banking Agreement dated March 21, 1983,. . . .           10-b-42              33-8164
among Hydro-Qubec, VELCO, NEET and parti-
cipating New England utilities acting by and
through the NEPOOL Management Committee for
terms of energy banking between participating
New England utilities and Hydro-Qubec.
Interconnection Agreement dated March 21, 1983, . . .           10-b-43              33-8164
between Hydro-Qubec and participating New
England utilities acting by and through the
NEPOOL Management Committee for terms and
conditions of energy transmission between
New England and Hydro-Qubec.
Energy Contract dated March 21, 1983, between . . . .           10-b-44              33-8164
Hydro-Qubec and participating New England
utilities acting by and through the NEPOOL
Management Committee for purchase of
surplus energy from Hydro-Qubec.
Agreement for Joint Ownership, Construction and . . .           10-b-50              33-8164
Operation of the Highgate Transmission
Interconnection, dated August 1, 1984,
between certain electric distribution
companies, including the Company.
Highgate Operating and Management Agreement,. . . . .           10-b-51              33-8164
dated as of August 1, 1984, among VELCO and
Vermont electric-utility companies, including
the Company.
Allocation Contract for Hydro-Qubec Firm Power. . . .           10-b-52              33-8164
dated July 25, 1984, between the State of
Vermont and  various Vermont electric utilities,
including the Company.
Highgate Transmission Agreement dated as of . . . . .           10-b-53              33-8164
August 1, 1984, between the Owners of the
Project and various Vermont electric
distribution companies.
Agreements entered in connection with Phase II. . . .           10-b-61              33-8164
of the NEPOOL/Hydro-Qubec + 450 KV HVDC
Transmission Interconnection.
Agreement between UNITIL Power Corp. and the. . . . .           10-b-62              33-8164
Company to sell 23 MW capacity and energy from
Stony Brook Intermediate Combined Cycle Unit.
Sales Agreement dated as of June 20, 1986,. . . . . .           10-b-64              33-8164
between the Company and Fitchburg Gas and
Electric Light Company for sale of 10 MW
capacity and energy from the Vermont Yankee
plant.
Firm Power and Energy Contract dated December 4,. . .           10-b-68  Form 10-K 1992
1987, between Hydro-Qubec and participating                                          (1-8291)
Vermont utilities, including the Company, for
the purchase of firm power for up to thirty years.
Firm Power Agreement dated as of October 26, 1987,. .           10-b-69  Form 10-K 1992
between Ontario Hydro and Vermont Department of                                      (1-8291)
Public Service.
Firm Power and Energy Contract dated as of. . . . . .           10-b-70  Form 10-K 1992
February 23, 1987, between the Vermont Joint                                         (1-8291)
Owners of the Highgate facilities and Hydro-
Quebec for up to 50 MW of capacity.
Amendment to 10-b-70. . . . . . . . . . . . . . . . .        10-b-70(a)  Form 10-K 1992
                                                                                                    (1-8291)
Interconnection Agreement dated as of . . . . . . . .           10-b-71  Form 10-K 1992
February 23, 1987, between the Vermont Joint                                         (1-8291)
Owners of the Highgate facilities and Hydro-Qubec.
Participation Agreement dated as of April 1, 1988,. .           10-b-72  Form 10-Q
between Hydro-Qubec and participating Vermont . . . .  June 1988
utilities, including the Company, implementing                                       (1-8291)
the purchase of firm power for up to 30 years
under the Firm Power and Energy Contract dated
December 4, 1987 (previously filed with the
Company's Annual Report on Form 10-K for 1987,
Exhibit Number 10-b-68).
Restatement of the Participation Agreement filed. . .        10-b-72(a)  Form 10-K 1988
as Exhibit 10-b-72 on Form 10-Q for June 1988.                                       (1-8291)
Agreement dated as of May 1, 1988, between. . . . . .           10-b-73  Form 10-Q
Rochester Gas and Electric Corporation and the. . . .  September. 1988
Company, implementing the Company's purchase of up                                   (1-8291)
to 50 MW of electric capacity and associated energy.
Firm Power and Energy Contract dated December 29, . .           10-b-77  Form 10-K 1988
1988, between Hydro-Qubec and participating                                          (1-8291)
Vermont utilities, including the Company, for the
purchase of up to 54 MW of firm power and energy.
Transmission Agreement dated December 23, 1988, . . .           10-b-78  Form 10-K 1988
between the Company and Niagara Mohawk Power                                         (1-8291)
Corporation (Niagara Mohawk), for Niagara
Mohawk to provide electric transmission to
the Company from Rochester Gas and Electric
and Central Hudson Gas and Electric.
Sales Agreement dated May 24, 1989, between . . . . .           10-b-81  Form 10-Q
the Town of Hardwick, Hardwick Electric Department. .  June 1989
and the Company for the Company to purchase                                          (1-8291)
all of the output of Hardwick's generation and
transmission sources and to provide Hardwick
with all-requirements energy and capacity except
for that provided by the Vermont Department of
Public Service or Federal Preference Power.
Sales Agreement dated July 14, 1989, between. . . . .           10-b-82  Form 10-Q
Northfield Electric Department and the Company. . . .  June 1989
for the Company to purchase all of the output                                        (1-8291)
of Northfield's generation and transmission
sources and to provide Northfield with all-
requirements energy and capacity except for
that provided by the Vermont Department of
Public Service or Federal Preference Power.
Power Purchase and Sale Agreement between . . . . . .           10-b-85  Form 10-K 1998
Morgan Stanley Capital Group Inc. and the                                            (1-8291)
Company
Revolving Credit Agreement with KeyBank . . . . . . .           10-b-86  Form 10-Q Sept.
                                                                                               2000 (1-8291)
Amendment to Fleet Revolving Credit Agreement . . . .           10-b-87  Form 10-Q Sept.
                                                                                               2000 (1-8291)
Energy East Power Purchase Option Agreement . . . . .           10-b-88  Form 10-Q Sept.
</TABLE>

          2000  (1-8291)
<TABLE>
<CAPTION>



MANAGEMENT CONTRACTS OR COMPENSATORY PLANS OR ARRANGEMENTS
REQUIRED TO BE FILED AS EXHIBITS TO THIS FORM 10-K
PURSUANT TO ITEM 14(C)., ALL UNDER SEC DOCKET 1-8291
<S>                                                         <C>        <C>             <C>
Green Mountain Power Corporation Second Amended. . . . . .    10-d-1b  Form 10-K 1993
and Restated Deferred Compensation Plan for
Directors.
Green Mountain Power Corporation Second Amended. . . . . .    10-d-1c  Form 10-K 1993
and Restated Deferred Compensation Plan for
Officers.
Amendment No. 93-1 to the Amended and Restated . . . . . .    10-d-1d  Form 10-K 1993
Deferred Compensation Plan for Officers.
Amendment No. 94-1 to the Amended and Restated . . . . . .    10-d-1e  Form 10-Q
Deferred Compensation Plan for Officers. . . . . . . . . .  June 1994
Green Mountain Power Corporation Medical Expense . . . . .     10-d-2  Form 10-K 1991
Reimbursement Plan.
Green Mountain Power Corporation Officer . . . . . . . . .     10-d-4  Form 10-K 1991
Insurance Plan.
Green Mountain Power Corporation Officers' . . . . . . . .    10-d-4a  Form 10-K 1990
Insurance Plan as amended.
Green Mountain Power Corporation Officers' . . . . . . . .     10-d-8  Form 10-K 1990
Supplemental Retirement Plan.
Green Mountain Power Corporation Compensation Program. . .   10-d-15b  Form 10-K 1997
for Officers and Key Management Personnel as amended
August 4, 1997
Severance Agreement with N. R. Brock . . . . . . . . . . .    10-d-21  Form 10-K 1998
Severance Agreement with C. L. Dutton. . . . . . . . . . .    10-d-22  Form 10-K 1998
Severance Agreement with R. J. Griffin . . . . . . . . . .    10-d-23  Form 10-K 1998
Severance Agreement with M. H. Lipson. . . . . . . . . . .    10-d-25  Form 10-K 1998
Severance Agreement with C. T. Myotte. . . . . . . . . . .    10-d-26  Form 10-K 1998
Severance Agreement with W. S. Oakes . . . . . . . . . . .    10-d-27  Form 10-K 1998
Severance Agreement with M. G. Powell. . . . . . . . . . .    10-d-28  Form 10-K 1998
Severance Agreement with S. C. Terry . . . . . . . . . . .    10-d-29  Form 10-K 1998
Severance Agreement with J. H. Winer . . . . . . . . . . .    10-d-30  Form 10-K 1998
Subsidiaries of the Registrant                                                     21  Form 10-K 1996
Consent of Arthur Andersen LLP . . . . . . . . . . . . . .     23-a-1
Limited Power of Attorney                                                          24
</TABLE>

79

                                                                      EXHIBIT 24

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

     We,  the  undersigned directors of Green Mountain Power Corporation, hereby
severally  constitute  Christopher  L.  Dutton,  Nancy  R.  Brock, and Robert J.
Griffin,  and  each of them singly, our true and lawful attorney with full power
of  substitution,  to  sign  for us and in our names in the capacities indicated
below,  the  Annual  Report on Form 10-K of Green Mountain Power Corporation for
the  fiscal year ended December 31, 2000, and generally to do all such things in
our  name  and  behalf  in  our capacities as directors to enable Green Mountain
Power  Corporation  to comply with the provisions of the Securities Exchange Act
of 1934, as amended, all requirements of the Securities and Exchange Commission,
and all requirements of any other applicable law or regulation, hereby ratifying
and  confirming  our  signatures  as they may be signed by our said attorney, to
said  Annual  Report.

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

_/s/  Christopher  L.  Dutton  President  and  Director      February  5,  2001
-----------------------------
Christopher  L.  Dutton     (Principal  Executive
                           Officer)

_/s/  Thomas  P.  Salmon____
----------------------------
Thomas  P.  Salmon          Chairman  of  the  Board       February  5,  2001

_/s/  Nordahl  L.  Brue_______
------------------------------
Nordahl  L.  Brue           Director                    February  5,  2001

_/s/  William  H.  Bruett_____
------------------------------
William  H.  Bruett         Director                    February  5,  2001

_/s/  Merrill  O.  Burns_____
-----------------------------
Merrill  O.  Burns          Director                    February  5,  2001

_/s/  Lorraine  E.  Chickering
------------------------------
Lorraine  E.  Chickering    Director                    February  5,  2001

_/s/  John  V.  Cleary________
------------------------------
John  V.  Cleary            Director                    February  5,  2001

_/s/  David  R.  Coates________
-------------------------------
David  R.  Coates           Director                    February  5,  2001

_/s/  Euclid  A.  Irving______
------------------------------
Euclid  A.  Irving          Director                    February  5,  2001





80

                                   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



                                       By: ____/s/ Christopher L. Dutton________
                                               --------------------------
                                             Christopher  L.  Dutton,  President
                                             and  Chief  Executive  Officer

Date:  March  28,  2001

     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 and Director              March 28, 2001
   -------------------------
   Christopher  L.  Dutton      (Principal  Executive  Officer)


 _/s/Nancy R. Brock_______    Vice President, Treasurer and       March 28, 2001
  ---------------------
   Nancy  R.  Brock             Chief  Financial  Officer  (Principal
                              Financial  Officer)


 /s/Robert  J.  Griffin_    Controller                          March  28,  2001
 -----------------------
   Robert  J.  Griffin          (Principal  Accounting  Officer)

     *Thomas  P.  Salmon        Chairman  of  the  Board

     *Nordahl  L.  Brue       )

     *William  H.  Bruett      )

     *Merrill  O.  Burns       )

     *David  R.  Coates         )

     *Lorraine  E.  Chickering   )

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


*By:  _/s/  Christopher  L. Dutton                                March 28, 2001
       ---------------------------
     Christopher  L.  Dutton
     (Attorney  -  in  -  Fact)