SECURITIES AND EXCHANGE COMMISSION

                           Washington, D. C.  20549

                     

                                  FORM 10-K

                  For the fiscal year ended December 31, 1995

                         Commission file number  1-8291

              _X_  Annual Report Pursuant to Section 13 or 15(d)
             of the Securities Exchange Act of 1934 [Fee Required]


             ___  Transition Report Pursuant to Section 13 or 15(d)
           of the Securities Exchange Act of 1934 [No Fee Required]

    For the transition period from ________________ to __________________


                        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)

    25 Green Mountain Drive 
     South Burlington, VT                                05403
_________________________________                      __________
(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 
nonaffiliates of the registrant as of March 15, 1996, was 
$132,671,421.00 based on the closing price 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 15, 1996, 
was 4,868,676.


DOCUMENTS INCORPORATED BY REFERENCE

	The Company's Definitive Proxy Statement relating to its Annual 
Meeting of Stockholders to be held on May 16, 1996, 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.

PART 1

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 an estimated population of 198,000.  It 
serves approximately 81,500 customers.  For the year ended December 31, 
1995, the Company's sources of revenue were derived as follows:  33.6% 
from residential customers, 31.0% from small commercial and industrial 
customers, 19.7% from large commercial and industrial customers, 10.6% 
from sales to other utilities, and 5.1% from other sources.  For the 
same period, the Company's energy resources for retail and requirements 
wholesale sales were obtained as follows:  46.4% from hydroelectric 
sources (5.8% Company-owned, 0.1% New York Power Authority (NYPA), 37.9% 
Hydro-Quebec and 2.6% small power producers), 30.4% from nuclear 
generating sources (the Vermont Yankee plant described below), 10.2% 
from coal sources, 3.3% from wood, 1.5% from natural gas, and 0.7% from 
oil.  The remaining 7.5% was purchased on a short-term basis from other 
utilities and through the New England Power Pool (NEPOOL).  In 1995, the 
Company purchased 92.7% of the energy required to satisfy its retail and 
requirements wholesale sales (including energy purchased from Vermont 
Yankee and under other long-term purchase arrangements).  See Note K of 
Notes to Consolidated Financial Statements.

     A major source of the Company's power supply is its entitlement to 
a share of the power generated by the 535-MW Vermont Yankee nuclear 
generating plant owned and operated by Vermont Yankee Nuclear Power 
Corporation (Vermont Yankee), in which the Company has a 17.9% equity 
interest.  For information concerning Vermont Yankee, see "Power 
Resources - Vermont Yankee."

     The Company participates in NEPOOL, a regional bulk power 
transmission organization established to assure the reliability and 
economic efficiency of power supply in the Northeast.  The Company's 
representative to NEPOOL is the Vermont Electric Power Company, Inc. 
(VELCO), a transmission consortium owned by the Company and other 
Vermont utilities, in which the Company has a 30% equity interest.  As a 
member of NEPOOL, the Company benefits from increased efficiencies of 
centralized economic dispatch, availability of replacement power for 
scheduled and unscheduled outages of its own power sources, sharing of 
bulk transmission facilities and reduced generation reserve 
requirements.

     The principal territory served by the Company comprises 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.  The 
Company also distributes electricity in four noncontiguous areas located 
in southern and southeastern Vermont that are interconnected with the 
Company's principal service area through the transmission lines of 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.  The Company also supplies at 
wholesale a portion of the power requirements of several municipalities 
and cooperatives in Vermont and one utility in another state.  The 
Company is obligated to meet the changing electrical requirements of 
these wholesale customers, in contrast to the Company's obligation to 
other wholesale customers, which is limited to specified amounts of 
capacity and energy established by contract.

     Major business activities in the Company's service areas include 
computer assembly and components manufacturing (and other electronics 
manufacturing), granite fabrication, service enterprises such as 
government, insurance and tourism (particularly winter recreation), and 
dairy and general farming.

     During the years ended December 31, 1995, 1994 and 1993, electric 
energy sales to International Business Machines Corporation (IBM), the 
Company's largest customer, accounted for 12.9%, 13.7% and 13.6%, 
respectively, of the Company's operating revenues in those years.  No 
other retail customer accounted for more than one percent of the 
Company's revenue.  


RECENT RATE DEVELOPMENTS

     On September 26, 1994, the Company filed a request with the Vermont 
Public Service Board (VPSB) to increase retail rates by 13.9%.  The 
increase was needed primarily to cover the rising cost of existing power 
sources, the cost of new power sources the Company has secured to 
replace power supply that will be lost in the near future, and the cost 
of energy efficiency programs the Company has implemented for its 
customers.

     The Company, the Vermont Department of Public Service (Department), 
and the other parties in the proceeding reached a settlement agreement 
providing for a 9.25% retail rate increase effective June 15, 1995, and 
a target return on equity of 11.25%.  The agreement was approved by the 
VPSB on June 9, 1995.

     On September 15, 1995, the Company filed a request with the VPSB to 
increase retail rates by 12.7%.  The increase is needed to cover higher 
power supply costs, to support additional investment in plant and 
equipment, to fund expenses associated with the Pine Street Marsh site, 
and to cover higher costs of capital.

     The Company and the Department reached a settlement agreement 
providing for a 5.25% retail rate increase effective June 1, 1996, and a 
target return on equity for utility operations of 11.25%.  The 
settlement was based on a newly negotiated arrangement with Hydro-Quebec 
that will result in a reduction of the Company's power supply costs 
below that which was anticipated, allowing the Company to reduce the 
amount of its rate request.  The rate settlement must be reviewed and 
approved by the VPSB before it can take effect.


CONSTRUCTION

     The Company's capital requirements result from the need to 
construct facilities or to invest in programs to meet anticipated 
customer demand for electric service.  The policy of the Company is to 
increase diversification of its power supply and other resources through 
various means, including power purchase and sales arrangements, and 
relying on sources that represent relatively small additions to the 
Company's mix to satisfy customer requirements.  This permits the 
Company to meet its financing needs in a flexible, orderly manner.  
Planned expenditures for the next five years will be primarily for 
distribution and conservation projects.

     Capital expenditures over the past three years and forecasted for 
the next five years are as follows:


<TABLE>
<CAPTION>
                                                                          
                                                                               Total Net
          Generation    Transmission    Distribution    Conservation   Other	Expenditures
          ----------    ------------    ------------    ------------   ----- ------------
       (Dollars in thousands and net of AFUDC and Customer Advances For Construction)
Actual
 <S>      <C>              <C>             <C>            <C>          <C>      <C> 
 1993     $1,747           $1,605          $9,093         $8,136       $2,937   $23,518
 1994      2,540            1,415           7,902          6,388        1,815    20,060
 1995      2,696            1,067           8,935          4,152        2,824    19,674
Forecasted
 1996     $9,530*            $569          $8,496         $2,754       $6,601   $27,950
 1997        899              999           8,745          2,444        3,861    16,948
 1998      1,978              999           8,872          2,742        3,591    18,182
 1999      2,478              999           9,084          2,643        4,895    20,099
 2000      2,478              999           9,084          2,543        2,897    18,001

*Includes $8.771 million projected for wind project.

</TABLE>

     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 1993-1995, internally generated funds, after payment 
of dividends, provided approximately 59% of total capital requirements 
for construction, sinking fund obligations and other requirements.  
Internally generated funds provided 58% of such requirements for 1995.  
It is expected that funds so generated will provide approximately 73% of 
such requirements for the period 1996 through 2000, with the remainder 
to be derived through short-term borrowings and the issuance of long-
term debt securities and common and preferred stock.

     In December 1995, the Company sold $24,000,000 of its first 
mortgage bonds in three components -- $8,000,000 at an interest rate of 
6.21% that will mature in 2001, $8,000,000 at an interest rate of 6.29% 
that will mature in 2002, and $8,000,000 at an interest rate of 6.41% 
that will mature in 2003.  A portion of the proceeds of the sale was 
used to reduce short-term bank loans outstanding and the remainder has 
allowed the Company to refund preexisting long-term debt.

     During 1995, the Company took several steps toward enhancing its 
financial flexibility.  The Company filed a shelf registration statement 
with the SEC that allows for the periodic sale to the public of its 
common stock, first mortgage bonds and unsecured notes.  As of December 
31, 1995, $26,000,000 was available under such registration statement.  
Additionally, the Company established medium-term note programs that 
allow for the sale of secured and unsecured debt.

     The Company anticipates issuing approximately $10,000,000 of common 
stock and $10,000,000 of first mortgage bonds in 1996.  The proceeds 
will be used to retire short-term debt and for other corporate purposes.  
The amount and timing of such issuances will depend upon the financial 
condition of the Company, prevailing market conditions and other 
relevant factors.

     In connection with the foregoing, see Management's Financial 
Analysis in Item 7 herein and the material appearing under the caption 
"Power Resources."

<TABLE>
<CAPTION>


OPERATING STATISTICS
For the Years Ended December 31
                                                          1995          1994          1993          1992          1991
                                                       ----------    ----------    ----------    ----------    ----------


<S>                                                        <C>           <C>           <C>           <C>           <C> 
Net System Capability During Peak Month (MW)
  Hydro (1)............................................    152.1         179.0         174.9         160.6         161.3
  Lease transmissions..................................      0.3           2.1           3.9           5.7           5.7
  Nuclear (1)..........................................     81.9         107.2         109.5         109.6          85.0
  Conventional steam...................................     77.8          67.1          92.6          95.0          88.5
  Internal combustion..................................     62.0          60.2          71.0          47.4          52.0
  Combined cycle.......................................     22.0          22.6          22.8          21.6          22.6
                                                       ----------    ----------    ----------    ----------    ----------
    Total capability (MW)..............................    396.1         438.2         474.7         439.9         415.1
  Net system peak......................................    297.1         308.3         307.3         314.4         308.5
                                                       ----------    ----------    ----------    ----------    ----------
  Reserve (MW).........................................     99.0         129.9         167.4         125.5         106.6
                                                       ==========    ==========    ==========    ==========    ==========
  Reserve % of peak....................................     33.3%         42.1%         54.5%         39.9%         34.6%

Net Production (MWH)
  Hydro (1)............................................1,043,617       742,088       751,078       641,525       611,658
  Lease transmissions..................................    --            --           15,425        58,374        67,600
  Nuclear (1)..........................................  682,814       763,690       598,245       665,034       731,582
  Conventional steam...................................  673,982       651,105       748,626       762,451       799,781
  Internal combustion..................................    6,646         3,532         2,849         1,504         3,809
  Combined cycle.......................................   92,723        37,808        40,966        60,138       104,344
                                                       ----------    ----------    ----------    ----------    ----------
    Total production...................................2,499,782     2,198,223     2,157,189     2,189,026     2,318,774
  Less non-requirements sales to other utilities.......  582,942       328,794       271,224       273,087       448,110
                                                       ----------    ----------    ----------    ----------    ----------
  Production for requirements sales....................1,916,840     1,869,429     1,885,965     1,915,939     1,870,664
  Less requirements sales & lease transmissions (MWH)..1,760,830     1,730,497     1,749,454     1,794,986     1,742,308
                                                       ----------    ----------    ----------    ----------    ----------
  Losses and company use (MWH).........................  156,010       138,932       136,511       120,953       128,356
                                                       ==========    ==========    ==========    ==========    ==========
Losses as a percentage of total production.............     6.24%         6.32%         6.33%         5.53%         5.54%
System load factor (2).................................     71.2%         67.7%         68.7%         68.5%         67.9%



Sales and Lease Transmissions (MWH)
  Residential - GMP....................................  549,296       564,635       541,579       505,234       483,998
  Lease transmissons...................................    --            --           15,425        58,374        67,600
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................  549,296       564,635       557,004       563,608       551,598
  Commercial & industrial - small......................  608,688       604,686       593,560       582,594       571,818
  Commercial & industrial - large......................  556,278       521,400       529,372       539,665       519,201
  Other................................................    8,855         1,146         8,868         6,312         2,770
                                                       ----------    ----------    ----------    ----------    ----------
    Total retail sales and lease transmissions.........1,723,117     1,691,867     1,688,804     1,692,179     1,645,387
  Sales to municipals and cooperatives and
    other requirements sales...........................   37,713        38,630        60,650       102,807        96,921
                                                       ----------    ----------    ----------    ----------    ----------
    Total requirements sales...........................1,760,830     1,730,497     1,749,454     1,794,986     1,742,308
  Other sales for resale...............................  582,942       328,794       271,224       273,087       448,110
                                                       ----------    ----------    ----------    ----------    ----------
    Total sales and lease transmissions................2,343,772     2,059,291     2,020,678     2,068,073     2,190,418
                                                       ==========    ==========    ==========    ==========    ==========

Average Number of Electric Customers
  Residential..........................................   69,659        68,811        67,994        67,201        66,406
  Commercial and industrial - small....................   11,712        11,611        11,447        11,245        11,215
  Commercial and industrial - large....................       24            24            25            24            24
  Other................................................       76            76            74            73            71
                                                       ----------    ----------    ----------    ----------    ----------
    Total..............................................   81,471        80,522        79,540        78,543        77,716
                                                       ==========    ==========    ==========    ==========    ==========


Average Revenue per KWH (Cents)
  Residential including lease revenues.................    10.09          9.03          8.94          8.44          8.06
  Lease charges........................................      --            --           0.06          0.41          0.26
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................    10.09          9.03          9.00          8.85          8.32
  Commercial and industrial - small....................     8.42          8.00          7.97          7.82          7.53
  Commercial and industrial - large....................     5.86          6.02          5.96          5.89          5.72
  Total retail including lease revenues................     8.36          7.96          7.86          7.56          7.29


Average Use and Revenue Per Residential Customer
  Kilowatt hours including lease transmissions.........    7,885         8,206         8,192         8,387         8,306
  Revenues including lease revenues....................     $796          $741          $733          $707          $670


(1) See Note K of Notes to Consolidated Financial Statements.
(2) Load factor is based on net system peak and firm MWH 
    production less off-system losses.

</TABLE>


DEMAND-SIDE MANAGEMENT

     The Company develops and implements demand-side management (DSM) 
programs as part of its long-term resource strategy.  These programs are 
aimed at improving the match between customer needs and the Company's 
ability to supply those needs at a reasonable cost.  Energy 
conservation, load management and efficient electric use are central to 
these program efforts and provide the means for controlling operating 
expenses and requirements for additional capital investment.  With more 
efficient electric consumption, the use of existing resources can be 
optimized.  DSM program components, energy conservation, load-management 
and efficient electric use also provide customers with options and 
choices with respect to their use and cost of electric service.  

     In 1994, the Company focused its energy efficiency activities on 
phasing out programs that were no longer cost effective in light of 
reduced electricity market prices.  In 1995, the Company entered into an 
agreement to work with the Department to design new programs and to 
refine other, continuing programs.  During the summer of 1995, the 
Company developed and implemented these program modifications and new 
programs.

     The most innovative of the new programs is targeted for the 
Company's customers in the Mad River Valley of Central Vermont.  A 
growing load there and limited transmission and distribution capacity in 
the area provided an ideal opportunity to direct energy efficiency 
efforts where short-term benefits from avoided transmission and 
distribution costs (as opposed to longer term avoided generation costs) 
are high.  The Company, in the Mad River Valley, also can test the 
ability of energy efficiency programs to reduce local area demand peaks 
in a limited time.  The programs offered in the Mad River Valley include 
a residential retrofit program, a residential new construction 
assessment-fee program, and two commercial and industrial retrofit 
programs, one targeting large customers and the other targeting small 
customers.

     The Company also invested in 1995 in the promotion of efficient, 
environmentally-friendly electro-technologies.  We believe that energy 
efficiency means more than just conservation.  In many cases, efficient 
electrical technologies are the optimum technology.  Most activities 
were centered around heat pumps, which are under-utilized in Vermont.  A 
series of seminars for local building designers, contractors, and 
equipment vendors were held to familiarize them with this technology to 
help invigorate a local infrastructure to support the technology.

     All of the Company's other programs are "lost opportunity" 
programs, in which energy efficient measures are undertaken when cost-
effective and when the failure to install a program would mean that the 
opportunity to do so is, for all practical purposes, lost.  The Company 
provides a comprehensive set of commercial, industrial and residential 
programs that are substantially lower in cost than the retrofit programs 
offered several years ago.  In part because of the shift away from 
retrofit programs, and in part because of a general push for greater 
administrative efficiencies in delivering DSM programs, the Company 
reduced its staff from approximately 25 full time employees to 18.  
Administrative improvements and program design changes have allowed the 
Company to combine, for example, the jobs of program managers of the 
commercial and industrial new construction and equipment replacements 
program into one manager who oversees both programs.



     In 1995, the Company spent approximately $3,700,000 on energy 
efficiency programs, approximately 2.8% of retail revenue.  Efficient 
technologies installed in 1995 saved approximately 9,200 Mwh per year.

     In 1995, the Company began to broaden its range of energy services 
beyond energy-efficiency programs supported by regulated utility 
operations.  Over time, the Company anticipates a gradual but steady 
transition of some energy efficiency services away from regulated 
activities paid for by all customers to more energy efficiency services 
paid for by the customers who use them.


     Rate Design.  The Company seeks to design rates to encourage the 
shifting of electrical use from peak hours.  Since 1976, the Company has 
offered optional time-of-use rates for residential and commercial 
customers.  Currently, approximately 2,500 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 depends on fair pricing to keep customers 
satisfied and to make predictable the customer use of its power supply 
so that it can keep control of its costs.  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.  Approximately 
1,400 of the Company's largest customers, comprising 48% of retail 
revenues, were successfully converted to time-of-use rates.  In May 
1994, the Company filed a new rate design case 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.


     Dispatchable and Interruptible Service Contracts.  In 1995, the 
Company had interruptible/dispatchable power contracts with three major 
ski areas, interruptible only contracts with two customers and 
dispatchable-only contracts with an additional eighteen customers.  The 
interruptible portion of the contracts allow the Company to control 
power supply capacity charges by reducing the Company's capacity 
requirements.  During 1995, the Company did not request any 
interruptions due to the surplus capacity in the region.  The 
dispatchable portion of the contracts allows customers to purchase 
electricity during times designated by the Company when low cost power 
is available at the energy only cost of the rate.  The customers' demand 
during these periods is not considered in calculating the monthly 
billing.  This program provides customers with discretionary use of 
portions of their load the opportunity to maximize their energy value 
and at the same time the Company is able to retain customer load 
requirements that might otherwise be met through alternative means.  
These programs are available by tariff for qualifying customers.


     Ripple Load-Management System.  The Company has operated a remote-
control load-management facility since 1976.  This facility, referred to 
as a "Ripple" system, allows the Company, from a central signaling 
point, to switch off temporarily certain electrical appliances in 
customers' homes that have a storage capacity, such as water heaters and 
thermal storage heaters, thereby eliminating electric loads at discreet 
times.  The Company's present Ripple system consists of approximately 
7,000 installed signal receivers, a central processing station and four 
signal injection stations.  Approximately 25% of the Company's eligible 
customers are participating in this load-control program, which allows 
the Company to reduce system load by four to five MW.


POWER RESOURCES

     The Company generated, purchased or transmitted 1,853,890.7 MWh of 
energy for retail and wholesale customers for the twelve months ended 
December 31, 1995.  The corresponding maximum one-hour integrated demand 
during that period was 297.1 MW on February 6, 1995.  This compares to 
the previous all-time peak of 322.6 MW on December 27, 1989.  The 
following tabulation shows the source of such energy for the twelve-
month period and the capacity in the month of the period system peak.  
See also "Power Resources - Long-Term Power Sales."

                                   Net Generated and      Net Generated and
                                    Purchased Year        Purchased in Month
                                   Ended 12/31/95 (a)      of Annual Peak
                                  ___________________    ___________________
                                     MWh         %          KW          %
WHOLLY OWNED PLANTS
  Hydro                            110,503.1    5.8        35,300       8.9
  Diesel and Gas Turbine             2,445.5    0.1        70,970      17.9

JOINTLY OWNED PLANTS
  Wyman #4                           4,037.1    0.2         7,040       1.8
  Stony Brook I                     12,164.5    0.6         7,590       1.9
  McNeil                             9,051.2    0.5         6,830       1.7

OWNED IN ASSOCIATION W/OTHERS
  Vermont Yankee Nuclear           582,087.7   30.4        81,940      20.7

NYPA LEASE TRANSMISSIONS
  State of Vermont (NYPA)            1,743.6    0.1           250       0.1

LONG-TERM PURCHASES
  Hydro-Quebec                     724,080.2   37.9        99,090      25.0
  Merrimack #2                     194,709.2   10.2        31,220       7.9
  Stony Brook I                     23,613.5    1.2        14,520       3.7
  Small Power Producers            105,038.1    5.5        24,340       6.1

SHORT-TERM PURCHASES               143,063.6    7.5        16,990       4.3
                                 ___________   ____       _______     _____
  Less System Sales Energy         (58,646.6)

  TOTAL                          1,853,890.7  100.00      396,080    100.00
                                 ===========  ======      =======    ======

    NOTE:  (a)  Excludes losses on off-system purchases, totaling 62,553 
MWh.

     Vermont Yankee.  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 535 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 its Power Contract, the 
Company is 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, the 
Company sold to other Vermont utilities 2.735% of its entitlement to the 
output of Vermont Yankee.  Accordingly, those utilities have an 
obligation to the Company to pay 2.735% of Vermont Yankee's operating 
expenses, fuel costs, decommissioning expenses, interest expense and 
return on common equity.  Vermont Yankee has also entered into capital 
funds agreements with its sponsor utilities that expire on December 31, 
2002.  Under its Capital Funds Agreement, the Company is required, 
subject to obtaining necessary regulatory approvals, to provide 20% of 
the capital requirements of Vermont Yankee not obtained from outside 
sources.

     On April 27, 1989, Vermont Yankee applied to the Nuclear Regulatory 
Commission (NRC) for an amendment to its operating license to extend the 
expiration date from December 2007 to March 2012, in order to take 
advantage of current NRC policy to issue operating licenses for a 40-
year term measured from the grant of the operating license.  (Prior NRC 
policy, under which the operating license was issued, called for a term 
of 40 years from the date of the construction permit.)  On August 22, 
1989, the State of Vermont, opposing the license extension, filed a 
request for a hearing and petition for leave to intervene, which 
petition was subsequently granted.  On December 17, 1990, the NRC issued 
an amendment to the operating license extending the expiration date 
until March 21, 2012, based upon a "no significant hazards" finding by 
the NRC Staff and subject to the outcome of the evidentiary hearing on 
the State of Vermont's assertions.  On July 31, 1991, Vermont Yankee 
reached a settlement with the State of Vermont, and the State filed a 
withdrawal of its intervention.  The proceeding was dismissed on 
September 3, 1991.

     During periods when Vermont Yankee is unavailable, the Company 
incurs replacement-power costs in excess of those costs that the Company 
would have incurred for power purchased from Vermont Yankee.  
Replacement power is available to the Company from NEPOOL and through 
special 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 ratemaking 
purposes over the period until the next scheduled outage.  Vermont 
Yankee has adopted an 18-month refueling schedule.  On March 16, 1995, 
Vermont Yankee began a scheduled refueling outage which ended May 3, 
1995.  Vermont Yankee's next scheduled refueling is August 1996.  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 decommissioning is 
approximately $347,000,000, of which $141,000,000 has been funded.  At 
December 31, 1995, the Company's portion of the net unfunded liability 
was $36,000,000, 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% of capital 
requirements not obtained by outside sources. 


During 1995, the Company incurred $27,700,000 in Vermont Yankee annual 
capacity charges, which included $1,800,000 for interest charges.  The 
Company's share of Vermont Yankee's long-term debt at December 31, 1995 
was $13,100,000.

     Vermont Yankee incurred capital expenditures of approximately 
$2,191,000 in 1995, $2,086,000 in 1994 and $7,229,000 in 1993.  Vermont 
Yankee estimates capital expenditures amounting to approximately 
$13,691,000 for 1996.

     During the year ended December 31, 1995, the Company utilized 
582,087.7 MWh of Vermont Yankee energy to meet 30.4% of its retail and 
requirements wholesale sales.  The average cost of electricity produced 
by the plant in 1995 was 4.7  per KWh.  In 1995, Vermont Yankee had an 
annual capacity factor of 85.0%, compared to 96.1% in 1994 and 76.9% in 
1993.  

     The Price-Anderson Act currently limits public liability from a 
single incident at a nuclear power plant to $8,900,000,000.  Any 
liability beyond $8,900,000,000 is indemnified under an agreement with 
the NRC, but subject to Congressional approval.  The first $200,000,000 
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 $8,700,000,000 per incident by 
assessing retrospective premiums of $79,300,000 against each of the 110 
reactor units in the United States that are currently subject to the 
Program, limited to a maximum assessment of $10,000,000 per incident per 
nuclear unit in any one year.  The maximum assessment is to be adjusted 
at least every five years to reflect inflationary changes.

     The above insurance covers all workers employed at nuclear 
facilities prior to January 1, 1988, for bodily injury claims.  Vermont 
Yankee has purchased a master worker insurance policy with limits of 
$200,000,000 with one automatic reinstatement of policy limits to cover 
workers employed on or after January 1, 1988.  Vermont Yankee's 
estimated contingent liability for a retrospective premium on the master 
worker policy as of December 1995 is $3,100,000.  The secondary 
financial protection program referenced above provides coverage in 
excess of the Master Worker policy.

     Insurance has been purchased from Nuclear Electric Insurance 
Limited (NEIL II and NEIL III) to cover the costs of property damage, 
decontamination or premature decommissioning resulting from a nuclear 
incident.  All companies insured with NEIL II and III are subject to 
retroactive assessments if losses exceed the accumulated funds 
available.  The maximum potential assessment against Vermont Yankee with 
respect to NEIL II losses arising during the current policy year is 
$14,000,000 and the NEIL III maximum retroactive assessment is 
$7,000,000.  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.


     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 200-MW AC-to-DC-to-AC converter 
terminal and seven miles of 345-kV transmission line.  VELCO built and 
operates the converter facilities, which are jointly owned by a number 
of Vermont utilities, including the Company.  On February 11, 1995, the 
transmission facilities maximum capability was upgraded from 200 MW to 
225 MW.


     NEPOOL/Hydro-Quebec Interconnection.  VELCO and certain other 
NEPOOL members have entered into agreements with Hydro-Quebec providing 
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% 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 a cost below that of the 
replacement cost of power and energy otherwise available to the New 
England participants; 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 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.  Vermont 
Electric Transmission Company, Inc. (VETCO), a wholly owned subsidiary 
of VELCO, 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, as 
well as a proportionate share of the total costs of service associated 
with those portions of the transmission facilities to be 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 expands 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, 1995, the 
present value of the Company's obligation was $9,800,000.  The Company's 
projected future minimum payments under the Phase II support agreements 
are $488,924 for each of the years 1996-2000 and an aggregate of 
$7,333,867 for the years 2001-2020.  

     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, 1995, the capital structure 
of such corporations was 38% common equity and 62% long-term debt.


     Hydro-Quebec Power Supply Contracts.  Under various contracts 
approved by the VPSB, 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.

<TABLE>
<CAPTION>

                                 July 1984               December 1987 Contract
                                  Contract      Schedule A    Schedule B    Schedule C3
                                 __________     __________    __________    ___________
                                                        (Dollars in thousands)

<S>                              <C>            <C>           <C>            <C>  
Capacity Acquired                  50 MW          17 MW         68 MW          46 MW

Contact Period                   1985-1995      1990-1995     1995-2015      1995-2015

Minimum Energy Purchase             50%            50%           75%            75%
 (annual load factor)

Annual Energy Charge              $3,091         $1,798        $2,468          $1,317
                                  (1995)         (1995)        (1995)          (1995)
                                                              $14,967         $10,324
                                                            (1996-2015)*    (1996-2015)*

Annual Capacity Charge            $2,367         $1,195        $3,482           $821
                                  (1995)         (1995)        (1995)          (1995)
                                                              $16,731         $10,484
                                                            (1996-2015)*    (1996-2015)*

Average Cost per KWH               3.0            5.5           5.9             4.0 
                                  (1995)         (1995)        (1995)          (1995)
                                                                6.7             6.1 
                                                            (1996-2015)**   (1996-2015)**
* Estimated average
** Estimated average in nominal dollars, levelized over the period 
indicated.

</TABLE>

     The Company's purchases pursuant to the contract with Hydro-Quebec 
entered into December 4, 1987, are as follows: (1) Schedule A -- 17 MW 
of firm capacity and associated energy to be delivered at the Highgate 
interconnection for five years beginning 1990; (2) Schedule B -- 68 MW 
of firm capacity and associated energy to be delivered at the Highgate 
interconnection for twenty years beginning in September 1995; and (3) 
Schedule C3 -- 46 MW of firm capacity and associated energy to be 
delivered at interconnections to be determined at a later time for 20 
years beginning in November 1995.

     At present, the Schedule C3 purchases are being delivered over the 
Company's entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase 
I and Phase II).  By use of the interconnection for Schedule C3 or other 
power transactions, the Company foregoes certain savings associated with 
other power deliveries for NEPOOL that would take place if the 
interconnection were not utilized for firm purchases. (Please also see 
description of the 1996 arrangement described below).

     In September 1994, the Company negotiated a renewal of a short-term 
"tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec 
delivers up to 61 MW of capacity and energy to the Company over the 
NEPOOL/Hydro-Quebec interconnection.  The electricity purchased under 
this tertiary contract is priced at less than 2.5  per KWh.  The 
benefits realized by the Company from this favorably priced electricity 
will be greater than those associated with deliveries foregone by the 
Company otherwise available over the NEPOOL/Hydro-Quebec 
interconnection.  The most recent tertiary energy contract will expire 
in August 1996.  The Company anticipates that purchases of tertiary 
energy will extend beyond August 1996, but these purchases will be 
subject to the availability of the Hydro-Quebec/New England 
interconnection.

     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, the Company is obligated to 
purchase $3,000,000 (in 1994 dollars) worth of research and development 
work from Hydro-Quebec over the four-year period, and made a $7,500,000 
(in 1994 dollars) cash payment to Hydro-Quebec in 1995.  The Company has 
exercised an option to purchase $1,000,000 worth of additional research 
and development work and the $7,500,000 cash payment was reduced 
accordingly.  Hydro-Quebec retains the right to curtail annual energy 
deliveries by 10% up to five times, over the 2000 to 2015 period, if 
documented drought conditions exist in Quebec.

     During the first year of the July 1994 Agreement (the period from 
November 1995 through October 1996), the average cost per KWh of 
Schedules B and C3 combined will be cut from 6.4  to 4.2  per KWh, a 34% 
(or $16,000,000) cost reduction.  Over the four-year period covered by 
the arrangement, combined unit costs will be lowered from 6.4  to 5.3  
per KWh, reducing unit costs by 18% and saving $34,100,000 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.

     Under an arrangement negotiated in January 1996, Hydro-Quebec will 
provide cash payments to the Company of $3,000,000 in 1996 and 
$1,100,000 in 1997.  In response, the Company will shift up to 40 
megawatts of the Schedule C3 deliveries to an alternate transmission 
path, and use the associated portion of the NEPOOL/Hydro-Quebec 
interconnection facilities to purchase power for the period of September 
1996 through June 2001 at prices that vary based upon conditions in 
effect when the purchases are made.  The 1996 arrangement also provides 
for minimum payments by the Company to Hydro-Quebec, for periods in 
which power is not purchased under the agreement.  Although the level of 
benefits to the Company will depend on various factors, the Company 
estimates that the 1996 arrangement will provide a minimum benefit of 
$1,800,000, net present value.

    In 1995, the Company utilized 190,779.7 MWh of Hydro-Quebec energy 
under the July 1984 contract, 52,816.4 MWh under the December 1987 
contract Schedule A, 99,017.5 Mwh under Schedule B, 49,036.0 Mwh under 
Schedule C3, and 332,430.6 MWh under the tertiary energy contract to 
meet 37.9% of its retail and requirements wholesale sales.  The average 
cost of Hydro-Quebec electricity in 1995 was 3.8  per KWh.  See Notes J 
and K-2 of Notes to Consolidated Financial Statements.


     New York Power Authority (NYPA).  The Department allocates NYPA 
power to the Company who, in turn, delivers the power to its residential 
and farm customers.  The Company purchased at wholesale 1,743.6 MWh to 
meet 0.1% of its retail and requirements wholesale sales of NYPA power 
at an average cost of 1.1  per KWh in 1995.  Under the allocation 
currently made by NYPA of NYPA power to states neighboring New York, the 
amount of such power delivered to residential and farm customers in the 
Company's service territory will be as follows:

                                    Entitlements to Customers
                                         in the Company's
               Period                Service Territory (MW)
               ------               -------------------------

         July 1995 - June 1996                 0.3
         July 1996 - June 1997                 0.3
         July 1997 - June 1998                 0.3


     Merrimack Unit #2.  Merrimack Unit #2 is a coal-fired steam plant 
of 356-MW capacity located in Bow, New Hampshire, and owned by Northeast 
Utilities.  The Company is entitled to 30.457 MW of capacity and related 
energy from the unit under a 30-year contract terminating May 1, 1998.  
During the year ended December 31, 1995, the Company utilized 
194,709.2 MWh from the unit to meet 10.2% of its total retail and 
requirements wholesale sales.  The average cost of electricity from this 
unit was 3.0  per KWh in 1995.  See Note K-1 of Notes to Consolidated 
Financial Statements.


     Stony Brook I.  The Massachusetts Municipal Wholesale Electric 
Company (MMWEC) is principal owner and operator of a 343.0-MW combined-
cycle intermediate generating station -- Stony Brook I -- located in 
Ludlow, Massachusetts, which commenced commercial operation in November 
1981.  The Company entered into a Joint Ownership Agreement with MMWEC 
dated as of October 1, 1977, whereby the Company acquired an 8.8% 
ownership share of the plant, entitling the Company to 30.2 MW of 
capacity.  In addition to this entitlement, the Company has contracted 
for 13.8 MW of capacity for the life of the Stony Brook I plant, for 
which it 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 primarily oil-fired.  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 1995, the Company utilized 35,778.0 MWh from this plant to 
meet 1.8% of its retail and requirements wholesale sales at an average 
cost of 5.4  per Kwh, the portion of these costs attributable to the 
30.2 MW joint ownership share are based only on operation, maintenance, 
and fuel costs incurred in 1995.  See Note I-3 and K-1 of Notes to 
Consolidated Financial Statements.


     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 619 MW.  
The construction of this plant was sponsored by Central Maine Power 
Company.  The Company has a joint-ownership share of 1.1% (7.1 MW) in 
the Wyman #4 unit, which began commercial operation in December 1978.

     During 1995, the Company utilized 4,037.1 MWh from this unit to 
meet 0.2% of its retail and requirements wholesale sales at an average 
cost of 4.4  per Kwh, based only on operation, maintenance, and fuel 
costs incurred during 1995.  See Note I-3 of Notes to Consolidated 
Financial Statements.


     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 53.6 MW.  The Company has an 11% or 5.9 MW interest in the 
J. C. McNeil plant, which began operation in June 1984.  During 1995, 
the Company utilized 9,051.2 MWh from this unit to meet 0.5% of its 
retail and requirements wholesale sales at an average cost of 4.6  per 
Kwh, based only on operation, maintenance, and fuel costs incurred 
during 1995.  In 1989, the plant added the capability to burn natural 
gas on an as-available/interruptible service basis.  See Note I-3 of 
Notes to Consolidated Financial Statements.

     Small Power Production.  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 which is based upon the 
projected Vermont composite system's power costs which would be required 
but for the purchases from small producers.  The state purchasing agent 
assigns the energy so purchased, and the costs of purchase, to each 
Vermont retail electric utility based upon its pro rata share of total 
Vermont retail energy sales.  Utilities may also contract directly with 
producers.  The rules provide that all reasonable costs incurred by a 
utility under the rules will be included in the utilities' revenue 
requirements for ratemaking purposes.

     Currently, the state purchasing agent, Vermont Power Exchange, Inc. 
(VPEX), is authorized to seek 150 MW of power from qualifying facilities 
under PURPA, of which the Company's current pro rata share would be 
approximately 32.4% or 48.7 MW.

     The rated capacity of the qualifying facilities currently selling 
power to VPEX is approximately 74 MW.  These facilities were all online 
by the spring of 1993, and no other projects are under development.  The 
Company does not expect any new projects to come online in the 
foreseeable future because the excess capacity in the region has 
eliminated the need and value for additional qualifying facilities.

     The Company and some utilities and producers have formed Vermont 
Electric Power Producers, Inc. (VEPPI) to be the purchasing agent for 
electricity produced by qualifying facilities in Vermont.  VEPPI and 
three other entities have sought VPSB approval to succeed VPEX.  In late 
1995, the VPSB's Hearing Examiner recommended that VEPPI be selected to 
perform this function for a five-year term that will begin in 1996.  The 
VPSB has accepted this recommendation.  The Company estimates that 
purchasing agent operations under VEPPI will save the Company about 
$70,000 per year.

     In 1995, the Company, through both its direct contracts and the 
Vermont Power Exchange, purchased 105,038.1 MWh of qualifying facilities 
production to meet 5.5% of its retail and requirements wholesale sales 
at an average cost of 10.4  per KWh.


     Short-Term Opportunity Purchases and Sales.  The Company has made 
arrangements with several utilities in New England and New York whereby 
the Company may make purchases or sales of utility system 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 from another utility for less than it would cost the 
Company to generate the power with its own sources.  Purchases also help 
the Company save on replacement-power costs during an outage of one of 
its base load sources.  Opportunity sales are arranged when the Company 
has 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.  The price is set so as to recover the forecasted fuel and 
capacity costs.

     During 1995, the Company purchased 143,063.6 MWh, 7.5% of the 
Company's retail and requirements wholesale sales, at an average cost of 
2.4  per KWh under such arrangements.


     NEPOOL.  As a participant of NEPOOL, through VELCO, the Company 
takes advantage of pool operations with central economic dispatch of 
participants' generating plants, pooling of transmission facilities and 
economy and emergency exchange of energy and capacity.  The NEPOOL 
agreement also imposes obligations on the Company to maintain a 
generating capacity reserve as set by the Pool, but which is lower than 
the reserve which would be required if the Company were not a Pool 
participant.


     Company Hydroelectric Power.  The Company wholly owns and operates 
eight hydroelectric generating facilities, the largest of which has a 
generating output of 8.8 MW, located on river systems within its service 
area.  In 1995, these plants provided 110,503.1 MWh of low-cost energy, 
meeting 5.8% of the Company's retail and requirements wholesale sales at 
an average cost of 0.7  per Kwh, based only on operation, maintenance, 
and fuel costs incurred in 1995.  See "State and Federal Regulation."


     VELCO.  The Company, together with six other Vermont electric 
distribution utilities, owns 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 Consolidated 
Financial Statements.


     Long-Term Power Sales.  The Company has entered into agreements for 
a unit sale of power to Fitchburg Gas and Electric Light Company of 
10 MW of Vermont Yankee capacity and associated energy from September 1, 
1990 through October 31, 1996. 

     In 1986, the Company entered into an agreement for the sale to 
UNITIL of 23 MW of capacity produced by the Stony Brook I combined-cycle 
plant for a 12-year period commencing October 1, 1986.  The agreement 
provides for the recovery by the Company of all costs associated with 
the capacity and energy sold.


     Fuel.  During 1995, the Company's retail and requirements wholesale 
sales were provided by the following fuel sources:  46.4% from hydro 
(5.8% Company-owned, 0.1% NYPA, 37.9% Hydro-Quebec and 2.6% small power 
producers), 30.4% from nuclear, 10.2% from coal, 3.3% from wood, 1.5% 
from natural gas, and 0.7% from oil.  The remaining 7.5% was purchased 
on a short-term basis from other utilities and through NEPOOL.

     Vermont Yankee has approximately $133,000,000 of "requirements 
based" purchase contracts for nuclear fuel needs to meet substantially 
all of its power production requirements through 2002.  Under these 
contracts, any disruption of operating activity would allow Vermont 
Yankee to cancel or postpone deliveries until actually needed.

     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 DOE contract obligates Vermont Yankee to pay a one-time fee of 
approximately $39,300,000 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 1995, Vermont Yankee accumulated 
approximately $66,000,000 in an irrevocable trust to be used exclusively 
for defeasing this obligation at some future date, provided the DOE 
complies with the terms of the aforementioned contract.

     The Company does not maintain long-term contracts for the supply of 
oil for the oil-fired peaking unit generating stations wholly owned by 
it (80 MW).  The Company did not experience difficulty in obtaining oil 
for its own units during 1995, and, while no assurance can be given, 
does not anticipate any such difficulty during 1996.  None of the 
utilities from which the Company expects to purchase oil- or gas-fired 
capacity in 1996 has advised the Company of grounds for doubt about 
maintenance of secure sources of oil and gas during the year.

     Coal for Merrimack #2 is presently being purchased by under a long-
term contract from Balley Mine in western Pennsylvania and occasionally 
on the spot market from northern West Virginia and southern Pennsylvania 
sources.  The sponsor of Merrimack advises that, as of March 11, 1996, 
there were 154,000 tons of coal at the plant.

     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 
196,626 tons of wood chips and mill residue and 130,703,000 cubic feet 
of gas in 1995.  The McNeil plant is forecasting consumption of wood 
chips for 1996 to be 150,000 tons and gas consumption of 300,000,000 
cubic feet.  Burlington Electric Department advises that, as of February 
24, 1996, there were 17,550 tons of wood chips in inventory for the 
McNeil plant.

     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.  The Company assumes 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.


FUTURE POWER RESOURCES

Wind Project
     The Company's 20 years of research and development work in wind 
generation was recognized in 1993 when the Company was selected by the 
United States Department of Energy (DOE) and the Electric Power Research 
Institute (EPRI) to build a commercial scale wind-powered facility.  The 
Company was awarded $3,500,000 by the DOE and EPRI, to provide partial 
funding for the wind project.  The overall cost of the project, which 
will be located in the southern Vermont towns of Searsburg and 
Readsboro, is estimated to be $10,100,000.  The Company estimates that 
it will spend approximately $8,700,000 on this project in 1996.  The new 
wind facility will consist of eleven wind turbines and will generate 6 
MW of electricity.

     In May 1995, the Company filed an application with the VPSB seeking 
a Certificate of Public Good for the wind project.  In late January 
1996, a hearing officer for the VPSB recommended  that the Company be 
awarded the Certificate of Public Good to allow the Company to construct 
its proposed wind facility in Searsburg.  The Company hopes to begin 
construction in the spring of 1996 and to have the facility in operation 
by year end.

     The Company has selected Zond Development Corporation of Tehachapi, 
California, to supply the wind turbines.  Zond will install eleven 550 
kilowatt wind turbines (model Z-40) at the Searsburg site.  The wind 
turbines were developed by Zond in conjunction with the DOE Value 
Engineered Turbine project.  The Z-40 currently is the largest wind 
turbine commercially produced in the United States.

     The Company is a utility leader in wind power research.  The 
Company's extensive wind resource database shows that wind power is 
technically feasible and is becoming economically viable at other sites 
within Vermont.  Several years of wind turbine operation at Mt. Equinox, 
Vermont, has provided the Company with valuable knowledge about the 
effects of icing and extreme cold on the performance of wind turbines, 
and the necessary adaptations for these conditions.

     The Searsburg wind project affords an opportunity to employ 
turbines that are of an advanced design and larger scale than the Mt. 
Equinox turbines.  The economies of scale and advanced technology 
inherent in these turbines offers a more competitive and reliable source 
of power than earlier designs.  First-hand knowledge about these 
turbines in Vermont's climatic conditions will enable the Company to 
make intelligent and timely decisions about this power resource, which 
can be installed in increments that closely match the need for power.  
Furthermore, the project's size and northerly location will boost the 
commercialization of wind power by deploying a new model of turbines in 
sufficient quantities to obtain statistically valid operations and 
maintenance data, which will be shared with utilities.  Finally, 
information related to the siting, permitting, and possible impacts on 
the natural environment will also be documented and shared with the 
industry and the public.

     The Company estimates that the wind project will cause rates to 
rise less than one-half of 1 percent in the first several years of the 
project.  Early in the next century, however, the Company projects that 
electricity from wind energy will cost less than comparable  power from 
other sources.  Over the life of the project, the average cost of 
electricity from the wind farm, which provides electricity at times of 
peak demand for the Company, is expected to be competitive with the cost 
of alternatives in the market.


STATE AND FEDERAL REGULATION

     General.  The Company is subject to the regulatory authority of the 
VPSB, which extends to retail rates, services, facilities, securities 
issues and various other matters.  The separate Vermont Department of 
Public Service, created by statute in 1981, is responsible for 
development of energy supply plans for the State, purchases of power as 
an agent for the State and other general regulatory matters.  The VPSB 
is principally responsible for quasi-judicial proceedings, such as rate 
proceedings.  The Department, through a Director for Public Advocacy, is 
entitled to participate as a litigant in such proceedings and regularly 
does so.

     Vermont law pertaining to rate proceedings of the Company provides 
that the rates as filed become final and effective seven months after 
suspension of the filed rates (which can occur within 45 days of filing) 
if the VPSB fails to act on the permanent rate request by that time.  
Once filed, a request for permanent rate relief may not be amended or 
supplemented except upon approval of the VPSB after hearing.  The VPSB 
must consider an application for and, in appropriate circumstances, 
order temporary rate relief pending a decision.  If the VPSB fails to 
act on an application for temporary rate relief within 30 days, or 
within 45 days after suspension of the permanent rate request, the 
temporary rates take effect.  If temporary relief is ordered, revenues 
recovered are subject to refund.

     The Company's rate tariffs are uniform throughout its service area.  
The Company has entered into two economic development agreements, 
providing for reduced charges to large customers to be applied only to 
new load.  A third economic development agreement with IBM is part of 
the rate settlement currently before the VPSB referenced above.

     The Company's wholesale rate on sales to four wholesale customers 
is regulated by the FERC.  Revenues from sales to these customers were 
approximately 0.9% of operating revenues for 1995.

     Late in 1989, the Company began serving a municipal utility, 
Northfield Electric Department, under its wholesale tariff.  This 
customer increased the Company's electricity sales by approximately 
22,777 MWh and peak requirements by approximately 6 MW.  Revenues in 
1995 from Northfield were $1,263,265.

     The Company provides transmission service to twelve customers 
within the State under rates regulated by the FERC; revenues for such 
services amounted to less than 1% of the Company's operating revenues 
for 1995.

     By reason of its relationship with Vermont Yankee, VELCO and VETCO, 
the Company has filed an exemption statement under Section 3(a)(2) of 
the Public Utility Holding Company Act, thereby securing exemption from 
the provisions of such Act, except for Section 9(a)(2) thereof (which 
prohibits the acquisition of securities of certain other utility 
companies without approval of the Securities and Exchange Commission).  
The Securities and Exchange Commission 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 projects:

Project             Issue Date                     Period
-------             ----------                     ------

Bolton             February 5, 1982      February 5, 1982 - February 4, 2022

Essex              March 30, 1995        March 1, 1995 - March 1, 2025

Vergennes          June 29, 1979         June 1, 1949 - May 31, 1999

Waterbury          July 20, 1954         September 1, 1951 - August 31, 2001

     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, the Vergennes and the Waterbury projects, the amounts 
appropriated are not material.  


     Department of Public Service Twenty-Year Power Plan.  In December 
1994, the Department adopted an update of its twenty-year electrical 
power-supply plan (the Plan) for the State of Vermont.  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.

     The Company's Integrated Resource Plan was published in June 1995.  
It was developed in a manner consistent with the Department's Plan.  The 
1995 Integrated Resource Plan calls for a greater emphasis on 
distributed utility approaches that can best use the Company's assets, 
maximize the benefit of demand-side management programs, and provide 
customers with the highest quality service.


ENVIRONMENTAL MATTERS

     In recent years, public concern for the physical environment has 
brought about increased government regulation of the licensing and 
operation of electric generation, transmission and distribution 
facilities.  The Company must meet various land, water, air and 
aesthetic requirements as administered by local, state and federal 
regulatory agencies.  Subject to the results of developments discussed 
below concerning the Pine Street Marsh site in Burlington, Vermont, the 
Company believes that it is in substantial compliance with such 
requirements, and no material complaints concerning compliance by the 
Company with present environmental protection regulations are 
outstanding.  Because the regulations and requirements under existing 
legislation have not been fully promulgated (and, when promulgated, are 
subject to revision), because permits and licenses when issued may be 
conditional or may be subject to renewal and because additional 
legislation may be adopted in the future, the Company cannot presently 
forecast the costs or other effects which environmental regulation may 
ultimately have upon its existing and proposed facilities and 
operations.

     In 1982, the United States Environmental Protection Agency (EPA) 
notified the Company that the EPA, pursuant to the Comprehensive 
Environmental Response, Compensation and Liability Act of 1980 (CERCLA), 
was considering spending public funds to investigate and take corrective 
action involving claimed releases of allegedly hazardous substances at a 
site identified as the Pine Street Marsh in Burlington, Vermont.  On 
part of this site was located a manufactured-gas facility owned and 
operated by a number of separate enterprises, including the Company, 
from the late 19th century to 1967.  In its notice, the EPA stated that 
the Company may be a "potentially responsible party" (PRP) under CERCLA 
from which reimbursement of costs of investigation and of corrective 
action may be sought.  On February 23, 1988, the Company received a 
Special Notice letter from the EPA stating that the letter constituted a 
formal demand for reimbursement of costs, including interest thereon, 
that were incurred and were expected to be incurred in response to the 
environmental problems at the site.

     On December 5, 1988, the EPA brought suit against the Company, New 
England Electric System, and Vermont Gas Systems, Inc. in the United 
States District Court for the District of Vermont seeking reimbursement 
for costs it incurred in conducting activities in 1985 to remove 
allegedly hazardous substances from the site, and requested a 
declaratory judgment that the Company and the other defendants are 
liable for all costs that have been incurred since the removal and that 
continue to be incurred in responding to claims of releases or 
threatened releases from the Maltex Pond Area -- the portion of the site 
where the removal action occurred.  The complaint specifically alleged 
that the EPA expended at least $741,000 during the 1985 removal action 
and sought interest on this amount from the date the funds were expended 
and costs of litigation, including attorneys' fees.  The Company entered 
a cross-claim against New England Electric System and third-party claims 
against UGI Corporation, Southern Union Corporation, the State of 
Vermont, and an individual property owner at the site for recovery of 
its response costs and for contribution.  Fourth-party defendants 
subsequently were joined.

     In July 1990, the Company and other parties signed a proposed 
Consent Decree settling the removal action litigation.  All 14 settling 
defendants contributed to the aggregate settlement amount of $945,000.  
Individual contributions were treated as confidential under the proposed 
Consent Decree.  On December 26, 1990, upon the unopposed motion of the 
United States, the Consent Decree was entered by the Court.

     During the summer and fall of 1989, the EPA conducted the initial 
phase of the Remedial Investigation (RI) and commenced the Feasibility 
Study (FS) relating to the site.  In the fall of 1990 and in 1991, the 
EPA conducted a second phase of RI work and studied the treatability of 
soils and groundwater at the site.  In the fall of 1991, the EPA 
responded favorably to a request from the Company and other PRPs to 
participate in informal discussions on the EPA's ongoing investigation 
and evaluation of the site, and invited the Company and other interested 
parties to share technical information and resources with the EPA that 
might assist it in evaluating remedial options.

     On November 6, 1992, the EPA released its final RI/FS and announced 
a proposed remedy with an estimated present value total cost of 
approximately $47,000,000.  This amount included 30 years' estimated 
operation and maintenance costs, with a net present value of 
approximately $26,400,000.  The EPA's preferred remedy called for 
construction of a Containment/Disposal Facility (CDF) over a portion of 
the site.  The CDF would have consisted of subsurface vertical barriers 
and a low permeability cap, with collection trenches and hydraulic 
control system to capture groundwater and prevent its migration outside 
of the CDF.  Collected groundwater would have been treated and 
discharged or stored and disposed of off-site.  The proposed remedy also 
would have required construction of new wetlands to replace those that 
would be destroyed by construction of the CDF and a long-term monitoring 
program.

     On or before May 15, 1993, the PRP group in which the Company 
participated submitted extensive comments to the EPA opposing the 
proposed remedy.  In response to an earlier request from the EPA, the 
PRP group also submitted a detailed analysis of an alternative remedy 
anticipated to cost approximately $20,000,000.  In early June, in 
response to overwhelming negative comment, the EPA withdrew its proposed 
remedy and announced that it would work with all interested parties in 
developing a new proposal.  Since then, the EPA has established a 
coordinating council, with representatives of PRPs, environmental 
groups, and government agencies, and presided over by a neutral 
facilitator.  The council is charged with determining what additional 
studies may be appropriate for the site and also is planning to 
eventually address additional response activities.

     In July 1994, the Company, New England Electric System (NEES), and 
Vermont Gas Systems, Inc. (VGS), entered into an Administrative Order by 
Consent, with the EPA, pursuant to which these PRPs are conducting 
certain additional studies that have been agreed to by the coordinating 
council.  These studies constitute the first phase of action the council 
has decided on to fill data gaps at the site.  A second phase, including 
tasks carried over from the first phase, additional field studies and 
preparation of an addendum feasibility study was begun during 1995 by 
the same parties under a second Order.  The EPA has not required 
reimbursement for its past RI/FS study costs as a condition to allowing 
the PRPs to conduct these additional studies.  The EPA has previously 
advised the Company that ultimately it will seek to hold the Company and 
the PRPs liable for such costs.  These costs have been estimated to be 
at least $4,500,000, but the Company has sufficient reserves on its 
balance sheet to cover such costs.

     On December 1, 1994, the Company, NEES and VGS entered into a 
confidential agreement with the State, the City of Burlington and nearly 
all other landowner PRPs under which the liability of those landowner 
PRPs for future Superfund response costs would be limited and specified.  
On December 1, 1994, the Company entered into a confidential agreement 
with VGS compromising contribution and cost recovery claims of each 
party and contractual indemnity claims of the Company arising from the 
1964 sale of the manufactured gas plant to VGS, and also entered into a 
confidential agreement with NEES for funding of work under the Order.

     In December 1991, the Company brought suit against several previous 
insurers seeking recovery of unrecovered past costs and indemnity 
against future liabilities associated with environmental problems at the 
site.  Discovery in the case is largely complete, with the exception of 
expert discovery, which was stayed by the magistrate pending the 
resolution of Summary Judgment Motions filed by the Company.  In August 
1994, the Magistrate granted the Company's Motion for Summary Judgment 
with respect to defense costs against one defendant and denied it 
against another defendant.  The United States District Judge affirmed 
those orders on September 30, 1994.

     The Company has reached confidential settlements with two of the 
defendants in its insurance litigation.  One of these defendants 
provided the Company with comprehensive general liability insurance 
between 1976 and 1982, and with environmental impairment liability 
insurance from 1981 to 1984.  These policies were in place in 1982 when 
the EPA first notified the Company that it might be a potentially 
responsible party at the Pine Street Marsh site.  The other defendant 
provided the Company with second layer excess liability coverage for a 
seven-month period in 1976.

     The Company has deferred amounts received from third parties 
pending resolution of the Company's ultimate liability with respect to 
the site and rate recognition of that liability.  The Company is unable 
to predict at this time the magnitude of any liability resulting from 
potential claims for the costs of the RI/FS or the performance of any 
remedial action, or the likely disposition or magnitude of claims the 
Company may have against others, including its insurers, except to the 
extent described above.

     Through rate cases filed in 1991, 1993 and 1994, the Company has 
sought and received recovery for ongoing expenses associated with the 
Pine Street Marsh site.  Specifically, the Company proposed rate 
recognition of its unrecovered expenditures between January 1991 and 
June 30, 1994 (in the total of approximately $7,300,000) for technical 
consultants and legal assistance in connection with the EPA's 
enforcement actions at the site and insurance litigation.  While 
reserving the right to argue in the future about the appropriateness of 
rate recovery for Pine Street Marsh related costs, the Company and the 
Vermont Department of Public Service (the Department) reached
agreements in these cases that the full amount of Pine Street Marsh 
costs reflected in those rate cases should be recovered in rates.  The 
Company's rates approved by the VPSB on April 2, 1992, on May 13, 1994, 
and on June 5, 1995, reflected the Pine Street Marsh related 
expenditures referred to above.

     In a rate case filed on September 15, 1995, the Company sought 
recovery in rates of approximately $1,300,000 in expenses associated 
with the Pine Street site.  This amount represented the Company's 
unrecovered expenditures between July 1994 and June 1995 for technical 
consultants and legal assistance in connection with EPA's enforcement 
action at the site and insurance litigation.  While reserving the right 
to argue in the future about the appropriateness of rate recovery for 
Pine Street related costs (and whether recovery or non-recovery of past 
costs and any insurance proceeds is relevant to such issue), the parties 
to the case have reached agreement that the full amount of Pine Street 
costs reflected in the Company's 1995 rate case should be recovered in 
rates.  This agreement is currently pending before the VPSB.

     Management expects to seek and (assuming treatment consistent with 
the previous regulatory treatment set forth above) receive ratemaking 
treatment for unreimbursed costs incurred beyond the amounts for which 
ratemaking treatment has been received.


COMPETITION

     The Company serves a fixed area of Vermont under a VPSB franchise.  
Except as noted below, the Company's electric business is substantially 
free from competition for retail customers from other electric 
utilities, municipalities and other public agencies in its franchise 
area, as mandated by the VPSB.  The Company, however, competes with 
other providers of energy for the home-heating market.  Wood stoves, 
oil-burning furnaces and natural gas represent the principal 
alternatives to electric heat for customers in the Company's service 
territory.  Fluctuations in the price of fossil fuels, especially oil 
and natural gas, affect the Company's position in the home-heating 
market.

     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.

     Regulatory and legislative authorities at the federal level and 
among states across the country, including Vermont, are considering how 
to facilitate competition for electricity sales at the wholesale and 
retail levels.  On October 24, 1994, the VPSB and the Department 
convened a "Roundtable on Competition and the Electric Industry," 
consisting of representatives of utilities (including the Company), 
customers, environmental groups and other affected parties.  On July 17, 
1995, a subgroup of the Roundtable agreed on a set of fourteen 
principles intended to guide the debate in Vermont concerning 
competition.  These principles, among other things, call for exploration 
of the potential for retail competition, honoring of past utility 
commitments incurred under regulation, protection for low income 
customers, and continued exploration of renewable resources, energy 
efficiency and environmental protections.

     On September 14, 1995, Governor Dean of Vermont announced his 
desire to provide for competition and a restructuring of the utility 
industry.  The Governor's announcement included proposed legislative 
adoption of restructuring principles in 1996, a VPSB proceeding to 
address the issue, filing by Vermont electric utilities of detailed 
plans by May 1, 1996, and implementation of restructuring by the end of 
1997.  In response to a Department petition, the VPSB opened a 
proceeding on utility industry restructuring by order dated October 17, 
1995.  On December 29, 1995, the Company released its proposed 
restructuring plan, calling for corporate separation into a regulated 
company for transmission and distribution functions, and an unregulated 
company for generation and sales functions.

     Increased competitive pressure in the electric utility industry may 
restrict the Company's ability to charge prices high enough to recover 
embedded costs and may lead to changes in the manner in which rates are 
set by regulators from cost-based regulation to a different form of 
regulation that approximates market conditions -- in which prices 
charged could be higher or lower than the Company's costs.


BUSINESS DEVELOPMENT

     The Company has a plan of diversification into energy-related 
businesses intended to complement the Company's basic utility 
enterprise.  These businesses are conducted through two subsidiaries, 
Green Mountain Propane Gas Company and Mountain Energy, Inc., and the 
Company's unregulated rental water heater activities.  The Company plans 
to limit such diversification to 20% of the Company's consolidated 
revenue.

     The Company consolidates the balance sheet of four of its wholly 
owned subsidiaries, Green Mountain Propane Gas Company, Mountain Energy, 
Inc., GMP Real Estate Corporation, and Lease-Elec, Inc.

     Included in equity in earnings of affiliates and non-utility 
operations in the Other Income section of the Statements of Consolidated 
Income are the results of operations of the Company's rental water 
heater program which is not regulated by the VPSB, and the four 
unregulated wholly owned subsidiaries named above.  Summarized financial 
information of the Company's unregulated activities over the last three 
years is as follows:

                                          For the years ended December 31
                                         1995          1994           1993
                                         ----          ----           ----
                                                   (In thousands)
Revenue . . . . . . . . . . . . . . .  $11,905        $12,031        $11,487
Expense . . . . . . . . . . . . . . .   10,416         10,920         11,527
                                       -------        -------       ---------
Net Income (Loss) . . . . . . . . . .  $ 1,489        $ 1,111       ($    40)
                                       =======        =======       =========


EMPLOYEES

     The Company had 350 employees, exclusive of temporary employees, as 
of December 31, 1995.  In addition, subsidiaries of the Company had 50 
employees at year end.


SEASONAL NATURE OF BUSINESS

     The Company experiences its heaviest loads in the colder months of 
the year.  Winter recreational activities, longer hours of darkness and 
heating loads from cold weather usually cause the Company's peak 
electric sales to occur in December, January or February.  The 1995 peak 
of 297.1 MW occurred on February 6, 1995.  The Company's retail electric 
rates are seasonally differentiated.  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 discussion -- Demand-Side Management -- Rate Design.




EXECUTIVE OFFICERS

Executive Officers of the Company as of March 31, 1996:

      Name                Age
Douglas G. Hyde            53    President, Chief Executive Officer and 
                                 Chairman of the Executive Committee of the 
                                 Corporation since 1993.  Executive Vice 
                                 President, Chief Operating Officer and 
                                 Director from 1989 to 1993.  Executive Vice 
                                 President and Director of the Corporation 
                                 from 1986 to 1989.

A. Norman Terreri          62    Executive Vice President and Chief 
                                 Operating Officer since January 1995.  Senior 
                                 Vice President and Chief Operating Officer 
                                 from 1993 to 1995.  Senior Vice President 
                                 from 1984 to 1993.  President - Mountain  
                                 Energy, Inc. since December 1989.

Edwin M. Norse             50    Vice President and General Manager, 
                                 Energy Resources and Sales since January 
                                 1995.  Vice President, Chief Financial 
                                 Officer and Treasurer from 1986 to January 
                                 1995.  President-Green Mountain Propane Gas 
                                 Company since October 1993.

Christopher L. Dutton      47    Vice President, Finance and 
                                 Administration, Chief Financial Officer and 
                                 Treasurer since January 1995.  Vice President 
                                 and General Counsel from 1993 to January 
                                 1995.  Vice President, General Counsel and 
                                 Corporate Secretary from 1989 to 1993.  
                                 General Counsel and Corporate Secretary from 
                                 1984 to 1989.

Glenn J. Purcell           62    Controller since September 1986.

Thomas C. Boucher          41    Vice President, Energy Resources and 
                                 Planning since January 1995.  Vice President-
                                 Corporate Planning from 1994 to 1995.  Vice 
                                 President, Financial Planning from 1992 to 
                                 1994.  Assistant Vice President-Energy 
                                 Planning from 1986 to 1992.

Stephen C. Terry           53    Vice President and General Manager, 
                                 Retail Energy Services since January 1995.  
                                 Vice President-External Affairs from 1991 to 
                                 January 1995.  Assistant Vice President-
                                 Corporate Relations from 1986 to 1991.

Walter S. Oakes            49    Assistant Vice President-Customer 
                                 Operations since June 1994.  Assistant Vice 
                                 President-Human Resources from August 1993 to 
                                 June 1994.  Assistant Vice President-
                                 Corporate Services from 1988 to 1993.



Robert C. Young            58    Assistant Vice President-Customer 
                                 Operations since 1994.  Assistant Vice 
                                 President-Operations and Engineering from 
                                 1992 to 1994.  Director of Engineering from 
                                 August 1991 to December 1992.  Director of 
                                 Special Projects from August 1991 to March 
                                 1992.  Prior to joining the Company, he was 
                                 employed by the Burlington Electric 
                                 Department for thirty-two years, including 
                                 sixteen years as General Manager.

Karen K. O'Neill           44    Assistant Vice President-Human 
                                 Resources and Organizational Development 
                                 since January 1995.  Assistant General 
                                 Counsel from 1989 to 1995.  Senior Attorney 
                                 from 1988 to 1989.

Craig T. Myotte            41    Assistant Vice President-Engineering 
                                 and Operations since 1994.  Assistant Vice 
                                 President-Operations and Maintenance from 
                                 1991 to 1994.  Director-System Operations 
                                 from 1986 to 1991.

John J. Lampron            51    Assistant Treasurer since July 1991.  
                                 Prior to joining the Company, he was employed 
                                 by Public Service Company of New Hampshire as 
                                 an Assistant Vice President from 1982 to 
                                 1990.

Donna S. Laffan            46    Corporate Secretary since December 
                                 1993.  Assistant Secretary from 1986 to 1993.

Peter H. Zamore            43    General Counsel since January 1995.  
                                 Prior to joining the Company, he was a 
                                 partner at the law firm of Sheehey Brue Gray 
                                 & Furlong, P.C. from 1984 to 1995.

     Officers are elected by the Board of Directors for one-year terms 
and serve at the pleasure of the Board of Directors.


ITEM 2.  PROPERTY

GENERATING FACILITIES

     The Company's Vermont properties are located in five areas and are 
interconnected by transmission lines of VELCO and New England Power 
Company.  The Company wholly owns and operates eight hydroelectric 
generating stations with a total nameplate rating of 36.4 MW and an 
estimated claimed capability of 35.7 MW.  It also owns two gas-turbine 
generating stations with an aggregate nameplate rating of 63.0 MW and an 
estimated aggregate claimed capability of 72.8 MW.  The Company has two 
diesel generating stations with an aggregate nameplate rating of 8.0 MW 
and an estimated aggregate claimed capability of 8.6 MW.

     The Company also owns 17.9% of the outstanding common stock, and is 
entitled to 17.265% (90.1 MW) of the capacity of Vermont Yankee, a 1.1% 
(7.1 MW) joint-ownership share of the Wyman #4 plant located in Maine, a 
8.8% (30.2 MW) joint-ownership share of the Stony Brook I intermediate 
units located in Massachusetts and an 11% (5.8 MW) joint-ownership share 
of theJ. C. McNeil wood-fired steam plant located in Burlington, Vermont.  
(See "Power Resources" under Item 1 above for plant details and the 
table hereinafter set forth for generating facilities presently 
available).


TRANSMISSION AND DISTRIBUTION

     The Company had, at December 31, 1995, approximately 1.5 miles of 
115-kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4 
miles of 44-kV and 265.4 miles of 34.5 kV transmission lines.  Its 
distribution system included about 2,374 miles of overhead lines, 2.4 kV 
to 34.5 kV, and about 418 miles of underground cable of 2.4 kV to 
34.5 kV.  At such date, the Company owned approximately 435,550 kVa of 
substation transformer capacity in distribution substations, 156,775 kVa 
of transformer capacity in transmission substations and 1,154,161 kVa of 
transformers for stepdown from distribution to customer use.

     The Company owns 33.8% of the Highgate transmission intertie, a 
200-MW converter and transmission line utilized to transmit power from 
Hydro-Quebec.

     The Company also owns 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 principal wholly owned plants of the Company are located on 
lands owned in fee by the Company.  Water power and floodage rights are 
controlled through ownership of the necessary land in fee or under 
easements.

     Transmission and distribution facilities which 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.


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 "Power Resources" in Item 1.



                                                                     
                                                                      Winter
                                                                    Capability
               Type     Location           Name              Fuel       MW(1)
               ----     --------           ----              ----   ----------

Wholly Owned   Hydro    Middlesex, VT      Middlesex #2      Hydro      3.3
                        Marshfield, VT     Marshfield #6     Hydro      4.9
                        Vergennes, VT      Vergennes #9      Hydro      2.1 
                        W. Danville, VT    W. Danville #15   Hydro      1.1

                        Colchester, VT     Gorge #18         Hydro      3.3
                        Essex Jct., VT     Essex #19         Hydro      7.8
                        Waterbury, VT      Waterbury #22     Hydro      5.0
                        Bolton, VT         DeForge #1        Hydro      7.8

               Diesel   Vergennes, VT      Vergennes #9      Oil        4.2
                        Essex Jct., VT     Essex #19         Oil        4.4

               Gas      Berlin, VT         Berlin #5         Oil       57.1
               Turbine  Colchester, VT     Gorge #16         Oil       15.7

Jointly Owned  Steam    Vernon, VT         Vermont Yankee    Nuclear   91.7(2)
                        Yarmouth, ME       Wyman #4          Oil        7.1
                        Burlington, VT     McNeil            Wood       6.6(3)

               Combined Ludlow, MA         Stony Brook #1    Oil/Gas   31.0(2)
                                                                       _____
 Total Winter Capability                                               253.1

(1)   Winter capability quantities are used since the Company's peak 
usage occurs during the winter months.  Some units are derated for 
the summer months.  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 "Long-Term Power 
Sales."

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


CORPORATE HEADQUARTERS

     For a discussion of the Company's operating lease for its Corporate 
Headquarters building, see Note I-2 of Notes to Consolidated Financial 
Statements.


ITEM 3.  LEGAL PROCEEDINGS

     See the discussion under "Environmental Matters" in Item 1 
concerning a notice received by the Company in 1982, under the 
Comprehensive Environmental Response, Compensation, and Liability Act of 
1980.




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.  The following tabulation shows the high and 
low sales prices for the Common Stock on the New York Stock Exchange 
during 1995 and 1994:

                                            HIGH         LOW
                                            ----         ---

        1995           First Quarter        28 1/4       24 7/8
                       Second Quarter       27           24 3/4
                       Third Quarter        27 1/8       23 7/8
                       Fourth Quarter       28 5/8       27 3/4

        1994           First Quarter        31 1/4       27 1/2
                       Second Quarter       30           23 3/4
                       Third Quarter        27 3/8       23 3/8
                       Fourth Quarter       28 1/8       23 7/8

     The number of common stockholders of record as of March 15, 1996 
was 8,601.

     Quarterly cash dividends were paid as follows for the past two 
years:

                    First       Second       Third       Fourth
                    Quarter     Quarter      Quarter     Quarter
                    -------     -------      -------     -------

      1995        53 cents    53 cents      53 cents    53 cents 
      1994        53 cents    53 cents      53 cents    53 cents

<TABLE>
<CAPTION>

ITEM 6. SELECTED FINANCIAL DATA  (In thousands except per share amounts)

Results of operations for the years ended December 31
-----------------------------------------------------

                                            1995         1994         1993         1992         1991
                                          ---------    ---------    ---------    ---------    ---------
<S>                                       <C>          <C>          <C>          <C>          <C>
Operating Revenues........................$161,544     $148,197     $147,253     $145,240     $143,555
Operating Expenses........................ 146,249      133,680      132,427      128,828      129,041
                                          ---------    ---------    ---------    ---------    ---------
  Operating Income........................  15,295       14,517       14,826       16,412       14,514
                                          ---------    ---------    ---------    ---------    ---------
Other Income
  AFUDC - equity..........................      27          263          273          186          225
  Other...................................   3,607        3,418        2,360        2,073        2,689
                                          ---------    ---------    ---------    ---------    ---------
    Total other income....................   3,634        3,681        2,633        2,259        2,914
                                          ---------    ---------    ---------    ---------    ---------
Interest Charges
  AFUDC - borrowed funds..................    (547)        (539)        (357)        (202)        (131)
  Other...................................   7,973        7,735        7,185        7,021        7,103
                                          ---------    ---------    ---------    ---------    ---------
    Total interest charges................   7,426        7,196        6,828        6,819        6,972
                                          ---------    ---------    ---------    ---------    ---------

Net Income................................  11,503       11,002       10,631       11,852       10,456

Dividends on Preferred Stock..............     771          794          811          831          852
                                          ---------    ---------    ---------    ---------    ---------
Net Income Applicable to Common Stock..... $10,732      $10,208       $9,820      $11,021       $9,604
                                          =========    =========    =========    =========    =========
Common Stock Data
  Earnings per share......................   $2.26        $2.23        $2.20        $2.54        $2.45
  Cash dividends declared per share.......   $2.12        $2.12        $2.11        $2.08        $2.04
  Weighted average shares outstanding.....   4,747        4,588        4,457        4,345        3,919



Financial Condition as of December 31
-------------------------------------
                                            1995         1994         1993         1992         1991
                                          ---------    ---------    ---------    ---------    ---------

Assets

 Utility Plant, Net.......................$181,999     $175,987     $171,411     $164,723     $159,730
 Other Investments........................  20,248       20,751       22,528       21,700       21,624
 Current Assets...........................  30,216       28,798       26,215       28,067       26,778
 Deferred Charges.........................  42,951       35,659       33,893       19,012       11,271
 Non-Utility Assets.......................  37,868       33,416       28,626       23,716       19,832
                                          ---------    ---------    ---------    ---------    ---------
  Total Assets............................$313,282     $294,611     $282,673     $257,218     $239,235
                                          =========    =========    =========    =========    =========

Capitalization and Liabilities

 Common Stock Equity......................$106,408     $101,319      $97,149      $92,645      $87,455
 Redeemable Cumulative Preferred Stock....   8,930        9,135        9,385        9,575        9,825
 Long-Term Debt, Less Current Maturities..  91,134       74,967       79,800       67,644       56,270
 Capital Lease Obligation.................   9,778       10,278       11,029       11,950       12,627
 Curent Liabilities.......................  32,629       40,441       37,925       30,099       32,893
 Deferred Credits and Other...............  52,041       49,434       40,214       33,264       29,694
 Non-Utility Liabilities..................  12,362        9,037        7,171       12,041       10,471
                                          ---------    ---------    ---------    ---------    ---------
  Total Capitalization and Liabilities....$313,282     $294,611     $282,673     $257,218     $239,235
                                          =========    =========    =========    =========    =========

</TABLE>


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

RESULTS OF OPERATIONS
Earnings Summary -- Earnings per average share of common stock in 1995 
were $2.26 as compared with $2.23 in 1994.  The 1995 earnings represent 
an earned return on average common equity of 10.3 percent.  In both 1994 
and 1993, the earned return on average common equity was also 
10.3 percent.

The 1995 increase in earnings was primarily due to higher retail 
revenues resulting from a 9.25 percent retail rate increase that went 
into effect in June 1995, increased sales of electricity to the 
Company's commercial and industrial customers, and a $557,000 increase 
in the earnings of Mountain Energy, Inc., the Company's wholly-owned 
subsidiary that invests in electric energy generation and efficiency 
projects.

The principal factor contributing to the increase in 1994 was a $722,000 
increase in earnings of Mountain Energy, Inc. and a $523,000 increase in 
earnings of Green Mountain Propane Gas Company, the Company's wholly-
owned propane subsidiary.

Operating Revenues and MWH Sales --  Operating revenues and MWH sales 
for the years 1995, 1994 and 1993 consisted of:



                                         1995          1994          1993
                                         ----          ----          ----
                                               (Dollars in Thousands)
Operating Revenues:
   Retail . . . . . . . . . . . . .  $  140,676    $  131,444    $  130,061
   Sales for Resale . . . . . . . .      17,541        13,521        14,441
   Other  . . . . . . . . . . . . .       3,327         3,232         2,751
                                     ----------    ----------    ----------
Total Operating Revenues  . . . . .  $  161,544    $  148,197    $  147,253
                                     ==========    ==========    ========== 
Megawatthour Sales:
   Retail . . . . . . . . . . . . .   1,723,117     1,691,867     1,688,803
   Sales for Resale . . . . . . . .     620,655       367,424       331,875
                                      ---------     ---------     ---------
Total Megawatthour Sales  . . . . .   2,343,772     2,059,291     2,020,678
                                      =========     =========     =========
Average Number of Customers:
   Residential  . . . . . . . . . .      69,659        68,811        67,994
   Commercial & Industrial  . . . .      11,736        11,635        11,472
   Other  . . . . . . . . . . . . .          76            76            74
                                         ------        ------        ------
Total Customers . . . . . . . . . .      81,471        80,522        79,540
                                         ======        ======        ======

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

                                                   1994         1993
                                                    to           to
                                                   1995         1994
                                                   ----         ----
                                                     (In Thousands)
Operating Revenues:
   Retail Rates . . . . . . . . . . . . . . .    $ 6,619       $1,140
   Retail Sales Volume  . . . . . . . . . . .      2,613          244
   Resales and Other Revenues . . . . . . . .      4,115         (440)
                                                 -------       -------
Increase in Operating Revenues  . . . . . . .    $13,347       $  944
                                                 =======       =======

In 1995, total electricity sales increased 13.8 percent due principally 
to an increase in electricity consumption by the Company's commercial 
and industrial customers and regional market conditions that allowed the 
Company to buy electricity and to resell it to other utilities at prices 
slightly higher than the purchase price.  Total operating revenues 
increased 9.0 percent in 1995 primarily due to a 9.25 percent retail 
rate increase that went into effect in June 1995 and the increase in 
electricity sales mentioned above.  Total retail revenues increased 
7.0 percent in 1995 primarily due to the 9.25 percent retail rate 
increase mentioned above.  Wholesale revenues increased 29.7 percent in 
1995 primarily due to the regional market conditions mentioned above.

In 1994, total electricity sales increased 1.9 percent due principally 
to colder than normal winter weather in the first quarter and warmer 
than normal summer weather.  Total operating revenues increased 
0.6 percent in 1994 due principally to a 2.9 percent rate increase that 
was effective in June 1994.  Wholesale revenues decreased 6.4 percent in 
1994 due principally to the greater availability of low-cost energy in 
New England, which drove down wholesale prices.

IBM, the Company's single largest customer, operates manufacturing 
facilities in Essex Junction.  IBM's electricity requirements for its 
main plant and an adjacent plant accounted for 12.9, 13.7 and 
13.6 percent of the Company's operating revenues in 1995, 1994 and 1993, 
respectively.  No other retail customer accounted for more than one 
percent of the Company's revenue.

Power Supply Expenses -- Power supply expenses constituted 60.1 percent, 
59.2 percent and 59.7 percent of total operating expenses for the years 
ended 1995, 1994 and 1993, respectively.  These expenses increased by 
$8.7 million (11.0 percent) in 1995 and by $190,000 (0.2 percent) in 
1994.

Power supply expenses increased in 1995 as the Company produced and 
purchased additional power to service increased electricity sales.

Power supply expenses were virtually unchanged in 1994 from 1993.

Other Operating Expenses -- Other operating expenses increased 
4.8 percent in 1995 primarily due to an increase in rent expense and 
expenses relating to customer-focused research.

Other operating expenses were virtually unchanged in 1994 from 1993.

Transmission Expenses -- Transmission expenses decreased 4.8 percent in 
1995 primarily due to cost reduction measures implemented by VELCO.

The Company's restructuring of a series of transmission contracts 
produced a 3.7 percent decrease in transmission expenses in 1994.

Maintenance Expenses -- Maintenance expenses decreased 5.7 percent in 
1995 primarily due to cost containment measures implemented by the 
Company.

Maintenance expenses increased 2.6 percent in 1994 due principally to a 
scheduled increase in plant maintenance.

Depreciation and Amortization -- Depreciation and amortization expenses 
increased 32.1 percent in 1995 primarily due to the amortization of 
expenditures related to energy conservation programs and the Pine Street 
Marsh environmental matter and insurance litigation (discussed in Note I 
of the Notes to Consolidated Financial Statements) and to additional 
investment in the Company's utility plant.

Depreciation and amortization expenses increased 24.6 percent in 1994 
for the same reasons.

Income Taxes -- The effective federal tax rates for the years 1995, 1994 
and 1993 were 25.3 percent, 25.1 percent and 28.9 percent, respectively.

Other Income -- Other income decreased 1.3 percent in 1995 primarily due 
to a decrease in the allowance for equity funds used during construction 
resulting from lower average construction work in progress balances and 
an increase in short-term debt outstanding during the year and a 
$389,000 decrease in earnings experienced by Green Mountain Propane Gas 
Company, the Company's wholly-owned propane subsidiary.  These decreases 
were partially offset by a $557,000 increase in earnings of Mountain 
Energy, Inc.  Additionally, other income in 1994 benefited from a one-
time increase of $162,000 resulting from a Vermont Supreme Court ruling 
overturning a Vermont Public Service Board (VPSB) decision disallowing 
certain DSM costs.

Other income increased 39.8 percent in 1994 due primarily to a $722,000 
increase in earnings of Mountain Energy, Inc., and a $523,000 increase 
in earnings of Green Mountain Propane Gas Company.

Interest Charges -- Interest charges increased 3.2 percent in 1995 
primarily due to interest charges related to an increase in short-term 
debt outstanding during 1995.  These charges were partially offset by a 
reduction in interest charges related to a decrease in long-term debt 
outstanding during 1995.

Interest charges increased 5.4 percent in 1994 due primarily to interest 
charges related to the sale of $20 million of first mortgage bonds in 
November 1993 and to an increase in short-term debt outstanding during 
1994.

Dividends on Preferred Stock -- Dividends on preferred stock decreased 
2.9 percent in 1995 due primarily to the repurchase by the Company in 
1994 of the following preferred stock:  450 shares of 4.75 percent, 
Class B; 450 shares of 7 percent, Class C, and 1,600 shares of 
9.375 percent, Class D, Series 1.

Dividends on preferred stock decreased 2.1 percent in 1994 due primarily 
to the repurchase by the Company in 1993 of the following preferred 
stock:  300 shares of 4.75 percent, Class B and 1,600 shares of 
9.375 percent, Class D, Series 1.

Future Outlook -- Regulatory and legislative authorities at the federal 
level and among states across the country, including Vermont, are 
considering how to facilitate competition for electricity sales at the 
wholesale and retail levels.  On October 24, 1994, the VPSB and the 
Vermont Department of Public Service (the Department) convened a 
"Roundtable on Competition and the Electric Industry," consisting of 
representatives of utilities (including the Company), customers, 
environmental groups and other affected parties.  On July 17, 1995, a 
subgroup of the Roundtable agreed on a set of fourteen principles 
intended to guide the debate in Vermont concerning competition.  These 
principles, among other things, call for exploration of the potential 
for retail competition, honoring of past utility commitments incurred 
under regulation, protection for low income customers, and continued 
exploration of renewable resources, energy efficiency and environmental 
protections.

On September 14, 1995, Governor Dean of Vermont announced his desire to 
provide for competition and a restructuring of the utility industry.  
The Governor's announcement included proposed legislative adoption of 
restructuring principles in 1996, a VPSB proceeding to address the 
issue, filing by Vermont electric utilities of detailed plans by May 1, 
1996, and implementation of restructuring by the end of 1997.  In 
response to a Department petition, the VPSB opened a proceeding on 
utility industry restructuring by order dated October 17, 1995.  On 
December 29, 1995, the Company released its proposed restructuring plan, 
calling for corporate separation into a regulated company for 
transmission and distribution functions, and an unregulated company for 
generation and sales functions.

Increased competitive pressure in the electric utility industry may 
restrict the Company's ability to charge prices high enough to recover 
embedded costs and may lead to changes in the manner in which rates are 
set by regulators from cost-based regulation to a different form of 
regulation that approximates market conditions -- in which prices 
charged could be higher or lower than the Company's costs.

Because the Company purchases most of its power supply from other 
utilities, it does not anticipate that it will incur any material direct 
cost increases as a result of the Federal Clean Air legislation.  
Furthermore, only one of its power supply purchase contracts, which 
expires in 1998, relates to a generating plant that is likely to be 
affected by the acid rain provisions of this legislation.  Overall, 
approximately 10 percent of the Company's committed electricity supply 
(a contract to purchase coal-fired generation that expires in 1998) is 
expected to be affected by federal and State environmental compliance 
requirements.

The Company continues to implement conservation programs to mitigate the 
increasing demand for electricity.  The Company is reviewing its future 
conservation plans in light of various factors, including competition, 
changing avoided electricity costs, its experience and increased 
effectiveness in delivering conservation programs, and its total 
resource mix.  Even with continued existing conservation programs, the 
Company anticipates, assuming normal weather, that the demand for 
electricity in its service territory will grow by approximately 
1.2 percent per year over the next five years.

The Company regularly reviews rates and forecasts costs.  As these 
forecasts change, the Company will seek changes in rates that will 
enable it to recover operating costs.

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.

Diversification -- The Company has a plan of diversification into 
energy-related businesses intended to complement the Company's basic 
utility enterprise.  The Company plans to limit diversification to 
20 percent of the Company's consolidated revenue.

Mountain Energy, Inc. performed well in 1995, producing an after-tax 
profit of $1.38 million, an increase of $557,000 from 1994, and 
contributed 29 cents of earnings per share to the Company's consolidated 
earnings.

During the year, Mountain Energy made new, long-term investments 
totaling $4.4 million in a New England hydroelectric facility and in 
energy-efficiency projects in New England, California, New York and New 
Jersey.  Mountain Energy has now invested almost $16 million in nine 
different projects, eight of which are renewable-energy related.  The 
Company's cash investment in Mountain Energy at December 31, 1995 was 
$10.7 million.

Environmental Matters -- In recent years, public concern for the 
physical environment has brought about increased government regulation 
of the licensing and operation of electric generation, transmission and 
distribution facilities.  The Company must meet various land, water, air 
and aesthetic requirements as administered by local, state and federal 
regulatory agencies.  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.  
Subject to the results of developments discussed in Note I.1 of Notes to 
Consolidated Financial Statements concerning the Pine Street Marsh site 
in Burlington, Vermont, the Company believes that it is in substantial 
compliance with such requirements, and no material complaints concerning 
compliance by the Company with present environmental protection 
regulations are outstanding.

Through rate cases filed in 1991, 1993 and 1994, the Company has sought 
and received recovery for ongoing expenses associated with the Pine 
Street Marsh site.  Specifically, the Company proposed rate recognition 
of its unrecovered expenditures between January 1991 and June 30, 1994 
(a total of approximately $7.3 million) for technical consultants and 
legal assistance in connection with the EPA's enforcement actions at the 
site and insurance litigation.  While reserving the right to argue in 
the future about the appropriateness of rate recovery for Pine Street 
Marsh related costs, the Company and the Department reached agreements 
in these cases that the full amount of Pine Street Marsh costs reflected 
in those rate cases should be recovered in rates.  The Company's rates 
approved by the VPSB on April 2, 1992, on May 13, 1994, and on June 5, 
1995, reflected the Pine Street Marsh related expenditures referred to 
above.

In a rate case filed on September 15, 1995, the Company sought recovery 
in rates of approximately $1.3 million in expenses associated with the 
Pine Street site.  This amount represented the Company's unrecovered 
expenditures between July 1994 and June 1995 for technical consultants 
and legal assistance in connection with EPA's enforcement action at the 
site and insurance litigation.  While reserving the right to argue in 
the future about the appropriateness of rate recovery for Pine Street 
related costs (and whether recovery or non-recovery of past costs and 
any insurance proceeds is relevant to such issue), the parties to the 
case have reached agreement that the full amount of Pine Street costs 
reflected in the Company's 1995 rate case should be recovered in rates.  
This agreement is currently pending before the VPSB.

Management expects to seek and (assuming treatment consistent with the 
previous regulatory treatment set forth above) receive ratemaking 
treatment for unreimbursed costs incurred beyond the amounts for which 
ratemaking treatment has been received.

As is more fully set forth in Note I.1 of Notes to Consolidated 
Financial Statements, the Company is unable to predict at this time the 
magnitude of liability that may be imposed on it resulting from 
potential claims for the cost of studies undertaken by the EPA or 
performance of any remedial action in connection with the Pine Street 
Marsh site.  The Company is one of several parties that the EPA has 
identified as potentially responsible for the cost of studying and 
remedying the results of releases of allegedly hazardous substances at 
the site.  The Company will continue to pursue claims against other 
responsible parties seeking to ensure that they contribute appropriately 
to reimburse the Company for any costs incurred.

In December 1991, the Company brought suit against several previous 
insurers seeking recovery of unrecovered past costs and indemnity 
against future liabilities associated with environmental problems at the 
site.  Discovery in the case is largely complete, with the exception of 
expert discovery which was stayed by the magistrate pending the 
resolution of Summary Judgment Motions filed by the Company.  In August 
1994, the Magistrate granted the Company's Motion for Summary Judgment 
with respect to defense costs against one defendant and denied it 
against another defendant.  The United States District Judge affirmed 
those orders on September 30, 1994.

The Company has reached confidential settlements with two of the 
defendants in its insurance litigation.  One of these defendants 
provided the Company with comprehensive general liability insurance 
between 1976 and 1982, and with environmental impairment liability 
insurance from 1981 to 1984.  These policies were in place in 1982 when 
the EPA first notified the Company that it might be a potentially 
responsible party at the Pine Street Marsh site.  The other defendant 
provided the Company with second layer excess liability coverage for a 
seven-month period in 1976.

LIQUIDITY AND CAPITAL RESOURCES
Construction -- The Company's capital requirements result from the need 
to construct facilities or to invest in programs to meet anticipated 
customer demand for electric service.  The policy of the Company is to 
increase diversification of its power supply and other resources through 
various means, including power purchase and sales arrangements and 
relying on sources that represent relatively small additions to the 
Company's mix to satisfy customer requirements.  This permits the 
Company to meet its financing needs in a flexible, orderly manner.  
Planned expenditures over the next five years will be primarily for 
distribution and conservation projects.

Capital expenditures over the past three years and projected for the 
next five years are as follows:

                                                                   Total Net
Actual  Generation  Transmission  Distribution Conservation Other	Expenditures
------  ----------  ------------  ------------ ------------ ----- ------------
(Dollars in thousands and net of AFUDC and Customer Advances For Construction)

 1993     $1,747       $1,605        $9,093       $8,136   $2,937   $23,518
 1994      2,540        1,415         7,902        6,388    1,815    20,060
 1995      2,696        1,067         8,935        4,152    2,824    19,674
Forecasted
 1996     $9,530*        $569        $8,496       $2,754   $6,601   $27,950
 1997        899          999         8,745        2,444    3,861    16,948
 1998      1,978          999         8,872        2,742    3,591    18,182
 1999      2,478          999         9,084        2,643    4,895    20,099
 2000      2,478          999         9,084        2,543    2,897    18,001

*Includes $8.771 million projected for wind project.

Other Cash Requirements -- In 1996, the Company may devote $3 million to 
unregulated investments.

Rates -- On September 26, 1994, the Company filed a request with the 
VPSB to increase retail rates by 13.9 percent.  The increase was needed 
primarily to cover the rising cost of existing power sources, the cost 
of new power sources the Company has secured to replace power supply 
that will be lost in the near future, and the cost of energy efficiency 
programs the Company has implemented for its customers.

The Company, the Department, and the other parties in the proceeding 
reached a settlement agreement providing for a 9.25 percent retail rate 
increase effective June 15, 1995, and a target return on equity of 
11.25 percent.  The agreement was approved by the VPSB on June 9, 1995.

On September 15, 1995, the Company filed a request with the VPSB to 
increase retail rates by 12.7 percent.  The increase is needed to cover 
higher power supply costs, to support additional investment in plant and 
equipment, to fund expenses associated with the Pine Street site, and to 
cover higher costs of capital.

The Company and the Department reached a settlement agreement providing 
for a 5.25 percent retail rate increase effective June 1, 1996, and a 
target return on equity for utility operations of 11.25 percent.  The 
settlement was based on a newly negotiated agreement with Hydro-Quebec 
that will result in a reduction of the Company's power supply costs 
below that which was anticipated, allowing the Company to reduce the 
amount of its rate request.  The rate settlement must be reviewed and 
approved by the VPSB before it can take effect.

Financing and Capitalization --  For the period 1993 through 1995, 
internally generated funds, after payment of dividends, provided 
approximately 59 percent of total capital requirements for construction, 
sinking funds and other requirements.  The Company anticipates that for 
the period 1996-2000, internally generated funds will provide 
approximately 73 percent of total capital requirements.

In December 1995, the Company sold $24 million of its first mortgage 
bonds in three components -- $8 million at an interest rate of 
6.21 percent that will mature in 2001, $8 million at an interest rate of 
6.29 percent that will mature in 2002, and $8 million at an interest 
rate of 6.41 percent that will mature in 2003.  A portion of the 
proceeds of the sale was used to reduce short-term bank loans 
outstanding and the remainder has allowed the Company to refund 
preexisting long-term debt.

At December 31, 1995, the Company's capitalization consisted of 
49.7 percent common equity, 46.1 percent long-term debt and 4.2 percent 
preferred equity.  The Company has a comprehensive capital plan to 
increase the equity component of its capital structure.

During 1995, the Company took several steps toward enhancing its 
financial flexibility.  The Company filed a shelf registration statement 
with the SEC which allows for the periodic sale to the public of its 
common stock, first mortgage bonds and unsecured notes.  On December 31, 
1995, $26 million was available under such registration statement.  
Additionally, the Company established a medium-term note program which 
allows for the sale of secured and unsecured debt.

The Company anticipates issuing approximately $10 million of common 
stock and $10 million of first mortgage bonds in 1996.  The proceeds 
will be used to retire short-term debt and for other corporate purposes.

The rating of the Company's first mortgage bonds by Standard & Poor's 
remains at "BBB+."  Standard & Poor's "outlook" of the Company remains 
"stable."

The rating of the Company's first mortgage bonds was lowered in January 
1995 by Duff & Phelps from "A" to "A-", reflecting Duff & Phelps' 
assessment that the electric utility industry is becoming increasingly 
more competitive and that the Company is highly dependent on purchased 
power resulting in escalating fixed payment obligations.  The rating of 
the Company's preferred stock was also lowered from "A-" to "BBB+."  
Duff & Phelps, however, concluded that the Company's cost and rate 
structure is one of the lowest in New England.

The Company's first mortgage bonds were rated publically for the first 
time by Moody's Investor Service in August 1995.  Moody's assigned a 
"Baa2" rating reflecting the Company's relatively small size, its 
financial profile after adjustments for purchased power obligations, and 
expected continuation of a high dividend payout ratio.  Moody's noted 
the Company's low rates in the Northeast region, its limited need for 
external financing of construction expenditures, and its prospective 
benefits resulting from a renegotiated arrangement with Hydro-Quebec.  
Moody's assigned an outlook of "stable" for the Company.

See Note F of Notes to Consolidated Financial Statements for a 
discussion of bank lines of credit available to the Company.



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES

                                                                       Page
Financial Statements

Statements of Consolidated Income
  For the Years Ended December 31, 1995, 1994 and 1993                  41

Consolidated Statements of Cash Flows for the
  Years Ended December 31, 1995, 1994 and 1993                          42

Consolidated Balance Sheets as of
  December 31, 1995 and 1994                                          43-44

Consolidated Capitalization data as of
  December 31, 1995 and 1994                                            45

Notes to Consolidated Financial Statements                            46-66

Report of Independent Public Accountants                                67

Schedules

For the Years Ended December 31, 1995, 1994 and 1993:

    II  Valuation and Qualifying Accounts and Reserves                  68

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

Consents and Reports of Independent Public Accountants

       Arthur Andersen LLP                                              81


<TABLE>
<CAPTION>


                             CONSOLIDATED STATEMENTS OF INCOME

        GREEN MOUNTAIN POWER CORPORATION   For the Years Ended December 31




                                                                      1995                1994                1993
                                                                -----------------    ---------------     ---------------
                                                                         (In thousands, except amounts per share)

<S>                                                                     <C>                <C>                 <C>
Operating Revenues (Note A).....................................        $161,544           $148,197            $147,253
                                                                -----------------    ---------------     ---------------
Operating Expenses
  Power Supply (Notes A, B and K)
     Vermont Yankee Nuclear Power Corporation...................          30,222             30,300              29,785
     Company-owned generation...................................           3,786              3,113               3,150
     Purchases from others......................................          53,915             45,777              46,066
  Other operating...............................................          18,120             17,296              17,353
  Transmission (Note J).........................................           9,874             10,374              10,775
  Maintenance...................................................           4,210              4,465               4,352
  Depreciation and amortization (Note A)........................          14,116             10,683               8,572
  Taxes other than income.......................................           6,428              6,277               6,125
  Income taxes (Note G).........................................           5,578              5,395               6,249
                                                                -----------------    ---------------     ---------------
     Total operating expenses...................................         146,249            133,680             132,427
                                                                -----------------    ---------------     ---------------
       Operating Income.........................................          15,295             14,517              14,826
                                                                -----------------    ---------------     ---------------

Other Income
  Equity in earnings of affiliates and 
     non-utility operations (Note B)............................           3,513              3,112               2,341
  Allowance for equity funds used during construction (Note A)..              27                263                 273
  Other income and deductions, net..............................              94                306                  19
                                                                -----------------    ---------------     ---------------
    Total other income..........................................           3,634              3,681               2,633
                                                                -----------------    ---------------     ---------------
      Income before interest charges............................          18,929             18,198              17,459
                                                                -----------------    ---------------     ---------------

Interest Charges
  Long-term debt................................................           6,546              6,868               6,539
  Other.........................................................           1,427                867                 646
  Allowance for borrowed funds used during 
     construction (Note A)......................................            (547)              (539)               (357)
                                                                -----------------    ---------------     ---------------
    Total interest charges......................................           7,426              7,196               6,828
                                                                -----------------    ---------------     ---------------
Net Income......................................................          11,503             11,002              10,631

Dividends on preferred stock....................................             771                794                 811
                                                                -----------------    ---------------     ---------------
Net Income Applicable to Common Stock...........................         $10,732            $10,208              $9,820
                                                                =================    ===============     ===============

Common Stock Data (Notes A and C)
  Earnings per share............................................           $2.26              $2.23               $2.20

  Cash dividends declared per share.............................           $2.12              $2.12               $2.11

  Weighted average shares outstanding...........................           4,747              4,588               4,457


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

</TABLE>

<TABLE>
<CAPTION>
                                    CONSOLIDATED STATEMENTS OF CASH FLOWS

                     GREEN MOUNTAIN POWER CORPORATION  For the Years Ended December 31


                                                                         1995          1994          1993
                                                                       ---------     ---------     ---------
                                                                                  (In thousands)
<S>                                                                     <C>           <C>           <C> 
Operating Activities:
  Net Income........................................................... $11,503       $11,002       $10,631
  Adjustments to reconcile net income to net cash
    provided by operating activities:
      Depreciation and amortization (Note A)...........................  14,116        10,683         8,572
      Dividends from associated companies less equity income (Note B)..     660           202           254
      Allowance for funds used during construction (Note A)............    (574)         (803)         (630)
      Deferred purchased power costs (Note A).......................... (12,935)         (536)       (6,432)
      Amortization of purchased power costs (Note A)...................   6,036         4,178         3,723
      Deferred income taxes (Note G)...................................   3,715         1,585         5,180
      Amortization of gain on sale of property.........................     (53)          (53)          (53)
      Amortization of investment tax credits (Note G)..................    (283)         (283)         (283)
      Environmental proceedings costs, net (Note I)....................  (1,351)        7,103        (2,472)
      Changes in:
        Accounts receivable............................................  (2,841)         (426)        2,384
        Accrued utility revenues.......................................    (510)          126          (538)
        Fuel, materials and supplies...................................       2          (473)           53
        Prepayments and other current assets...........................   1,562        (1,982)        1,069
        Accounts payable...............................................   2,191        (2,327)          513
        Taxes accrued..................................................    (871)        1,044          (418)
        Interest accrued...............................................    (106)         (117)          903
        Other current liabilities......................................     (22)          (65)       (2,745)
      Other............................................................     (42)        2,436        (1,883)
                                                                       ---------     ---------     ---------
    Net cash provided by operating activities..........................  20,197        31,294        17,828
                                                                       ---------     ---------     ---------

Investing Activities:
    Construction expenditures.......................................... (15,314)      (13,536)      (15,949)
    Conservation expenditures..........................................  (3,960)       (6,388)       (8,136)
    Investment in non-utility property.................................  (6,121)       (1,220)       (5,950)
    Special fund for postretirement benefits (Note A)..................    --            --            (601)
                                                                       ---------     ---------     ---------
      Net cash used in investing activities............................ (25,395)      (21,144)      (30,636)
                                                                       ---------     ---------     ---------
Financing Activities:
    Reduction in preferred stock (Note D)..............................    (205)         (250)         (190)
    Issuance of common stock (Note C)..................................   4,404         3,671         4,077
    Short-term debt, net (Note F)...................................... (11,799)        1,198         7,402
    Issuance of long-term debt (Note E) ...............................  25,917          --          20,000
    Reduction in long-term debt (Note E)...............................  (4,833)       (1,800)       (8,530)
    Cash dividends..................................................... (10,818)      (10,504)      (10,204)
                                                                       ---------     ---------     ---------
      Net cash provided by (used in) financing activities..............   2,666        (7,685)       12,555
                                                                       ---------     ---------     ---------

    Net increase (decrease) in cash and cash equivalents...............  (2,532)        2,465          (253)
    Cash and cash equivalents at beginning of year.....................   2,692           227           480
                                                                       ---------     ---------     ---------
Cash and Cash Equivalents at End of Year...............................    $160        $2,692          $227
                                                                       =========     =========     =========

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

</TABLE>

<TABLE>
<CAPTION>

                          CONSOLIDATED BALANCE SHEETS

                   GREEN MOUNTAIN POWER CORPORATION    December 31


                                                         1995               1994
                                                       ---------          ---------
                                                              (In thousands)
ASSETS

<S>                                                    <C>                <C>
Electric Utility
Utility Plant (Notes A, E and I)
    Utility plant, at original cost....................$239,291           $227,991
    Less accumulated depreciation......................  75,797             69,246
                                                       ---------          ---------
      Net utility plant................................ 163,494            158,745
    Property under capital lease (Note J)..............   9,778             10,278
    Construction work in progress......................   8,727              6,964
                                                       ---------          ---------
      Total utility plant, net......................... 181,999            175,987
                                                       ---------          ---------
Other Investments
    Associated companies, at equity (Notes A,B and I)..  16,024             16,684
    Other investments (Note A).........................   4,224              4,067
                                                       ---------          ---------
      Total other investments..........................  20,248             20,751
                                                       ---------          ---------
Current Assets
    Cash...............................................      84              2,113
    Accounts receivable, customers and others,
      less allowance for doubtful accounts.............  18,081             15,240
    Accrued utility revenues (Note A)..................   6,523              6,012
    Fuel, materials and supplies, at average cost......   3,312              3,314
    Prepayments........................................   1,890              1,796
    Other..............................................     326                323
                                                       ---------          ---------
      Total current assets.............................  30,216             28,798
                                                       ---------          ---------
Deferred Charges
    Demand side management programs...................   18,367             18,560
    Environmental proceedings costs (Note I)...........   7,893              7,741
    Purchased power costs..............................   8,433              1,534
    Other..............................................   8,258              7,824
                                                       ---------          ---------
      Total deferred charges...........................  42,951             35,659
                                                       ---------          ---------
Non-Utility
    Cash and cash equivalents..........................      76                579
    Other current assets...............................   4,055              5,716
    Property and equipment.............................  11,478             11,329
    Intangible assets..................................   2,580              3,022
    Equity investment in energy-related businesses.....  10,999             10,199
    Other assets.......................................   8,680              2,571
                                                       ---------          ---------
      Total non-utility assets.........................  37,868             33,416
                                                       ---------          ---------
Total Assets...........................................$313,282           $294,611
                                                       =========          =========

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



                   GREEN MOUNTAIN POWER CORPORATION    December 31

                                                         1995               1994
                                                       ---------          ---------
                                                              (In thousands)

CAPITALIZATION AND LIABILITIES

Electric Utility
Capitalization (See Capitalization Data)
    Common Stock Equity (Note C)
      Common stock..................................... $16,168            $15,592
      Additional paid-in capital.......................  64,206             60,378
      Retained Earnings................................  26,412             25,727
      Treasury stock, at cost..........................    (378)              (378)
                                                       ---------          ---------
        Total common stock equity...................... 106,408            101,319
    Redeemable cumulative preferred stock (Note D).....   8,930              9,135
    Long-term debt, less current maturities (Note E)...  91,134             74,967
                                                       ---------          ---------
        Total capitalization........................... 206,472            185,421
                                                       ---------          ---------

Capital Lease Obligation (Note J)......................   9,778             10,278
                                                       ---------          ---------

Current Liabilities
    Current maturuties of long-term debt...............   7,833              4,833
    Short-term debt (Note F)...........................   8,416             20,214
    Accounts payable, trade, and accrued liabilities...   5,529              5,489
    Accounts payable to associated companies (Note B)..   7,011              4,860
    Dividends declared.................................     194                194
    Customer deposits..................................     816                964
    Taxes Accrued......................................     571              1,442
    Interest accrued...................................   1,847              1,953
    Other..............................................     412                492
                                                       ---------          ---------
        Total current liabilities......................  32,629             40,441
                                                       ---------          ---------
Deferred Credits
    Accumulated deferred income taxes (Note G).........  25,292             22,082
    Unamortized investment tax credits (Note G)........   5,107              5,390
    Other (Note A).....................................  21,642             21,962
                                                       ---------          ---------
        Total deferred credits.........................  52,041             49,434
                                                       ---------          ---------

Non-Utility
    Current liabilities................................   1,124                918
    Other liabilities..................................  11,238              8,119
                                                       ---------          ---------
        Total non-utility liabilities..................  12,362              9,037
                                                       ---------          ---------
Total Capitalization and Liabilities...................$313,282           $294,611
                                                       =========          =========

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

</TABLE>

<TABLE>
<CAPTION>


CONSOLIDATED CAPITALIZATION DATA

                                            GREEN MOUNTAIN POWER CORPORATION  December 31


                                                                                     Issued and Outstanding
CAPITAL STOCK                                                         Authorized        1995         1994         1995         1994
                                                                      -----------    ----------   ----------    ---------    -------
                                                                                                                    (In thousands)
<S>                                                           <C>     <C>            <C>          <C>            <C>          <C>   
Common Stock,$3.33 1/3 par value (Note C)...................         10,000,000     4,850,496    4,677,512      $16,168      $15,592
                                                                                                                =========    =======
     ----------------------------------------------------------------------------------------------------------------

                                                                                            Outstanding
                                                          Authorized   Issued          1995         1994         1995         1994
                                                          ---------- -----------    ----------   ----------    ---------    -------
                                                                                                                   (In thousands)
Redeemable Cumulative Preferred Stock,
 $100 par value (Note D)
   4.75%,Class B, redeemable at
     $101 per share.......................................    15,000     15,000         3,000        3,450         $300         $345
   7%,Class C, redeemable at
     $101 per share.......................................    15,000     15,000         5,100        5,100          510          510
   9.375%,Class D,Series 1,
     redeemable at $101 per share.........................    40,000     40,000        11,200       12,800        1,120        1,280
   8.625%,Class D,Series 3,
     redeemable at $103.835 per share.....................    70,000     70,000        70,000       70,000        7,000        7,000
   Class E................................................   200,000       --             --           --           --           --
                                                                                                                ---------    -------
Total Preferred Stock.....................................                                                       $8,930       $9,135
                                                                                                               =========    ========


LONG-TERM DEBT (Note E)                                                                                          1995         1994
                                                                                                               ---------    -------
                                                                                                                   (In thousands)

First Mortgage Bonds
  5 1/8% Series due 1996.......................................................................................  $3,000       $3,000
  7% Series due 1998...........................................................................................   3,000        3,000
  10.7% Series due 2000 - Cash sinking fund,$1,800,000 
      annually.................................................................................................   9,000       10,800
  10.0% Series due 2004 - Cash sinking fund,$1,700,000
      annually.................................................................................................  15,300       17,000
  9.64% Series due 2020........................................................................................   9,000        9,000
  8.65% Series due 2022 - Cash sinking fund,commences 2012.....................................................  13,000       13,000
  6.84% Series due 1997 - Cash sinking fund,$1,333,000
      annually.................................................................................................   2,667        4,000
  5.71% Series due 2000........................................................................................   5,000        5,000
  6.7% Series due 2018.........................................................................................  15,000       15,000
  6.21% Series due 2001........................................................................................   8,000         --
  6.29% Series due 2002........................................................................................   8,000         --
  6.41% Series due 2003........................................................................................   8,000         --
                                                                                                                ---------    -------
Total Long-term Debt Outstanding...............................................................................  98,967       79,800
  Less Current Maturities (due within one year)................................................................   7,833        4,833
                                                                                                               ---------    --------
Total Long-term Debt, Net...................................................................................... $91,134      $74,967
                                                                                                               =========    ========

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

</TABLE>

Notes to Consolidated Financial Statements

A. Significant Accounting Policies
1. The Company
Green Mountain Power Corporation (the Company) is an investor-owned 
energy services company located in Vermont that serves one-third of its 
population.  The most significant portion of the Company's net income is 
derived from its electric utility operations, which purchases and 
generates electric power and distributes it to 82,000 retail and 
wholesale customers.  Two of the Company's wholly-owned subsidiaries 
(which are not regulated by the Vermont Public Service Board (VPSB)) are 
Green Mountain Propane Gas Company, which supplies propane to 10,000 
customers in Vermont and New Hampshire, and Mountain Energy, Inc., which 
invests in electric generation and energy conservation projects across 
the United States.  The results of these subsidiaries, the Company's 
unregulated rental water heater program and its other unregulated 
wholly-owned subsidiaries (GMP Real Estate Corporation and Lease-Elec, 
Inc.) are included in earnings of affiliates and non-utility operations 
in the Other Income section of the Consolidated Statements of Income.  
Summarized financial information is as follows:
                             


                                            For the years ended December 31
                                                 1995             1994
                                                 ----             ----
                                                    (In thousands)
   Revenue  . . . . . . . . . . . . . . .       $11,905          $12,031
   Expense. . . . . . . . . . . . . . . .        10,416           10,920
                                                -------          -------
   Net Income . . . . . . . . . . . . . .       $ 1,489          $ 1,111
                                                =======          =======

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 -- at 
equity.

2. Basis of Presentation
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) 
71, Accounting for Certain Types of Regulation.  Under SFAS 71, the 
Company is permitted to account for certain transactions in accordance 
with permitted regulatory treatment.  As such, regulators may permit 
incurred costs, typically treated as expenses, to be deferred and 
recovered in future revenues.  In the event that the Company no longer 
meets the criteria under SFAS 71, the Company would be required to 
writeoff related regulatory assets and liabilities.

SFAS 121, Accounting for the Impairment of Long Lived Assets, which 
becomes effective for the Company January 1, 1996, requires that any 
assets, including regulatory assets, which are no longer probable of 
recovery through future revenues, be revalued based upon future cash 
flows.  SFAS 121 requires that a rate-regulated enterprise recognize an 
impairment loss for the amount of costs excluded from recovery.  Based 
upon the regulatory environment within which the Company currently 
operates, the Company does not expect that SFAS 121 will have a material 
impact on the Company's financial position or results of operations.  
Therefore, the Company believes that its use of regulatory accounting 
under SFAS 71 remains appropriate.

3. Statements of Cash Flows
The following amounts of interest (net of amounts capitalized) and 
income taxes were paid for the years ending December 31:
                                              1995        1994         1993
                                              ----        ----         ----
                                                    (In thousands)
   Interest . . . . . . . . . . . . . . . .  $7,940       $7,714      $6,206
   Income Taxes (Net of refunds)  . . . . .  $2,949       $3,088      $1,920

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).  The costs of renewals and betterments 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.

AFUDC represents the composite interest and equity costs of capital 
funds used to finance construction.  AFUDC, a non-cash item, is 
recognized as a cost of "Utility Plant" with offsetting credits to 
"Other Income" and "Interest Charges."  This is in accordance with 
established regulatory ratemaking practice under which a utility is 
permitted a return on, and the recovery of, these capital costs through 
their ultimate inclusion in rate base and in the provisions for 
depreciation.

When Construction Work in Progress (CWIP) is included in rate base and 
the utility is recovering the cost of financing this construction 
through rates, no AFUDC is included in the cost of such construction.  
The VPSB generally allows CWIP in rate base for short-term construction 
projects and projects for which completion is imminent.

AFUDC, which is compounded semi-annually, was calculated using weighted 
average rates of 6.6 percent, 6.9 percent and 7.2 percent for the years 
1995, 1994 and 1993, respectively.

5. Depreciation
The Company provides for depreciation on the straight-line method based 
on the cost and estimated remaining service life of the depreciable 
property outstanding at the beginning of the year.

The annual depreciation provision was approximately 3.6 percent of total 
depreciable property at the beginning of each year 1995, 1994 and 1993.

6. Operating Revenues
Operating revenues consist principally of sales of electric energy.  The 
Company records accrued 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.

7. 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 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.

At December 31, 1995, other deferred charges totaled $11.6 million, 
consisting of repair costs for the Essex and Vergennes hydroelectric 
facilities, regulatory deferrals of storm damages, rights-of-way 
maintenance, regulatory proceedings expenses, unamortized debt expense, 
preliminary survey and investigation charges, and various other projects 
and deferrals.

8. Earnings Per Share
Earnings per share are based on the weighted average number of shares of 
common stock outstanding during each year.

9. Major Customers
The Company had one major retail customer, IBM, metered at two 
locations, that accounted for 12.9, 13.7 and 13.6 percent of operating 
revenues in 1995, 1994 and 1993, respectively.

10. 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 pension costs accrued.  The Company records annual 
expense based on amounts funded in accordance with methods approved in 
the rate-setting process.

Net pension costs reflect the following components and assumptions:
                                                      1995      1994      1993
                                                      ----      ----      ----
                                                        (Dollars in thousands)
Service cost-benefits earned during the period  .    $  687   $  768    $  748
Interest cost on projected benefit obligations  .     1,671    1,633     1,593
Actual return on plan assets  . . . . . . . . . .    (6,447)  (1,296)   (3,107)
Net amortization and deferral . . . . . . . . . .     4,232     (906)    1,141
Effect of voluntary retirement program  . . . . .       765      ---       ---
Adjustment due to actions of regulator  . . . . .      (878)    (174)      337
                                                     -------  -------   ------
Net periodic pension cost funded and recognized .    $   30   $   25    $  712
                                                     =======  =======   ======

Assumptions used to determine pension costs and the related benefit
obligation in 1995, 1994 and 1993 were:
   Discount rate . . . . . . . . . . . . . . . .       8.0%     7.5%*     8.0%
   Rate of increase in future compensation levels      5.0%     5.0%      6.0%
   Expected long-term rate of return on assets .       9.0%     9.0%      9.0%

*The discount rate used to determine the accumulated benefit obligation was
8.0%.

The following table sets forth the Plan's funded status as of December 31:
                                                      1995      1994      1993
                                                      ----      ----      ----
                                                             (In thousands)
Actuarial present value of benefit obligations:
   Accumulated benefit obligations,
     including vested benefits of $19,107,
     $18,184 and $16,825, respectively . . . . .   ($19,431) ($18,479) ($17,105)
                                                   ========= ========= =========
   Projected benefit obligations for
     service rendered to date  . . . . . . . . .   ($21,974) ($21,363) ($21,002)
Plan assets at fair value  . . . . . . . . . . .     28,685    24,171    23,981
                                                   --------- --------- ---------
Assets in excess of projected
   benefit obligations . . . . . . . . . . . . .      6,711     2,808     2,979
Unrecognized net gain from past
   experience different from that assumed  . . .     (5,188)     (285)     (272)
Prior service cost not yet recognized in net
   periodic pension cost . . . . . . . . . . . .      1,506     1,642     1,885
Unrecognized net asset at transition
   being recognized over 16.47 years . . . . . .     (1,706)   (1,934)   (2,162)
Adjustment due to actions of regulator . . . . .     (1,323)   (2,231)   (2,430)
                                                   --------- --------- ---------
Prepaid pension cost included in other assets  .   $    ---  $    ---  $    ---
                                                   ========= ========= =========

The plan assets consist primarily of cash equivalent funds, fixed income 
securities and equity securities.

In 1995, the Company offered a Voluntary Retirement Incentive Option to 
its employees which was accepted by 24 eligible participants.  This 
program, which is funded by the pension plan, resulted in an increase in 
the projected benefit obligation of $765,000 as of December 31, 1995.  
The cost of the Option will be expensed when additional funding is made 
to the pension trust.

The Company also has a supplemental pension plan for certain employees.  
Pension costs for the years ended December 31, 1995, 1994 and 1993 were 
$397,000, $381,000 and $384,000, respectively, under this plan.  This 
plan is supported through insurance contracts.

11. Fair Value of Financial Instruments
If the first mortgage bonds and preferred stock outstanding at December 
31, 1995 were refinanced using new issue debt rates of interest, which, 
on average, are lower than the Company's outstanding rates, the present 
value of those obligations would differ from the amounts outstanding on 
the December 31, 1995 balance sheet by 10 percent.  In the event of such 
a refinancing, there would be no gain or loss, inasmuch as under 
established regulatory precedent, any such difference would be reflected 
in rates and have no effect upon income.

12. Postretirement Health Care Benefits
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.

Accrued postretirement health care expenses are recovered in rates if 
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 subaccount and established 
separate VEBA trusts for its union and non-union employees.  The plan 
assets consist primarily of cash equivalent funds, fixed income 
securities and equity securities.

Net postretirement benefits costs for 1995 reflect the following 
components and assumptions:
                                                 1995       1994      1993
                                                 ----       ----      ----
                                                       (In thousands)
Accumulated postretirement benefit obligation:
   Current retirees . . . . . . . . . . . .   ($ 4,594)  ($ 3,497)  ($3,628)
   Participants currently eligible  . . . .       (681)    (1,863)   (2,288)
   All others . . . . . . . . . . . . . . .     (3,384)    (3,785)   (4,789)
                                              ---------  ---------  --------
Total accumulated postretirement benefit
   obligation . . . . . . . . . . . . . . .     (8,659)    (9,145)  (10,705)
Plan assets at fair value . . . . . . . . .      5,465      3,433       ---
                                              ---------  ---------  --------
Accumulated postretirement benefit
   obligation in excess of plan assets  . .     (3,194)    (5,712)  (10,705)
Unrecognized prior service cost . . . . . .       (929)       ---       ---
Unrecognized transition obligation  . . . .      5,982      6,485     6,845
Unrecognized net gain . . . . . . . . . . .     (1,687)    (1,777)      538
                                               --------  --------- ---------   
Prepaid (Accrued) postretirement benefit
   cost . . . . . . . . . . . . . . . . . .    $   172   ($ 1,004) ($ 3,322)
                                               ========  ========= =========



Net periodic postretirement benefit cost for 1995 includes the following
components:

                                                  1995       1994      1993
                                                        (In thousands)
Service cost . . . . . . . . . . . . . . . .   $   224    $   407   $   438
Interest cost  . . . . . . . . . . . . . . .       697        864       940
Actual return on plan assets . . . . . . . .      (586)      (127)      ---
Deferred asset loss/(gain) . . . . . . . . .       264       (107)      ---
Recognition of transition obligation,
   net of amortization . . . . . . . . . . .       234        361       380
                                               -------    -------   -------
Total net periodic postretirement
   benefit cost  . . . . . . . . . . . . .     $   833    $ 1,398   $ 1,758
                                               =======    =======   =======

Assumptions used to determine postretirement benefit costs and the related
benefit obligation were:

                                                  1995       1994      1993
                                                  ----       ----      ----
Discount rate to determine postretirement
  benefit costs .  . . . . . . . . . . . . .      8.5%       7.5%      8.0%
Discount rate to determine postretirement
  benefit obligation . . . . . . . . . . . .      8.5%       8.5%      8.0%
Expected long-term rate of return on assets       7.5%       7.5%      9.0%

For measurement purposes, a 6.2 percent annual rate of increase in the 
per capita cost of covered benefits was assumed for 1995; the rate was 
assumed to decrease gradually to 5.0 percent by the year 2001 and remain 
at that level thereafter.  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 would increase the accumulated postretirement benefit obligation 
as of December 31, 1995 by $1.4 million and the aggregate of the service 
and interest components of net periodic postretirement benefit cost for 
the year ended December 31, 1995 by $200,000.

13. Deferred Credits
The Company has other deferred credits and long-term liabilities of 
$21.6 million, consisting of operating lease equalization, reserves for 
damage claims and environmental liabilities and accruals for employee 
benefits.

14. 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.

15. Reclassification
Certain items on the prior years' financial statements have been 
reclassified for consistent presentation with the current year.


B. Investments in Associated Companies
The Company accounts for investments in the following companies by the 
equity method:
                                                    Investment in Equity
                          Percent Ownership             December 31,     
                        at December 31, 1995        1995            1994
                        --------------------        ----            ----
                                                       (In thousands)
VELCO - Common . . . . . . . . .  29.5%          $ 1,811          $ 1,814
      - Preferred  . . . . . . .  30.0%            1,278            1,418
                                                 -------          -------
Total VELCO  . . . . . . . . . .                   3,089            3,232

Vermont Yankee - Common  . . . .  17.9%            9,631            9,766
New England Hydro-Transmission -
     Common  . . . . . . . . . .  3.18%            1,296            1,398
New England Hydro-Transmission
     Electric - Common . . . . .  3.18%            2,008            2,288
                                                 -------          -------
                                                 $16,024          $16,684
                                                 =======          =======

Undistributed earnings in associated companies totaled $666,000 at
December 31, 1995.

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 bills all costs, including interest on debt and a 
fixed return on equity, to the State and others using the system.  The 
Company's purchases of transmission services from VELCO were 
$7.6 million, $7.9 million and $8.0 million for the years 1995, 1994 and 
1993, 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.

Summarized financial information for VELCO is as follows:
                                                       December 31,      
                                                 1995      1994       1993
                                                 ----      ----       ----
                                                      (In thousands)
Company's equity in net income . . . . . . .   $   377   $   386    $   406
                                               =======   =======    =======
Total assets . . . . . . . . . . . . . . . .   $71,668   $69,724    $70,199
Less:
   Liabilities and long-term debt  . . . . .    61,238    58,850     58,806
                                               -------   -------    -------     
Net assets . . . . . . . . . . . . . . . . .   $10,430   $10,874    $11,393
                                               =======   =======    =======
Company's equity in net assets . . . . . . .   $ 3,089   $ 3,232    $ 3,388
                                               =======   =======    =======
Vermont Yankee
The Company is responsible for 17.3 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 535 megawatts.  
Vermont Yankee's current estimate of decommissioning is approximately 
$347 million, of which $141 million has been funded.  At December 31, 
1995, the Company's portion of the net unfunded liability was 
$36 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 1995, the Company 
incurred $27.7 million in Vermont Yankee annual capacity charges, which 
included $1.8 million for interest charges.  The Company's share of 
Vermont Yankee's long-term debt at December 31, 1995 was $13.1 million.

The Price-Anderson Act currently limits public liability from a single 
incident at a nuclear power plant to $8.9 billion.  Any liability beyond 
$8.9 billion is indemnified under an agreement with the Nuclear 
Regulatory Commission, 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 
$8.7 billion per incident by assessing retrospective premiums of 
$79.3 million against each of the 110 reactor units in the United States 
that are currently subject to the Program, limited to a maximum 
assessment of $10 million per incident per nuclear unit in any one year.  
The maximum assessment is to be adjusted at least every five years to 
reflect inflationary changes.

The above insurance covers all workers employed at nuclear facilities 
prior to January 1, 1988, for bodily injury claims.  Vermont Yankee has 
purchased a master worker insurance policy with limits of $200 million 
with one automatic reinstatement of policy limits to cover workers 
employed on or after January 1, 1988.  Vermont Yankee's estimated 
contingent liability for a retrospective premium on the master worker 
policy as of December 1995 is $3.1 million.  The secondary financial 
protection program referenced above provides coverage in excess of the 
Master Worker policy.

Insurance has been purchased from Nuclear Electric Insurance Limited 
(NEIL II and NEIL III) to cover the costs of property damage, 
decontamination or premature decommissioning resulting from a nuclear 
incident.  All companies insured with NEIL II and III are subject to 
retroactive assessments if losses exceed the accumulated funds 
available.  The maximum potential assessment against Vermont Yankee with 
respect to NEIL II losses arising during the current policy year is 
$14.0 million and the NEIL III maximum retroactive assessment is 
$7.0 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.

Summarized financial information for Vermont Yankee is as follows:
                                                       December 31,       
                                                 1995       1994       1993
                                                 ----       ----       ---- 
                                                       (In thousands)
Earnings:
   Operating revenues . . . . . . . . . . .   $180,437   $162,757   $180,145
   Net income applicable to common stock  .      6,790      6,588      7,793
   Company's equity in net income . . . . .      1,171      1,143      1,425
Total assets  . . . . . . . . . . . . . . .   $531,293   $512,142   $469,770
Less:
   Liabilities and long-term debt . . . . .    477,350    457,669    415,606
                                              --------   --------   --------
Net assets  . . . . . . . . . . . . . . . .   $ 53,943   $ 54,473   $ 54,164
                                              ========   ========   ========
Company's equity in net assets  . . . . . .   $  9,631   $  9,766   $  9,745
                                              ========   ========   ========


C. Common Stock Equity
The Company maintains a Dividend Reinvestment and Stock Purchase Plan 
(DRIP) under which 659,107 shares were reserved and unissued at December 
31, 1995.  The Company also funds an Employee Savings and Investment 
Plan (ESIP).  At December 31, 1995, there were 29,544 shares reserved 
and unissued under the ESIP.

During 1995, the Company's Board of Directors, with subsequent approval 
of the Company's common shareholders, adopted the Compensation Program 
for Officers and Certain Key Management Personnel.  Participants are 
entitled to receive cash and restricted and unrestricted stock grants in 
predetermined proportions.  Participants who receive restricted stock 
are entitled to receive dividends and have voting rights but assumption 
of full beneficial ownership is contingent upon two restrictions of a 
five year duration, including no transferability and forfeiture of the 
stock upon termination of employment with the Company.  Participants who 
receive unrestricted stock assume full beneficial ownership upon grant 
and may retain or sell such shares.  During 1995, 11,926 shares of 
common stock were awarded.  At December 31, 1995, there were 38,074 
shares reserved and unissued under the Compensation Program.

Changes in common stock equity for the years ended December 31, 1993, 
1994 and 1995 are as follows:

<TABLE>
<CAPTION>


                                                Common Stock                                   Treasury Stock
                                         ------------------------  Paid-in     Retained  ------------------------   Stock
                                            Shares      Amount     Capital     Earnings     Shares      Amount      Equity
                                            ------      ------     -------     --------     ------      ------      ------
                                                                             (Dollars in thousands)

<S>                                        <C>           <C>         <C>         <C>          <C>          <C>       <C>
BALANCE, December 31, 1992...............  4,413,537     $14,712     $53,510     $24,801      15,856       ($378)    $92,645

Common Stock Issuance:
  DRIP...................................     86,974         290       2,586                                           2,876
  ESIP...................................     35,531         118       1,082                                           1,200
Net Income...............................                                         10,631                              10,631
Cash Dividends on Capital Stock:
  Common Stock      -$2.11 per share.....                                         (9,396)                             (9,396)
  Preferred Stock   -$4.75 per share.....                                            (19)                                (19)
                    -$7.00 per share.....                                            (38)                                (38)
                    -$9.375 per share....                                           (146)                               (146)
                    -$8.625 per share....                                           (604)                               (604)
                                         ------------------------------------------------------------------------------------
BALANCE, December 31, 1993...............  4,536,042      15,120      57,178      25,229      15,856        (378)     97,149

Common Stock Issuance:
  DRIP...................................    109,959         367       2,472                                           2,839
  ESIP...................................     31,511         105         728                                             833
Net Income...............................                                         11,002                              11,002
Cash Dividends on Capital Stock:
  Common Stock      -$2.12 per share.....                                         (9,713)                             (9,713)
  Preferred Stock   -$4.75 per share.....                                            (18)                                (18)
                    -$7.00 per share.....                                            (38)                                (38)
                    -$9.375 per share....                                           (131)                               (131)
                    -$8.625 per share....                                           (604)                               (604)
                                         ------------------------------------------------------------------------------------
BALANCE, December 31, 1994...............  4,677,512      15,592      60,378      25,727      15,856        (378)    101,319

Common Stock Issuance:
  DRIP...................................    125,046         417       2,731                                           3,148
  ESIP...................................     36,012         120         829                                             949
  Compensation Program:..................
    Restricted Shares....................      8,100          27         182                                             209
    Stock Grant..........................      3,826          12          86                                              98
Net Income...............................                                         11,503                              11,503
Cash Dividends on Capital Stock:
  Common Stock      -$2.12 per share.....                                        (10,047)                            (10,047)
  Preferred Stock   -$4.75 per share.....                                            (15)                                (15)
                    -$7.00 per share.....                                            (36)                                (36)
                    -$9.375 per share....                                           (116)                               (116)
                    -$8.625 per share....                                           (604)                               (604)
                                         ------------------------------------------------------------------------------------
BALANCE, December 31, 1995...............  4,850,496     $16,168     $64,206     $26,412      15,856       ($378)   $106,408
                                         ====================================================================================

</TABLE>

Dividend Restrictions
Certain restrictions on the payment of cash dividends on common stock 
are contained in the indentures relating to long-term debt and in the 
Restated Articles of Association.  Under the most restrictive of such 
provisions, $20.3 million of retained earnings were free of restrictions 
at December 31, 1995.

The properties of the Company include several hydroelectric projects 
licensed under the Federal Power Act, with license expiration dates 
ranging from 1993 to 2022.  At December 31, 1995, $302,000 of retained 
earnings 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 the placement of restrictions on 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 a 
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 certain classes of preferred 
stock are as follows:

Purchase and Sinking Fund
-------------------------
  8.625%, Class D, Series 3  . .  September 1    14,000 Shares
  4.75%, Class B . . . . . . . .  December 1        450 Shares
  7%, Class C  . . . . . . . . .  December 1        450 Shares
  9.375%, Class D, Series 1  . .  December 1      1,600 Shares

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 is $1,650,000.

All of the 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.  The redemption 
premium for the Class D, Series 3, is $3.835 per share until September 
1, 1996; $2.877 per share from September 1, 1996 to September 1, 1997; 
$1.919 per share from September 1, 1997 to September 1, 1998; and $0.916 
per share from September 1, 1998 to September 1, 1999, after which there 
is no redemption premium.

No shares of Class E preferred stock were issued as of December 31, 
1995.

E. Long-term Debt
Utility
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 annual sinking fund requirements (excluding 
amounts that may be satisfied by property additions) and long-term debt 
maturities for the next five years are:
                                  Sinking
                                   Funds    Maturities     Total
                                  -------   ----------     -----
                                           (In thousands)

1996 . . . . . . . . . . . . . .   $4,833      $3,000     $7,833
1997 . . . . . . . . . . . . . .    3,500       1,334      4,834
1998 . . . . . . . . . . . . . .    3,500       3,000      6,500
1999 . . . . . . . . . . . . . .    3,500         ---      3,500
2000 . . . . . . . . . . . . . .    1,700       6,800      8,500

Non-Utility
At December 31, 1995, Green Mountain Propane Gas Company, the Company's 
propane subsidiary, had long-term debt of $3,900,000, which was secured 
by substantially all of the subsidiary's assets, and Mountain Energy, 
Inc., the Company's subsidiary that invests in electric energy 
generation and efficiency projects, had unsecured long-term debt of 
$1,916,667.  The annual sinking fund requirements and maturities for the 
next five years are:
                                  Sinking
                                   Funds    Maturities     Total
                                  -------   ----------     -----
                                          (In thousands)

1996 . . . . . . . . . . . . .     $1,167      $  ---     $1,167
1997 . . . . . . . . . . . . .      1,167         ---      1,167
1998 . . . . . . . . . . . . .      1,167         ---      1,167
1999 . . . . . . . . . . . . .        167         900      1,067
2000 . . . . . . . . . . . . .         83       1,167      1,250

F. Short-term Debt
Utility
At December 31, 1995, the Company had lines of credit with six banks 
totaling $40.0 million, with borrowings outstanding of $8.4 million.  
Borrowings under these lines of credit are at interest rates based on 
various market rates and are generally less than the prime rate.  The 
Company has fee arrangements on its lines of credit ranging from 1/8 to 
1/4 percent and no compensating balance requirements.  These lines of 
credit are subject to periodic review and renewal during the year by the 
various banks.

The weighted average interest rate on borrowings outstanding on December 
31, 1995 and December 31, 1994 was 6.3 percent and 6.4 percent, 
respectively.

Non-Utility
At December 31, 1995, Green Mountain Propane Gas Company, the Company's 
propane subsidiary, had a line of credit with a bank for $1.5 million, 
with $150,000 outstanding.

G. Income Taxes
Utility
The Company accounts for income taxes using an asset and liability 
approach.  This approach accounts for deferred income taxes by applying 
statutory rates in effect at year end to the differences between the 
book and tax bases of assets and liabilities.

The regulatory assets and liabilities represent taxes that will be 
collected from or returned to customers through rates in future periods.  
As of December 31, 1995 and 1994, the net regulatory assets were 
$690,000 and $187,000, respectively.

The temporary differences which gave rise to the net deferred tax 
liability at December 31, 1995 and December 31, 1994, were as follows:

                                          At December 31,   At December 31,
                                               1995               1994     
                                          ---------------   ---------------
                                                   (In thousands)
Deferred Tax Assets
 Contributions in aid of construction        $ 6,361            $ 5,857 
 Deferred compensation and
   postretirement benefits . . . . . .         2,931              2,296 
 Alternative minimum tax credit  . . .          (661)              (829)
 Excess deferred taxes . . . . . . . .         1,990              2,089 
 Unamortized investment tax credits  .         2,151              2,277 
 Other . . . . . . . . . . . . . . . .         2,982              3,352 
                                             -------            -------
                                             $15,754            $15,042 
                                             =======            =======
Deferred Tax Liabilities
 Property-related and other  . . . . .       $28,009            $26,314
 Demand side management costs  . . . .         6,685              6,457
 Deferred purchased power costs  . . .         2,901                174
 Reversal of previously flowed-through
   tax depreciation  . . . . . . . . .         2,816              3,499 
 AFUDC equity basis adjustment . . . .           635                680 
                                            --------           --------
                                              41,046             37,124 
                                            --------           --------
Net accumulated deferred income tax
   liability . . . . . . . . . . . . .      ($25,292)          ($22,082)
                                            =========          =========

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:

                                                    Year End December 31,  
                                                 1995       1994       1993
                                                 ----       ----       ----
                                                        (In thousands)
Net change in deferred income tax
  liability per above table . . . . . . . . .   $3,210     $1,080    $4,677
Change in income tax related regulatory
  assets and liabilities. . . . . . . . . . .      503        505       503
Change in alternative minimum tax credit  . .      168     (1,578)      444
IRS audit adjustment, 1989 - 90 . . . . . . .      255        ---       405
                                                ------     ------    ------
Deferred income tax expense for the period  .   $4,136     $    7    $6,029
                                                ======     ======    ======

The components of the provision for income taxes are as follows:

                                            Year Ended December 31,
                                           1995        1994        1993
                                           ----        ----        ----
                                                 (In thousands)
Current state income taxes . . . . . . . $   365    $ 1,205      $  134
Deferred state income taxes  . . . . . .     897         70       1,225
Current federal income taxes . . . . . .   1,359      4,466         369
Deferred federal income taxes  . . . . .   3,239        (63)      4,804
Investment tax credits -- net  . . . . .    (282)      (283)       (284)
                                          -------    -------     -------
Total income taxes . . . . . . . . . . .   5,578      5,395       6,248
Amounts included in "Other income" . . .      --         --           1
                                          ------     ------      ------
Income taxes charged to operations . . .  $5,578     $5,395      $6,249
                                          ======     ======      ======  

The following table details the components of the provisions for deferred
federal income taxes:

                                             Year Ended December 31,
                                           1995        1994         1993
                                           ----        ----         ----
                                                 (In thousands)
Deferred purchased power costs  . . . .   $2,351     $(1,310)     $  985
Excess tax depreciation . . . . . . . .    1,652       1,387       1,417
Demand side management  . . . . . . . .      197       1,013       2,090
State tax benefit . . . . . . . . . . .     (304)         39        (416)
Contributions in aid of construction  .     (435)       (657)       (440)
Supplemental benefit plans  . . . . . .     (266)         26        (198)
Postretirement health care benefits . .     (281)        824         (95)
Pine Street . . . . . . . . . . . . . .     (191)     (1,915)        890
Other . . . . . . . . . . . . . . . . .      516         530         571
                                          ------      -------     ------
Total deferred federal income taxes . .   $3,239      $  (63)     $4,804
                                          ======      =======     ======

Total federal income taxes differ from the amounts computed by applying
the statutory tax rate to income before taxes.  The reasons for the
differences are as follows:

                                             Year Ended December 31,
                                           1995        1994        1993
                                           ----        ----        ----
                                             (Dollars in thousands)
Income before income tax . . . . . . .   $17,081     $16,398     $16,880
Federal statutory rate . . . . . . . .        34%         34%         34%
Computed "expected" federal
  income taxes . . . . . . . . . . . .   $ 5,808     $ 5,575     $ 5,739
Increase (decrease) in taxes
  resulting from:
  Tax versus book depreciation . . . .       327         327         327
  Dividends received and paid credit .      (616)       (499)       (580)
  AFUDC - equity funds . . . . . . . .        (9)        (89)        (93)
  Amortization of ITC  . . . . . . . .      (282)       (283)       (284)
  State tax benefit  . . . . . . . . .      (429)       (433)       (462)
  Excess deferred taxes  . . . . . . .       (60)        (60)        (60)
  Taxes attributable to subsidiaries .      (401)       (268)        156
  Other  . . . . . . . . . . . . . . .       (22)       (150)        146
                                         --------    --------    -------
Total federal income taxes . . . . . .   $ 4,316     $ 4,120     $ 4,889
                                         ========    ========    =======
Effective federal income tax rate  . .      25.3%       25.1%       28.9%

Non-Utility
The Company's non-utility subsidiaries had accumulated deferred income 
taxes of $3.2 million on their balance sheets at December 31, 1995, 
largely attributable to property-related transactions.

The components of the provision for income taxes for the non-utility 
operations are:
                                             Year Ended December 31,
                                           1995        1994        1993
                                           ----        ----        ----
                                                  (In thousands)
State income taxes . . . . . . . . . .      $165        $123      $ (58)
Federal income taxes . . . . . . . . .       613         444       (224)
Investment tax credits . . . . . . . .       (45)        (45)       (45)
                                            -----       -----     ------
Income taxes charged to operations . .      $733        $522      $(327)
                                            =====       =====     ======

Total federal income taxes differ from the amounts computed by applying 
the statutory rate to income before taxes, primarily attributable to 
state tax benefits.

The effective federal income tax rates for the non-utility operations 
were 29.7 percent, 29.0 percent and 34.2 percent for the years ended 
December 31, 1995, 1994 and 1993, respectively.

H. 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.

                                               1995 Quarter Ended
                                  March    June    Sept.     Dec.     Total
                                  -----    ----    -----     ----     -----
                                  (Amounts in thousands, except per share)
Operating Revenues . . . . . .  $40,023  $37,127  $39,781  $44,613  $161,544
Operating Income . . . . . . .    4,482    2,770    3,826    4,217    15,295
Net Income . . . . . . . . . .    3,227    1,992    3,071    3,213    11,503
Net Income Applicable to
  Common Stock . . . . . . . .    3,033    1,798    2,877    3,024    10,732
Earnings per Average Share of
  Common Stock . . . . . . . .    $0.65    $0.38    $0.60    $0.63     $2.26
Weighted Average Number of
  Common Shares Outstanding  .    4,680    4,721    4,771    4,815     4,747

                                            1994 Quarter Ended
                                  March    June    Sept.     Dec.     Total
                                  -----    ----    -----     ----     -----
                                  (Amounts in thousands, except per share)
Operating Revenues . . . . . .  $40,611  $33,603  $36,684  $37,299  $148,197
Operating Income . . . . . . .    4,892    1,872    3,243    4,510    14,517
Net Income . . . . . . . . . .    4,040    1,237    2,653    3,072    11,002
Net Income Applicable to
  Common Stock . . . . . . . .    3,841    1,038    2,454    2,875    10,208
Earnings per Average Share of
  Common Stock . . . . . . . .    $0.85    $0.23    $0.54    $0.61     $2.23
Weighted Average Number of
  Common Shares Outstanding  .    4,537    4,564    4,605    4,644     4,588

I. Commitments and Contingencies
1. Environmental Matters
In 1982, the United States Environmental Protection Agency (EPA) 
notified the Company that the EPA, pursuant to the Comprehensive 
Environmental Response, Compensation and Liability Act of 1980 (CERCLA), 
was considering spending public funds to investigate and take corrective 
action involving claimed releases of allegedly hazardous substances at a 
site identified as the Pine Street Marsh in Burlington, Vermont.  On 
part of this site was located a manufactured-gas facility owned and 
operated by a number of separate enterprises, including the Company, 
from the late 19th century to 1967.  In its notice, the EPA stated that 
the Company may be a "potentially responsible party" (PRP) under CERCLA 
from which reimbursement of costs of investigation and of corrective 
action may be sought.  On February 23, 1988, the Company received a 
Special Notice letter from the EPA stating that the letter constituted a 
formal demand for reimbursement of costs, including interest thereon, 
that were incurred and were expected to be incurred in response to the 
environmental problems at the site.

On December 5, 1988, the EPA brought suit against the Company, New 
England Electric System, and Vermont Gas Systems, Inc. in the United 
States District Court for the District of Vermont seeking reimbursement 
for costs it incurred in conducting activities in 1985 to remove 
allegedly hazardous substances from the site, and requested a 
declaratory judgment that the Company and the other defendants are 
liable for all costs that have been incurred since the removal and that 
continue to be incurred in responding to claims of releases or 
threatened releases from the Maltex Pond Area -- the portion of the site 
where the removal action occurred.  The complaint specifically alleged 
that the EPA expended at least $741,000 during the 1985 removal action 
and sought interest on this amount from the date the funds were expended 
and costs of litigation, including attorneys' fees.  The Company entered 
a cross-claim against New England Electric System and third-party claims 
against UGI Corporation, Southern Union Corporation, the State of 
Vermont, and an individual property owner at the site for recovery of 
its response costs and for contribution.  Fourth-party defendants 
subsequently were joined.

In July 1990, the Company and other parties signed a proposed Consent 
Decree settling the removal action litigation.  All 14 settling 
defendants contributed to the aggregate settlement amount of $945,000.  
Individual contributions were treated as confidential under the proposed 
Consent Decree.  On December 26, 1990, upon the unopposed motion of the 
United States, the Consent Decree was entered by the Court.

During the summer and fall of 1989, the EPA conducted the initial phase 
of the Remedial Investigation (RI) and commenced the Feasibility Study 
(FS) relating to the site.  In the fall of 1990 and in 1991, the EPA 
conducted a second phase of RI work and studied the treatability of 
soils and groundwater at the site.  In the fall of 1991, the EPA 
responded favorably to a request from the Company and other PRPs to 
participate in informal discussions on the EPA's ongoing investigation 
and evaluation of the site, and invited the Company and other interested 
parties to share technical information and resources with the EPA that 
might assist it in evaluating remedial options.

On November 6, 1992, the EPA released its final RI/FS and announced a 
proposed remedy with an estimated present value total cost of 
approximately $47.0 million.  This amount included 30 years' estimated 
operation and maintenance costs, with a net present value of 
approximately $26.4 million.  The EPA's preferred remedy called for 
construction of a Containment/Disposal Facility (CDF) over a portion of 
the site.  The CDF would have consisted of subsurface vertical barriers 
and a low permeability cap, with collection trenches and hydraulic 
control system to capture groundwater and prevent its migration outside 
of the CDF.  Collected groundwater would have been treated and 
discharged or stored and disposed of off-site.  The proposed remedy also 
would have required construction of new wetlands to replace those that 
would be destroyed by construction of the CDF and a long-term monitoring 
program.

On or before May 15, 1993, the PRP group in which the Company 
participated submitted extensive comments to the EPA opposing the 
proposed remedy.  In response to an earlier request from the EPA, the 
PRP group also submitted a detailed analysis of an alternative remedy 
anticipated to cost approximately $20 million.  In early June, in 
response to overwhelming negative comment, the EPA withdrew its proposed 
remedy and announced that it would work with all interested parties in 
developing a new proposal.  Since then, the EPA has established a 
coordinating council, with representatives of PRPs, environmental 
groups, and government agencies, and presided over by a neutral 
facilitator.  The council is charged with determining what additional 
studies may be appropriate for the site and also is planning to 
eventually address additional response activities.

In July 1994, the Company, New England Electric System (NEES), and 
Vermont Gas Systems, Inc. (VGS), entered into an Administrative Order by 
Consent, with the EPA, pursuant to which these PRPs are conducting 
certain additional studies that have been agreed to by the coordinating 
council.  These studies constitute the first phase of action the council 
has decided on to fill data gaps at the site.  A second phase, including 
tasks carried over from the first phase, additional field studies and 
preparation of an addendum feasibility study was begun during 1995 by 
the same parties under a second Order.  The EPA has not required 
reimbursement for its past RI/FS study costs as a condition to allowing 
the PRPs to conduct these additional studies.  The EPA has previously 
advised the Company that ultimately it will seek to hold the Company and 
the PRPs liable for such costs.  These costs have been estimated to be 
at least $4.5 million, but the Company has sufficient reserves on its 
balance sheet to cover such costs.

On December 1, 1994, the Company, NEES and VGS entered into a 
confidential agreement with the State, the City of Burlington and nearly 
all other landowner PRPs under which the liability of those landowner 
PRPs for future Superfund response costs would be limited and specified.  
On December 1, 1994, the Company entered into a confidential agreement 
with VGS compromising contribution and cost recovery claims of each 
party and contractual indemnity claims of the Company arising from the 
1964 sale of the manufactured gas plant to VGS, and also entered into a 
confidential agreement with NEES for funding of work under the Order.

In December 1991, the Company brought suit against several previous 
insurers seeking recovery of unrecovered past costs and indemnity 
against future liabilities associated with environmental problems at the 
site.  Discovery in the case is largely complete, with the exception of 
expert discovery, which was stayed by the magistrate pending the 
resolution of Summary Judgment Motions filed by the Company.  In August 
1994, the Magistrate granted the Company's Motion for Summary Judgment 
with respect to defense costs against one defendant and denied it 
against another defendant.  The United States District Judge affirmed 
those orders on September 30, 1994.

The Company has reached confidential settlements with two of the 
defendants in its insurance litigation.  One of these defendants 
provided the Company with comprehensive general liability insurance 
between 1976 and 1982, and with environmental impairment liability 
insurance from 1981 to 1984.  These policies were in place in 1982 when 
the EPA first notified the Company that it might be a potentially 
responsible party at the Pine Street Marsh site.  The other defendant 
provided the Company with second layer excess liability coverage for a 
seven-month period in 1976.

The Company has deferred amounts received from third parties pending 
resolution of the Company's ultimate liability with respect to the site 
and rate recognition of that liability.  The Company is unable to 
predict at this time the magnitude of any liability resulting from 
potential claims for the costs of the RI/FS or the performance of any 
remedial action, or the likely disposition or magnitude of claims the 
Company may have against others, including its insurers, except to the 
extent described above.

Through rate cases filed in 1991, 1993 and 1994, the Company has sought 
and received recovery for ongoing expenses associated with the Pine 
Street Marsh site.  Specifically, the Company proposed rate recognition 
of its unrecovered expenditures between January 1991 and June 30, 1994 
(in the total of approximately $7.3 million) for technical consultants 
and legal assistance in connection with the EPA's enforcement actions at 
the site and insurance litigation.  While reserving the right to argue 
in the future about the appropriateness of rate recovery for Pine Street 
Marsh related costs, the Company and the Vermont Department of Public 
Service (the Department) reached agreements in these cases that the full 
amount of Pine Street Marsh costs reflected in those rate cases should 
be recovered in rates.  The Company's rates approved by the VPSB on 
April 2, 1992, on May 13, 1994, and on June 5, 1995, reflected the Pine 
Street Marsh related expenditures referred to above.

In a rate case filed on September 15, 1995, the Company sought recovery 
in rates of approximately $1.3 million in expenses associated with the 
Pine Street site.  This amount represented the Company's unrecovered 
expenditures between July 1994 and June 1995 for technical consultants 
and legal assistance in connection with EPA's enforcement action at the 
site and insurance litigation.  While reserving the right to argue in 
the future about the appropriateness of rate recovery for Pine Street 
related costs (and whether recovery or non-recovery of past costs and 
any insurance proceeds is relevant to such issue), the parties to the 
case have reached agreement that the full amount of Pine Street costs 
reflected in the Company's 1995 rate case should be recovered in rates.  
This agreement is currently pending before the VPSB.

Management expects to seek and (assuming treatment consistent with the 
previous regulatory treatment set forth above) receive ratemaking 
treatment for unreimbursed costs incurred beyond the amounts for which 
ratemaking treatment has been received.

2. Operating Leases
The Company has an operating lease for its corporate headquarters 
building and two of its service center buildings, including related real 
estate.  This lease has a base term of 25 years, ending June 30, 2009, 
with renewal options aggregating another 25 years.  The annual lease 
charges will total $983,000 for each of the years 1996 through 2008 and 
$574,000 for 2009.  The Company has options to purchase the buildings at 
fair market value at the end of the base term and at the end of each 
renewal period.

3. Jointly-Owned Facilities
The Company had joint-ownership interests in electric generating and 
transmission facilities at December 31, 1995, as follows:

                            Ownership  Share of       Utility   Accumulated
                             Interest  Capacity        Plant    Depreciation
                            ---------  --------       -------   ------------
                               (In %)     (In MW)        (In thousands)
Highgate  . . . . . . . . . .   33.8        67.6      $ 9,730       $2,816
McNeil  . . . . . . . . . . .   11.0         5.9      $ 8,555       $2,981
Stony Brook (No. 1) . . . . .    8.8        30.2      $10,039       $5,520
Wyman (No. 4) . . . . . . . .    1.1         6.8      $ 2,376       $1,234
Metallic Neutral Return (1) .   59.4         ---      $ 1,563       $  306

(1)	Neutral conductor for NEPOOL/Hydro-Quebec Interconnection

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



4. Rate Matters
1995 Retail Rate Case -- On September 15, 1995, the Company filed a 
request with the VPSB to increase retail rates by 12.7 percent.  The 
increase is needed to cover higher power supply costs, to support 
additional investment in plant and equipment, to fund expenses 
associated with the Pine Street site, and to cover higher costs of 
capital.

The Company and the Department reached a settlement agreement providing 
for a 5.25 percent retail rate increase effective June 1, 1996, and a 
target return on equity for utility operations of 11.25 percent.  The 
settlement was based on a newly negotiated agreement with Hydro-Qu bec 
that will result in a reduction of the Company's power supply costs 
below that which was anticipated, allowing the Company to reduce the 
amount of its rate request.  The rate settlement must be reviewed and 
approved by the VPSB before it can take effect.

1994 Retail Rate Case -- On September 24, 1994, the Company filed a 
request with the VPSB to increase retail rates by 13.9 percent.  The 
increase was needed primarily to cover the rising cost of existing power 
sources, the cost of new power sources the Company has secured to 
replace power supply that will be lost in the near future, and the cost 
of energy efficiency programs the Company has implemented for its 
customers.  The Company, the Department and the other parties reached a 
settlement agreement providing for a 9.25 percent retail rate increase 
effective June 15, 1995, and a target return on equity for utility 
operations of 11.25 percent.  The agreement was approved by the VPSB on 
June 9, 1995.

1993 Retail Rate Case -- On October 1, 1993, the Company filed a request 
with the VPSB to increase retail rates by 8.6 percent.  The increase was 
needed primarily to cover the cost of buying power from independent 
power producers, the cost of energy conservation programs, the cost of 
plant additions made in the past two years, and costs incurred in 1992 
and 1993 associated with the Company's response to the EPA's RI/FS and 
proposed remedy at the Pine Street Marsh site and with the Company's 
litigation against its previous insurers seeking recovery of past costs 
incurred and indemnity against future liabilities in connection with the 
site.  On January 28, 1994, the Company and the other parties in the 
proceeding reached a settlement agreement providing for a 2.9 percent 
retail rate increase effective June 15, 1994, and a target return on 
equity for utility operations of 10.5 percent.  The settlement agreement 
also provided for the Company's recovery in rates of $4.2 million in 
costs associated with the Pine Street Marsh site, as described herein 
above.  The agreement was approved by the VPSB on May 13, 1994.

1991 Retail Rate Case -- On July 19, 1991, the Company filed a request 
with the VPSB to increase retail rates by 9.96 percent to cover power 
supply cost increases expected in 1992; the costs of upgrading and 
maintaining the Company's generation, transmission and distribution 
facilities; expenditures associated with the Company's conservation 
programs; and higher employee pension and health care costs.  In orders 
dated April 2, 1992 and May 21, 1992, the VPSB approved an increase of 
5.6 percent, or approximately $6.6 million, effective April 2, 1992.

The Department appealed the VPSB orders challenging, among other 
rulings, the VPSB's acceptance of the Company's method of treating 
accumulated depreciation and certain Vermont Yankee-related power costs.  
The Company filed a cross-appeal contending, among other things, that 
the VPSB had erred in reducing ratebase relating to certain demand-side 
management (DSM) program cost projections that had been made in the 
Company's prior rate case.

On April 22, 1994, the Vermont Supreme Court affirmed in part and 
reversed in part the VPSB orders.  The Court overturned the VPSB's 
decision disallowing certain DSM costs.  The impact of this portion of 
the Court's ruling resulted in the Company's other income since April 
1992 being increased by $162,000.  On the other hand, the Court 
overturned the VPSB decision in the Company's favor on an issue 
involving the method of treating accumulated depreciation, and on the 
inclusion of one item of Vermont Yankee's capital projections in power 
costs.  The overall impact of the Court's ruling resulted in a reduction 
of $840,000 in the Company's revenues in 1994.

5. 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-Qu bec, provided for the construction of the second 
phase (Phase II) of the interconnection between the New England electric 
systems and that of Hydro-Qu bec.  Phase II expands the Phase I 
facilities from 690 megawatts to 2,000 megawatts and provides for 
transmission of Hydro-Qu bec 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, 1995, the 
present value of the Company's obligation is $9.8 million.

Projected future minimum payments under the Phase II support agreements 
are as follows:
     Year ending December 31,
     1996 . . . . . . . . . . .  $  488,924
     1997 . . . . . . . . . . .     488,924
     1998 . . . . . . . . . . .     488,924
     1999 . . . . . . . . . . .     488,924
     2000 . . . . . . . . . . .     488,924
     Total for 2001-2020  . . .   7,333,867
                                 ----------
                                 $9,778,487
                                 ==========

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 (amounts necessary to retire the principal of 
and to pay the interest on the portion of the related long-term debt 
ascribed to the Company) whether or not the production plants are 
operating.  The cost of power obtained under such long-term contracts, 
including payments required to be made 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 1995 follows:

                                                      Stony     Vermont
                                       Merrimack      Brook      Yankee
                                       ---------      -----     -------
                                             (Dollars in thousands)
Plant capacity . . . . . . . . . . .      320.0 MW   343.0 MW    535.0 MW
Company's share of output  . . . . .        8.9%       4.4%       17.3%
Contract period  . . . . . . . . . .  1968-1998         (1)         (2)
Company's annual share of:
  Interest . . . . . . . . . . . . .     $  606     $  245     $ 1,840
  Other debt service . . . . . . . .        329        296         ---
  Other capacity . . . . . . . . . .      1,759        406      25,899
                                         ------     ------     -------
Total annual capacity  . . . . . . .     $2,694     $  947     $27,739
                                         ======     ======     =======
Company's share of long-term debt  .     $  919     $4,825     $13,121
                                         ======     ======     =======

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

2. Hydro-Quebec System Power Purchases
Under various contracts approved by the VPSB, 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 purchases pursuant to the contract with Hydro-Quebec 
entered into December 4, 1987 are as follows:  (1) Schedule A -- 17 
megawatts (MW) of firm capacity and associated energy to be delivered at 
the Highgate interconnection for five years beginning 1990; (2) 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 (3) Schedule C3 -- 46 megawatts of firm capacity and 
associated energy to be delivered at interconnections to be determined 
at a later time for 20 years beginning in November 1995.

At present, the Schedule C3 purchases are being delivered over the 
Company's entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase 
I and Phase II).  By use of the interconnection for Schedule C3 or other 
power transactions, the Company foregoes certain savings associated with 
other power deliveries for NEPOOL that would take place if the 
interconnection were not utilized for firm purchases. (Please also see 
description of the 1996 arrangement described below).

In September 1994, the Company negotiated a renewal of a short-term 
"tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec 
delivers up to 61 megawatts of capacity and energy to the Company over 
the NEPOOL/Hydro-Quebec interconnection.  The electricity purchased 
under this tertiary contract is priced at less than 2.5 cents per 
kilowatthour.  The benefits realized by the Company from this favorably 
priced electricity will be greater than those associated with deliveries 
foregone by the Company otherwise available over the NEPOOL/Hydro-Quebec 
interconnection.  The most recent tertiary energy contract will expire 
in August 1996.  The Company anticipates that purchases of tertiary 
energy will extend beyond August 1996, but these purchases will be 
subject to the availability of the Hydro-Quebec/New England 
interconnection.

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, the Company is obligated to purchase 
$3 million (in 1994 dollars) worth of research and development work from 
Hydro-Quebec over the four-year period, and made a $7.5 million (in 1994 
dollars) cash payment to Hydro-Qu bec in 1995.  The Company has 
exercised an option to purchase $1 million worth of additional research 
and development work and the $7.5 million cash payment was reduced 
accordingly.  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.

During the first year of the July 1994 Agreement (the period from 
November 1995 through October 1996), the average cost per kilowatthour 
of Schedules B and C3 combined will be cut from 6.4 to 4.2 cents per 
kilowatthour, a 34 percent (or $16 million) cost reduction.  Over the 
four-year period covered by the arrangement, combined unit costs will be 
lowered from 6.4 to 5.3 cents per kilowatthour, reducing unit costs by 
18 percent and saving $34.1 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-Qu bec facility 
that can be distinguished from the overall charges paid under the 
contracts.



A Summary of the Hydro-Quebec contracts, including the July 1994 
Agreement but excluding the 1996 arrangement, follows:

                         July 1984              December 1987 Contract
                          Contract     Schedule A  Schedule B     Schedule C3
                         ---------     ----------  ----------     -----------
	(Dollars in thousands)
Capacity Acquired . . . .   50 MW       17 MW         68 MW          46 MW
Contract Period . . . . . 1985-1995    1990-1995    1995-2015      1995-2015
Minimum Energy Purchase
 (annual load factor) . .    50%          50%          75%             75%

Annual Energy Charge  . .   $3,091       $1,798      $2,468          $1,317
                            (1995)       (1995)      (1995)          (1995)

                                                    $14,967         $10,324
                                                  (1996-2015)*    (1996-2015)*

Annual Capacity Charge .    $2,367       $1,195      $3,482           $821
                            (1995)       (1995)      (1995)          (1995)

                                                    $16,731         $10,484
                                                  (1996-2015)*    (1996-2015)*

Average Cost per KWH . .     3.0           5.5        5.9             4.0 
                            (1995)       (1995)      (1995)          (1995)

                                                      6.7             6.1 
                                                  (1996-2015)** (1996-2015)**

*Estimated average.
**Estimated average in nominal dollars, levelized over the period indicated.

Under an arrangement negotiated in January 1996, Hydro-Quebec will 
provide cash payments to the Company of $3.0 million in 1996 and $1.1 
million in 1997.  In response, the Company will shift up to 40 megawatts 
of the Schedule C3 deliveries to an alternate transmission path, and use 
the associated portion of the NEPOOL/Hydro-Quebec interconnection 
facilities to purchase power for the period of September 1996 through 
June 2001 at prices that vary based upon conditions in effect when the 
purchases are made.  The 1996 arrangement also provides for minimum 
payments by the Company to Hydro-Quebec, for periods in which power is 
not purchased under the agreement.  Although the level of benefits to 
the Company will depend on various factors, the Company estimates that 
the 1996 arrangement will provide a minimum benefit of $1.8 million, net 
present value.



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of
Green Mountain Power Corporation:

We have audited the accompanying consolidated balance sheets and 
capitalization data of Green Mountain Power Corporation (a Vermont 
corporation) as of December 31, 1995 and 1994, and the related 
consolidated statements of income and cash flows for each of the three 
years in the period ended December 31, 1995.  These financial statements 
are the responsibility of the Company's management.  Our responsibility 
is to express an opinion on these financial statements based on our 
audits.

We conducted our audits in accordance with generally accepted auditing 
standards.  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 as of December 31, 1995 and 1994, and 
the consolidated results of its operations and its cash flows for each 
of the three years in the period ended December 31, 1995, in conformity 
with generally accepted accounting principles.


ARTHUR ANDERSEN LLP



Boston, Massachusetts
January 29, 1996


<TABLE>
<CAPTION>

Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1995, 1994 and 1993

                                                                  Additions
                                        Balance at      -------------------------------                    Balance at
                                       Beginning of       Charged to       Charged to                        End of
Description                               Period        Cost & Expenses  Other Accounts    Deductions        Period
-----------------------------------    -------------    --------------   --------------   -------------   -------------

<S>                                        <C>            <C>              <C>              <C>               <C>
Pine Street Marsh (1)
  1995.................................          $0       $     --         $   --           $   --                  $0
  1994.................................    $684,430       $     --         $   --             $684,430              $0
  1993.................................    $684,430       $     --         $   --           $   --            $684,430


Injuries and Damages
  1995.................................    $513,720           $38,000      $   --             $448,419        $103,301
  1994.................................    $105,660           $35,000         $394,430         $21,370        $513,720
  1993.................................     ($2,357)         $142,000      $   --              $33,983        $105,660


Bad Debt Reserve (3)
  1995.................................    $402,923          $371,564          $48,696 (2)    $405,499        $417,684
  1994.................................    $639,853          $243,974          $53,076 (2)    $533,980        $402,923
  1993.................................    $469,922          $410,000          $89,014 (2)    $329,083        $639,853

(1) See Note I-1 of the Notes to Consolidated Financial Statements.
(2) Represents collection of accounts previously written off.
(3) Includes non-utility bad debt reserve.

</TABLE>

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," "Compliance with the Securities Exchange Act," "Executive 
Compensation," "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 
16, 1996.  Such information is incorporated herein by reference.  Such 
proxy statement pertains to the election of directors and other matters.  
Definitive proxy materials will be filed with the Securities and Exchange 
Commission pursuant to Regulation 14A in April 1996.


PART IV

<TABLE>
<CAPTION>

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

                                                                    Filed
                                                                   Herewith
                                                                   On Page 
                                                                   --------

     Item 14(a)(1).  The financial statements and financial           40
statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.

ITEM 14 (a) (3).                      EXHIBITS
                                                                 Incorporated by Reference from 
Exhibit                                                                           SEC Docket or
Number                                                           Exhibit    Page Filed Herewith
------     ----------------------------------------------        -------    -------------------

<S>        <C>                                                   <C>            <C> 
3-a        Restated Articles of Association, as certified        3-a            Form 10-K 1993
             June 6, 1991.                                                      (1-8291)

3-a-1      Amendment to 3-a above, dated as of May 20, 1993.     3-a-1          Form 10-K 1993
                                                                                (1-8291)

3-b        By-laws of the Company, as amended                    3-b            Form 10-Q Sept. 1995
             May 18, 1995.                                                      (1-8291)

4-b-1      Indenture of First Mortgage and Deed of Trust         4-b            2-27300
             dated as of February 1, 1955.

4-b-2      First Supplemental Indenture dated as of              4-b-2          2-75293
             April 1, 1961.

4-b-3      Second Supplemental Indenture dated as of             4-b-3          2-75293
             January 1, 1966.

4-b-4      Third Supplemental Indenture dated as of              4-b-4          2-75293
             July 1, 1968.

4-b-5      Fourth Supplemental Indenture dated as of             4-b-5          2-75293
             October 1, 1969.

4-b-6      Fifth Supplemental Indenture dated as of              4-b-6          2-75293
             December 1, 1973.

4-b-7      Seventh Supplemental Indenture dated as of            4-a-7          2-99643
             August 1, 1976.

4-b-8      Eighth Supplemental Indenture dated as of             4-a-8          2-99643
             December 1, 1979.

4-b-9      Ninth Supplemental Indenture dated as of              4-b-9          2-99643
             July 15, 1985.

4-b-10     Tenth Supplemental Indenture dated as of              4-b-10         Form 10-K 1989
             June 15, 1989.                                                     (1-8291)

4-b-11     Eleventh Supplemental Indenture dated as of           4-b-11         Form 10-Q Sept
             September 1, 1990.                                                 1990 (1-8291)

4-b-12     Twelfth Supplemental Indentrue dated as of            4-b-12         Form 10-K 1991 
             March 1, 1992.                                                     (1-8291)

4-b-13     Thirteenth Supplemental Indenture dated as of         4-b-13         Form 10-K 1991
              March 1, 1992.                                                    (1-8291)

4-b-14     Fourteenth Supplemental Indenture dated as of         4-b-14         Form 10-K 1993
              November 1, 1993.                                                 (1-8291)

4-b-15     Fifteenth Supplemental Indenture dated as of          4-b-15         Form 10-K 1993
              November 1, 1993.                                                 (1-8291)

*4-b-16     Sixteenth Supplemental Indenture dated as of          
              December 1, 1995.

4-b-17     Revised form of Indenture as filed as an Exhibit      4-a-17         Form 10-Q Sept. 1995
              to Registration Statement No. 33-59383.                           (1-8291)

4-c        Debenture Indenture dated as of August 1, 1967        4-c            2-75293
             (6 5/8% Debentures due August 1, 1992).

4-c-1      First Supplemental Indenture dated as of              4-c-1          2-49697
             August 1, 1969, amending Exhibit 4-c above.

4-d        Debenture Indenture dated as of October 1, 1969       4-d            2-75293
             (8 7/8% Debentures due October 1, 1994).

4-e        Debenture Indenture dated as of December 1, 1976      4-d            2-99643
             (9 3/8% Debentures due December 1, 1996).

4-f        Debenture Indenture dated as of August 1, 1983        4-f            Form 10K 1992
             (12 5/8% Debentures due August 1, 1998).                           (1-8291)

10-a       Form of Insurance Policy issued by Pacific            10-a           33-8146
             Insurance Company, with respect to
             indemnification of Directors and Officers.

10-b-1     Firm Power Contract dated September 16, 1958,         13-b           2-27300
             between the Company and the State of Vermont 
             and supplements  thereto dated September 19,
             1958; November 15, 1958;  October 1, 1960 and
             February 1, 1964.

10-b-2     Power Contract, dated February 1, 1968, between       13-d           2-34346
             the Company and Vermont Yankee Nuclear Power 
             Corporation.

10-b-3     Amendment, dated June 1, 1972, to Power Contract      13-f-1         2-49697
             between the Company and Vermont Yankee Nuclear
             Power Corporation.

10-b-3     Amendment, dated April 15, 1983, to Power             10-b-3(a)      33-8164
  (a)        Contract between the Company and Vermont 
             Yankee Nuclear Power Corporation.

10-b-3     Additional Power Contract, dated                      10-b-3(b)      33-8164
  (b)        February 1, 1984,between the Company and 
             Vermont Yankee Nuclear Power Corporation.

10-b-4     Capital Funds Agreement, dated February 1,            13-e           2-34346
             1968, between the Company and Vermont 
             Yankee Nuclear Power Corporation.

10-b-5     Amendment, dated March 12, 1968, to Capital           13-f           2-34346
             Funds Agreement between the Company and 
             Vermont Yankee Nuclear Power Corporation.

10-b-6     Guarantee Agreement, dated November 5, 1981,          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.

10-b-7     Three-Party Power Agreement among the Company,        13-i           2-49697
             VELCO and Central Vermont Public Service 
             Corporation dated November 21, 1969.

10-b-8     Amendment to Exhibit 10-b-7, dated June 1, 1981.      10-b-8         2-75293



10-b-9     Three-Party Transmission Agreement among the          13-j           2-49697
             Company, VELCO and Central Vermont Public 
             Service Corporation, dated November 21, 1969.

10-b-10    Amendment to Exhibit 10-b-9, dated June 1, 1981.      10-b-10        2-75293

10-b-12    Unit Purchase Contract dated February 10, 1968,       13-h           2-34346
             between the Company and Vermont Electric 
             Power Company, Inc., for purchase of 
             "Merrimack" power from Public Service 
             Company of New Hampshire.

10-b-14    Agreement with Central Maine Power Company et         5.16           2-52900
             al, to enter into joint ownership of Wyman 
             plant, dated November 1, 1974.

10-b-15    New England Power Pool Agreement as amended to        4.8            2-55385
               November 1, 1975.

10-b-16    Bulk Power Transmission Contract between the          13-v           2-49697
             Company and VELCO dated June 1, 1968.

10-b-17    Amendment to Exhibit 10-b-16, dated June 1, 1970.     13-v-i         2-49697

10-b-20    Power Sales Agreement, dated August 2, 1976, as       10-b-20        33-8164
             amended October 1, 1977, and related 
             Transmission Agreement, with the Massachusetts
             Municipal Wholesale Electric Company.

10-b-21    Agreement dated October 1, 1977, for Joint            10-b-21        33-8164
             Ownership, Construction and Operation of the 
             MMWEC Phase I  Intermediate Units, dated 
             October 1, 1977.

10-b-28    Contract dated February 1, 1980, providing for        10-b-28        33-8164
             the sale of firm power and energy by the Power 
             Authority of the State of New York to the 
             Vermont Public Service Board.

10-b-30    Bulk Power Purchase Contract dated April 7,           10-b-32        2-75293
             1976, between VELCO and the Company.

10-b-33    Agreement amending New England Power Pool             10-b-33        33-8164
             Agreement dated as of December 1, 1981, 
             providing for use of  transmission inter-
             connection between New England and 
             Hydro-Quebec.

10-b-34    Phase I Transmission Line Support Agreement           10-b-34        33-8164
             dated as of December 1, 1981, and Amendment  
             No. 1 dated as of June 1, 1982, between 
             VETCO and participating New England utilities
             for construction, use and support of Vermont 
             facilities of transmission interconnection
             between New England and Hydro-Quebec.

10-b-35    Phase I Terminal Facility Support Agreement           10-b-35        33-8164
             dated as of December 1, 1981, and Amendment 
             No. 1 dated as of June 1, 1982, between 
             New England Electric Transmission Corporation
             and participating New England utilities for
             construction, use and support of New Hampshire 
             facilities of transmission interconnection
             between New England and Hydro-Quebec.

             Interconnection dated as of December 1, 1981,
             among participating New England utilities 
             for use of transmission interconnection
             between New England and Hydro-Quebec.

10-b-39    Vermont Participation Agreement for Quebec            10-b-39         33-8164
             Inter-connection dated as of July 15, 1982, 
             between VELCO and participating Vermont 
             utilities for allocation of VELCO's rights 
             and obligations as a participating New
             England utility in the transmission inter-
             connection between New England and Hydro-Quebec.

10-b-40    Vermont Electric Transmission Company, Inc.            10-b-40        33-8164
             Capital Funds Agreement dated as of July 15, 
             1982, between VETCO and VELCO for VELCO to 
             provide capital to VETCO for construction of 
             the Vermont facilities of the transmission 
             inter-connection between New England and 
             Hydro-Quebec.

10-b-41    VETCO Capital Funds Support Agreement dated as         10-b-41        33-8164
             of July 15, 1982, between VELCO and partici-
             pating Vermont utilities for allocation
             of VELCO's obligation to VETCO under the 
             Capital Funds Agreement.

10-b-42    Energy Banking Agreement dated March 21, 1983,         10-b-42        33-8164
             among Hydro-Quebec, VELCO, NEET and parti-
             cipating New England utilities acting by and
             through the NEPOOL Management Committee for
             terms of energy banking between participating
             New England utilities and Hydro-Quebec.

10-b-43    Interconnection Agreement dated March 21, 1983,        10-b-43        33-8164
             between Hydro-Quebec and participating New
             England utilities acting by and through the
             NEPOOL Management Committee for terms and
             conditions of energy transmission between
             New England and Hydro-Quebec.

10-b-44    Energy Contract dated March 21, 1983, between          10-b-44        33-8164
             Hydro-Quebec and participating New England 
             utilities acting by and through the NEPOOL 
             Management Committee for purchase of 
             surplus energy from Hydro-Quebec.

10-b-45    Firm-Power Agreement dated as of October 5, 1982,      10-b-45        33-8164
             between Ontario Hydro and Vermont Department 
             of Public Service.

10-b-46    Sales Agreement, dated January 20, 1983, between       10-b-46        33-8164
             Central Maine Power Company and the Company 
             for excess power.



10-b-48    Sales Agreement, dated February 1, 1983,               10-b-48        33-8164
             betweenNiagara Mohawk and Vermont Electric 
             Power Company for purchase of energy.

10-b-50    Agreement for Joint Ownership, Construction and        10-b-50        33-8164
             Operation of the Highgate Transmission 
             Interconnection, dated August 1, 1984, 
             between certain electric distribution 
             companies, including the Company.

10-b-51    Highgate Operating and Management Agreement,           10-b-51        33-8164
             dated as of August 1, 1984, among VELCO and 
             Vermont electric-utility companies, including 
             the Company.

10-b-52    Allocation Contract for Hydro-Quebec Firm Power        10-b-52        33-8164
             dated July 25, 1984, between the State of 
             Vermont and  various Vermont electric utilities, 
             including the Company.

10-b-53    Highgate Transmission Agreement dated as of            10-b-53        33-8164
             August 1, 1984, between the Owners of the 
             Project and various Vermont electric 
             distribution companies.

10-b-54    Lease and Sublease Agreement dated June 1, 1984,       10-b-54        33-8164
             between Burlington Associates and the Company.

10-b-55    Ground Lease Agreement dated June 1, 1984,             10-b-55        33-8164
             between GMP Real Estate Corporation and 
             Burlington Associates.
 
10-b-56    Assignment of Lease and Agreement, dated June 1,       10-b-56        33-8164
             1984, from Burlington Associates to Teachers 
             Insurance and Annuity Association of America.

10-b-57    Mortgage dated June 1, 1984, from GMP Real Estate      10-b-57        33-8164
             Corporation, Mortgagor, to Teachers Insurance
             and Annuity Association of America, Mortgagee.

10-b-58    Lease and Operating Agreement dated June 28,1985,      10-b-58        33-8164
               between the State of Vermont and the Company.

10-b-59    Service Contract dated June 28, 1985, between the      10-b-59        33-8164
               State of Vermont and the Company.

10-b-61    Agreements entered in connection with Phase II         10-b-61        33-8164
               of the NEPOOL/Hydro-Quebec + 450 KV HVDC 
               Transmission Interconnection.

10-b-62    Agreement between UNITIL Power Corp. and the           10-b-62        33-8164
             Company to sell 23 MW capacity and energy from
             Stony Brook Intermediate Combined Cycle Unit.

10-b-63    Sales Agreement dated as of June 20, 1986,             10-b-63        33-8164
             between the Company and UNITIL Power Corp.
              for sale of system power.



10-b-64    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.

10-b-65    Sales Agreement dated September 18, 1985,              10-b-65        Form 10-K 1991
             between the Company and Fitchburg Gas and                           (1-8291)
             Electric Light Company for the sale of 
             system power.

10-b-66    Sales Agreement dated January 1, 1987, between          10-b-66       Form 10-K 1991
             the Company and Bozrah Light and Power                              (1-8291)
             Company for sale of power.


10-b-67    Sales Agreement dated August 31, 1987, amending         10-b-67       Form 10-K 1992
             the agreement dated June 20, 1986, between                          (1-8291)
             the Company and UNITIL Power Corp. for sale 
             of system power.

10-b-68    Firm Power and Energy Contract dated December 4,        10-b-68       Form 10-K 1992
             1987, between Hydro-Quebec and participating                        (1-8291)
             Vermont utilities, including the Company, for
             the purchase of firm power for up to thirty years.

10-b-69    Firm Power Agreement dated as of October 26, 1987,      10-b-69       Form 10-K 1992
             between Ontario Hydro and Vermont Department of                     (1-8291)
             Public Service.

10-b-70    Firm Power and Energy Contract dated as of              10-b-70       Form 10-K 1992
             February 23, 1987, between the Vermont Joint                        (1-8291)
             Owners of the Highgate facilities and Hydro-
             Quebec for up to 50 MW of capacity.

10-b-70    Amendment to 10-b-70.                                   10-b-70(a)    Form 10-K 1992
  (a)                                                                            (1-8291)

10-b-71    Interconnection Agreement dated as of                   10-b-71       Form 10-K 1992
             February 23, 1987, between the Vermont Joint                        (1-8291)
             Owners of the Highgate facilities and Hydro-Quebec.

10-b-72    Participation Agreement dated as of April 1, 1988,      10-b-72       Form 10-Q 
             between Hydro-Quebec and participating Vermont                      June 1988
             utilities, including the Company, implementing                      (1-8291)
             the purchase of firm power for up to 30 years 
             under the Firm Power and Energy Contract dated 
             December 4, 1987 (previously filed with the
             Company's Annual Report on Form 10-K for 1987,
             Exhibit Number 10-b-68).
 
10-b-72    Restatement of the Participation Agreement filed        10-b-72(a)    Form 10-K 1988
  (a)        as Exhibit 10-b-72 on Form 10-Q for June 1988.                      (1-8291)

10-b-73    Agreement dated as of May 1, 1988, between              10-b-73       Form 10-Q
             Rochester Gas and Electric Corporation and the                      Sept. 1988 
             Company,implementing the Company's purchase of up                   (1-8291)
             to 50 MW of electric capacity and associated energy.



10-b-74    Agreement dated as of November 1, 1988, between         10-b-74       Form 10-Q for
             the Company and Fitchburg Gas and Electric Light                    Sept. 1988
             Company,for sale of electric capacity and                           (1-8291)
             associated energy.
 
10-b-74    Amendment to Exhibit 10-b-74.                           10-b-74(a)    Form 10-Q
  (a)                                                                            Sept 1989
                                                                                 (1-8291)

10-b-75    Allocation Agreement dated as of March 25, 1988,        10-b-75       Form 10-Q
             between Ontario Hydro and the State of Vermont,                     Sept. 1988
             for firm power and associated energy from                           (1-8291)
             Ontario Hydro.

10-b-76    Agreement dated as of October 1, 1988, between          10-b-76       Form 10-K 1988
             the Company and Central Hudson Gas & Electric                       (1-8291)
             Corporation for the Company to purchase up to 
             50 MW of capacity and associated energy.

10-b-76    Transmission agreement dated February 28, 1989,         10-b-76(a)    Form 10-K 1988
  (a)        between the Company and Consolidated Edison                         (1-8291)
             Company of New York, Inc. (Con Edison), that 
             Con Edison will provide electric transmission 
             to the Company from Central Hudson Gas &
             Electric Company.

10-b-77    Firm Power and Energy Contract dated December 29,       10-b-77       Form 10-K 1988 
             1988, between Hydro-Quebec and participating                        (1-8291)
             Vermont utilities, including the Company, for the
             purchase of up to 54 MW of firm power and energy.

10-b-78    Transmission Agreement dated December 23, 1988,         10-b-78       Form 10-K 1988
             between the Company and Niagara Mohawk Power                        (1-8291)
             Corporation (Niagara Mohawk), for Niagara 
             Mohawk to provide electric transmission to 
             the Company from RochesterGas and Electric 
             and Central Hudson Gas and Electric.

10-b-79    Lease Agreement dated November 1, 1988, between         10-b-79       Form 10-K 1988
             the Company and International Business Machines                     (1-8291)
             Corporation (IBM) for the lease to IBM of the 
             gas turbines and associated facilities located 
             on land adjacent to IBM's  Essex Junction, 
             Vermont, plant.

10-b-80    Sales Agreement dated January 1, 1989, between          10-b-80       Form 10-K 1988
             the Company and Public Service of New Hampshire                     (1-8291)
             (PSNH)for PSNH to purchase electric capacity 
             from the Company.

10-b-81    Sales Agreement dated May 24, 1989, between             10-b-81       Form 10-Q
             the Town of Hardwick, Hardwick Electric Department                  June 1989
             and the Company for the Company to purchase                         (1-8291)
             all of the output of Hardwick's generation and
             transmission sources and to provide Hardwick 
             with all-requirements energy and capacity except
             for that provided by the Vermont Department of 
             Public Service or Federal Preference Power.



10-b-82    Sales Agreement dated July 14, 1989, between            10-b-82       Form 10-Q 
             Northfield Electric Department and the Company                      June 1989
             for the Company to purchase all of the output                       (1-8291)
             of Northfield's generation and transmission 
             sources and to provide Northfield with all-
             requirements energy and capacity except for 
             that provided by the Vermont Department of
             Public Service or Federal Preference Power.

10-b-83    Power Purchase and Operating Agreement dated as         10-b-83       Form 10-Q 
             of April 20, 1990, between CoGen Lime Rock,                         June 1990
             Inc., and the Company for the production of                         (1-8291)
             energy to meet customer needs.

10-b-84    Capacity, Transmission and Energy Service               10-b-84       Form 10-K 1992
             Agreement dated December 23, 1992, between                          (1-8291)
             the Company and Connecticut Light and Power 
             Company (CL&P) for CL&P to supply power to 
             Bozrah Light and Power Company.

Management contracts or compensatory plans or arrangements
  required to be filed as exhibits to this form 10-K
  pursuant to Item 14(c).

10-c       Contract dated as of October 15, 1983, between          10-c          33-8164
             the Company and Thomas V. O'Connor, Jr.

10-c-1     Amendment dated as of March 31, 1988, to an             10-c-1        Form 10-Q 
             agreement between the Company and                                   March 1988
             Thomas V. O'Connor, Jr                                              (1-8291)

10-d-1a    Green Mountain Power Corporation Amended and            10-d-1a       Form 10-Q 
             Restated Deferred Compensation Plans for                            March 1990
             Directors and Officers.                                             (1-8291)

10-d-1b    Green Mountain Power Corporation Second Amended        10-d-1b        Form 10-K 1993
              and Restated Deferred Compensation Plan for                        (1-8291)
              Directors.

10-d-1c    Green Mountain Power Corporation Second Amended        10-d-1c        Form 10-K 1993
              and Restated Deferred Compensation Plan for                        (1-8291)
              Officers.

10-d-1d    Amendment No. 93-1 to the Amended and Restated         10-d-1d        Form 10-K 1993
              Deferred Compensation Plan for Officers.                           (1-8291)

10-d-1e    Amendment No. 94-1 to the Amended and Restated         10-d-1e        Form 10-Q
              Deferred Compensation Plan for Officers.                           June 1994
                                                                                 (1-8291)

10-d-2     Green Mountain Power Corporation Medical Expense        10-d-2        Form 10-K 1991
             Reimbursement Plan.                                                 (1-8291)

10-d-3     Green Mountain Power Corporation Management             10-d-3        Form 10-K 1991
             Incentive Plan.                                                     (1-8291)

10-d-4     Green Mountain Power Corporation Officer                10-d-4        Form 10-K 1991 
             Insurance Plan.                                                     (1-8291)

10-d-4a    Green Mountain Power Corporation Officers'              10-d-4a       Form 10-K 1990
             Insurance Plan as amended.                                          (1-8291)

10-d-5a    Severance Agreements with J. V. Cleary, D. G. Hyde,     10-d-5a       Form 10-K 1990
             A. N. Terreri, E. M. Norse, T. V. O'Connor, Jr.,                    (1-8291)
             C. L. Dutton, G. J. Purcell, S. C. Terry and 
             T. C. Boucher.

10-d-6     Severance Agreements with W. S. Oakes, E. L. Shlatz     10-d-6        Form 10-K 1988
             and J. H. Winer.                                                    (1-8291)

10-d-6a    Restatement of 10-d-6 above.                            10-d-6a       Form 10-K 1990
                                                                                 (1-8291)

10-d-7     Severance Agreement with  K. K. O'Neill.                10-d-7        Form 10-K 1990
                                                                                 (1-8291)

10-d-8     Green Mountain Power Corporation Officers'              10-d-8        Form 10-K 1990
             Supplemental Retirement Plan.                                       (1-8291)

10-d-9     Severance Agreement with  C. T. Myotte.                 10-d-9        Form 10-Q June
                                                                                 1991 (1-8291)

10-d-10    Severance Agreement with J. J. Lampron.                 10-d-10       Form 10-K 1991 
                                                                                 (1-8291)

10-d-11    Severance Agreement with D. R. Stroupe                  10-d-11       Form 10-Q Sept
                                                                                 1992 (1-8291)

10-d-12    Green Mountain Power Corporation Officer Compensation   10-d-12       Form 10-Q
             Program, Highlights Brouchure / Program Document.                   June 1994
                                                                                 (1-8291)

10-d-13    Severance Agreement with M. H. Lipson.                  10-d-13       Form 10-K 1994
                                                                                 (1-8291)

10-d-14    Severance Agreement with D. G. Whitmore.                10-d-14       Form 10-K 1994
                                                                                 (1-8291)

10-d-15    Green Mountain Power Corporation Officer Compensation   10-d-15       Form 10-K 1994
             Program, Highlights Brochure / Program Document                     (1-8291)
             amended.

10-d-15a   Green Mountain Power Corporation Compensation Program   10-d-15a      Form 10-Q
             for Officers and Key Management Personnel as amended                Sept. 1995
             August 8, 1995                                                      (1-8291)

10-d-16    Severance Agreement with R. C. Young                    10-d-16       Form 10-Q March
                                                                                 1995 (1-8291)

10-d-17    Severance Agreement with P. H. Zamore                   10-d-17       Form 10-Q March
                                                                                 1995 (1-8291)

10-e-2     Agreement dated as of May 26, 1988, between the         10-e-2        Form 10-K for
             Company and Thomas P. Salmon, Chairman of the Board.                1988 (1-8291)

*12        Computation of Ratio of Earnings to Fixed Charges

16-a       Letter from former accountant, Coopers & Lybrand.                     Form 8-K for 
                                                                                 1987 (1-8291)

*23-a-1    Consent of Arthur Andersen LLP

*27        Financial Data Schedule

* Filed herewith
</TABLE>


ITEM 14(b)	

	There were no reports on Form 8-K filed for the quarter ending 
December 31, 1995.



OTHER MATTERS


	For the purposes of complying with the amendments to the rules 
governing Form S-8 (effective July 13, 1990) under the Securities Act of 
1933, the undersigned registrant hereby undertakes as follows, which 
undertaking shall be incorporated by reference into registrant's 
Registration Statement on Form S-8 No. 33-58413 (filed April 4, 1995):

	Insofar as indemnification for liabilities arising under the 
Securities Act of 1933 may be permitted to directors, officers and 
controlling persons of the registrant pursuant to the foregoing provisions, 
or otherwise, the registrant has been advised that in the opinion of the 
Securities and Exchange Commission such indemnification is against public 
policy as expressed in the Securities Act of 1933 and is, therefore, 
unenforceable.  In the event that a claim for indemnification against such 
liabilities (other than the payment by the registrant of expenses incurred 
or paid by a director, officer or controlling person of the registrant in 
the successful defense of any action, suit or proceeding) is asserted by 
such director, officer or controlling person in connection with the 
securities being registered, the registrant will, unless in the opinion of 
its counsel the matter has been settled by controlling precedent, submit to 
a court of appropriate jurisdiction the question whether such 
indemnification by it is against public policy as expressed in the Act and 
will be governed by the final adjudication of such issue.



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/ D. G. Hyde                  Date:  March 29, 1996
	(D. G. Hyde, President and
	Chief Executive Officer)

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

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


 /s/ D. G. Hyde               Chairman of the Executive Commit-   March 29, 1996
        (D. G. Hyde)          tee, President, Chief Executive
                              Officer and Director

 /s/ C. L. Dutton             Vice President, Treasurer and       March 29, 1996
       (C. L. Dutton)         Chief Financial Officer (Principal 
                              Financial Officer)

 /s/ G. J. Purcell            Controller                          March 29, 1996
       (G. J. Purcell)        (Principal Accounting Officer)

 /s/ T. P. Salmon             Chairman of the Board and           March 29, 1996
       (T. P. Salmon)         Director

 /s/ R. E. Boardman           Director                            March 29, 1996
       (R. E. Boardman)

 /s/ N. L. Brue               Director                            March 29, 1996
       (N. L. Brue)

 /s/ W. H. Bruett             Director                            March 29, 1996
       (W. H. Bruett)

                              Director                            
       (M. O. Burns)

 /s/ L. E. Chickering         Director                            March 29, 1996
     (L. E. Chickering)

 /s/ J. V. Cleary             Director                            March 29, 1996
       (J. V. Cleary)

 /s/ R. I. Fricke             Director                            March 29, 1996
       (R. I. Fricke)

 /s/ E. A. Irving             Director                            March 29, 1996
       (E. A. Irving)

 /s/ M. L. Johnson            Director                            March 29, 1996
       (M. L. Johnson)

 /s/ R. W. Page               Director                            March 29, 1996
       (R. W. Page)



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS



To the Board of Directors of
Green Mountain Power Corporation:

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 January 29, 1996.  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 index on page 40 of this Form 10-K is the 
responsibility of the Company's management and 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
January 29, 1996                       /s/  Arthur Andersen LLP