SECURITIES AND EXCHANGE COMMISSION

                              Washington, D. C.  20549

                     

                                      FORM 10-K


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


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

     For the transition period from ________________ to __________________

                   For the fiscal year ended December 31, 1996

                          Commission file number  1-8291

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

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

    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 non-
affiliates of the registrant as of March 14, 1997, was $120,638,465.00 
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 14, 1997, 
was 5,052,920.


DOCUMENTS INCORPORATED BY REFERENCE

	The Company's Definitive Proxy Statement relating to its Annual 
Meeting of Stockholders to be held on May 15, 1997, 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 I

ITEM 1.  BUSINESS
THE COMPANY

     Green Mountain Power Corporation (the Company) is a public utility 
operating company engaged in supplying electrical energy in the State of 
Vermont in a territory with approximately one quarter of the State's 
population.  It serves approximately 82,500 customers.  The Company was 
incorporated under the laws of the State of Vermont on April 7, 1893.

     For the year ended December 31, 1996, the Company's sources of 
revenue were derived as follows:  33.3% from residential customers, 
31.0% from small commercial and industrial customers, 20.1% from large 
commercial and industrial customers, 11.3% from sales to other 
utilities, and 4.3% from other sources.  For the same period, the 
Company's energy resources for retail and requirements wholesale sales 
were obtained as follows:  50.4% from hydroelectric sources (7.4% 
Company-owned, 0.1% New York Power Authority (NYPA), 39.6% Hydro-Quebec 
and 3.3% small power producers), 27.9% from nuclear generating sources 
(the Vermont Yankee plant described below), 7.4% from coal sources, 3.7% 
from wood, 1.1% from natural gas, and 1.1% from oil.  The remaining 8.4% 
was purchased on a short-term basis from other utilities and through the 
New England Power Pool (NEPOOL).  In 1996, the Company purchased 96.7% 
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 531-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, 1996, 1995 and 1994, electric 
energy sales to International Business Machines Corporation (IBM), the 
Company's largest customer, accounted for 13.2%, 12.9% and 13.7%, 
respectively, of the Company's operating revenues in those years.  No 
other retail customer accounted for more than 1.0% of the Company's 
revenue.  Under the present regulatory system, the loss of IBM as a 
customer of the Company would require the Company to seek rate relief to 
recover the revenues previously paid by IBM from other customers in an 
amount sufficient to offset the fixed costs that IBM had been covering 
through its payments.


EMPLOYEES


     The Company had 344 employees, exclusive of temporary employees, as 
of December 31, 1996.  In addition, subsidiaries of the Company had 45 
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 Company's 
heaviest load in 1996 - 313.0 MW - occurred on December 31, 1996.  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 "Energy Efficiency - Rate Design."

<TABLE>
<CAPTION>


OPERATING STATISTICS
For the Years Ended December 31
                                                          1996          1995          1994          1993          1992
                                                       ----------    ----------    ----------    ----------    ----------



<S>                                                        <C>           <C>           <C>           <C>           <C>
Net System Capability During Peak Month (MW)
  Hydro (1)............................................    193.8         152.1         179.0         174.9         160.6
  Lease transmissions..................................      0.6           0.3           2.1           3.9           5.7
  Nuclear (1)..........................................     95.7          81.9         107.2         109.5         109.6
  Conventional steam...................................     52.9          77.8          67.1          92.6          95.0
  Internal combustion..................................     60.7          62.0          60.2          71.0          47.4
  Combined cycle.......................................     22.1          22.0          22.6          22.8          21.6
                                                       ----------    ----------    ----------    ----------    ----------
    Total capability (MW)..............................    425.8         396.1         438.2         474.7         439.9
  Net system peak......................................    313.0         297.1         308.3         307.3         314.4
                                                       ----------    ----------    ----------    ----------    ----------
  Reserve (MW).........................................    112.8          99.0         129.9         167.4         125.5
                                                       ==========    ==========    ==========    ==========    ==========
  Reserve % of peak....................................     36.0%         33.3%         42.1%         54.5%         39.9%

Net Production (MWH)
  Hydro (1)............................................1,192,881     1,043,617       742,088       751,078       641,525
  Lease transmissions..................................    --            --            --           15,425        58,374
  Nuclear (1)..........................................  680,613       682,814       763,690       598,245       665,034
  Conventional steam...................................  705,331       673,982       651,105       748,626       762,451
  Internal combustion..................................    2,674         6,646         3,532         2,849         1,504
  Combined cycle.......................................   51,162        92,723        37,808        40,966        60,138
                                                       ----------    ----------    ----------    ----------    ----------
    Total production...................................2,632,661     2,499,782     2,198,223     2,157,189     2,189,026
  Less non-requirements sales to other utilities.......  663,175       582,942       328,794       271,224       273,087
                                                       ----------    ----------    ----------    ----------    ----------
  Production for requirements sales....................1,969,486     1,916,840     1,869,429     1,885,965     1,915,939
  Less requirements sales & lease transmissions (MWH)..1,814,371     1,760,830     1,730,497     1,749,454     1,794,986
                                                       ----------    ----------    ----------    ----------    ----------
  Losses and company use (MWH).........................  155,115       156,010       138,932       136,511       120,953
                                                       ==========    ==========    ==========    ==========    ==========
Losses as a percentage of total production.............     5.89%         6.24%         6.32%         6.33%         5.53%
System load factor (2).................................     69.7%         71.2%         67.7%         68.7%         68.5%



Sales and Lease Transmissions (MWH)
  Residential - GMP....................................  557,726       549,296       564,635       541,579       505,234
  Lease transmissons...................................    --            --            --           15,425        58,374
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................  557,726       549,296       564,635       557,004       563,608
  Commercial & industrial - small......................  630,839       608,688       604,686       593,560       582,594
  Commercial & industrial - large......................  584,249       556,278       521,400       529,372       539,665
  Other................................................    2,898         8,855         1,146         8,868         6,312
                                                       ----------    ----------    ----------    ----------    ----------
    Total retail sales and lease transmissions.........1,775,712     1,723,117     1,691,867     1,688,804     1,692,179
  Sales to municipals and cooperatives and
    other requirements sales...........................   38,659        37,713        38,630        60,650       102,807
                                                       ----------    ----------    ----------    ----------    ----------
    Total requirements sales...........................1,814,371     1,760,830     1,730,497     1,749,454     1,794,986
  Other sales for resale...............................  663,175       582,942       328,794       271,224       273,087
                                                       ----------    ----------    ----------    ----------    ----------
    Total sales and lease transmissions................2,477,546     2,343,772     2,059,291     2,020,678     2,068,073
                                                       ==========    ==========    ==========    ==========    ==========

Average Number of Electric Customers
  Residential..........................................   70,198        69,659        68,811        67,994        67,201
  Commercial and industrial - small....................   11,828        11,712        11,611        11,447        11,245
  Commercial and industrial - large....................       25            24            24            25            24
  Other................................................       75            76            76            74            73
                                                       ----------    ----------    ----------    ----------    ----------
    Total..............................................   82,126        81,471        80,522        79,540        78,543
                                                       ==========    ==========    ==========    ==========    ==========


Average Revenue per KWH (Cents)
  Residential including lease revenues.................    10.87         10.09          9.03          8.94          8.44
  Lease charges........................................      --            --            --           0.06          0.41
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................    10.87         10.09          9.03          9.00          8.85
  Commercial and industrial - small....................     8.96          8.42          8.00          7.97          7.82
  Commercial and industrial - large....................     6.28          5.86          6.02          5.96          5.89
  Total retail including lease revenues................     8.72          8.36          7.96          7.86          7.56


Average Use and Revenue Per Residential Customer
  Kilowatt hours including lease transmissions.........    7,945         7,885         8,206         8,192         8,387
  Revenues including lease revenues....................     $863          $796          $741          $733          $707


(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>

STATE AND FEDERAL REGULATION

     General.  The Company is subject to the regulatory authority of the 
Vermont Public Service Board (VPSB), which extends to retail rates, 
services, facilities, securities issues and various other matters.  The 
separate Vermont Department of Public Service (the Department), created 
by statute in 1981, is responsible for development of energy supply 
plans for the State of Vermont (the State), purchases of power as an 
agent for the State and other general regulatory matters.  The VPSB 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.

     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 was part of 
the rate settlement approved by the VPSB on May 23, 1996.  See Item 7. 
Management's Discussion and Analysis of Financial Condition and Results 
of Operations (MD&A) - "Results of Operations - Operating Revenues and 
MWh Sales."

     The Company's wholesale rate on sales to three wholesale customers 
is regulated by the Federal Energy Regulatory Commission (FERC).  
Revenues from sales to these customers were approximately 0.9% of 
operating revenues for 1996.

     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 
23,350 MWh and peak requirements by approximately 6EMW.  Revenues in 
1996 from Northfield were $1,389,972.

     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 1.0% of the Company's operating revenues 
for 1996.

     On April 24, 1996, the FERC issued Orders 888 and 889 which among 
other things required the filing of open access transmission tariffs by 
electric utilities.  See Item 7. MD&A - "Transmission Issues - Federal 
Open Access Tariff Orders."  NEPOOL has proposed a transmission tariff 
for certain transmission facilities, including certain facilities 
between New York and New England, that incorporates a load-based method 
of capacity allocation for NEPOOL transmission facilities.  The proposal 
could reduce the amount of capacity available to the Company from such 
facilities in the future.  See Item 7.  MD&A - "Transmission Issues - 
Proposed NEPOOL Transmission Tariff."

     By reason of its relationship with Vermont Yankee, VELCO and 
Vermont Electric Transmission Company, Inc. (VETCO), a wholly owned 
subsidiary of VELCO, 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 (IRP) was published in June 
1996.  It was developed in a manner consistent with the Department's 
Plan.  The Company's 1996 IRP calls for a greater emphasis on 
distributed utility approaches that can best use the Company's assets, 
maximize the benefit of energy efficiency programs, and provide 
customers with the highest quality service.

RECENT RATE DEVELOPMENTS


     In early 1996, the Company entered into an agreement with Hydro-
Quebec which enabled the Company to settle its rate case filed in 
September 1995.  The settlement provided for an overall increase in 
retail rates of 5.25%, effective June 1, 1996, and a target return on 
equity for utility operations of 11.25%.  For further information 
regarding recent rate developments, see Item 7. MD&A - "Liquidity and 
Capital Resources - Rates" and Note I.5 of Notes to Consolidated 
Financial Statements.


COMPETITION AND RESTRUCTURING


     Electric utilities historically have had exclusive franchises for 
the retail sale of electricity in specified service territories.  
Legislative authority has existed since 1941 that would permit Vermont 
cities, towns and villages to own and operate public utilities.  Since 
that time, no municipality served by the Company has established or, as 
far as is known to the Company, is presently taking steps to establish, 
a municipal public utility.

     In 1987, the Vermont General Assembly enacted legislation that 
authorized the Department to sell electricity on a significantly 
expanded basis.  Before the new law was passed, the Department's 
authority to make retail sales had been limited.  It could sell at 
retail only to residential and farm customers and could sell only power 
that it had purchased from the Niagara and St. Lawrence projects 
operated by the New York Power Authority.

     Under the law, the Department can sell electricity purchased from 
any source at retail to all customer classes throughout the state, but 
only if it convinces the VPSB and other state officials that the public 
good will be served by such sales.  The Department has made limited 
additional retail sales of electricity.  The Department retains its 
traditional responsibilities of public advocacy before the VPSB, and 
electricity planning on a statewide basis.

     Regulatory and legislative authorities at the federal level and 
among states across the country, including Vermont, are considering how 
to restructure the electric industry to facilitate competition for 
electricity sales at wholesale and retail levels.  For further 
information regarding Competition and Restructuring, See Item 7. MD&A - 
"Future Outlook."

     In a recent order related to electric industry restructuring issued 
by the VPSB on December 31, 1996 (Final Order), the VPSB requested 
utilities to submit their initial utility restructuring plans  to the 
VPSB by June 30, 1997.  These plans will set forth the utility's plan 
for the structural changes required to implement functional separation 
or operational unbundling of the regulated transmission and distribution 
operations from the unregulated generation and retail competitive 
services operations.  These filings will include plans for providing 
unbundled service rates and other elements to facilitate separation of 
regulated and unregulated activities. The Company is currently in the 
process of preparing its restructuring plan, including unbundled service 
tariffs, for submission to the VPSB in accordance with its Final Order.  
The Company's final restructuring plans will not be formulated until 
definitive restructuring legislation has been adopted by the Vermont 
General Assembly and such plans will be subject to approval by the VPSB. 


POWER RESOURCES


     The Company generated, purchased or transmitted 1,924,811.9 MWh of 
energy for retail and requirements wholesale customers for the twelve 
months ended December 31, 1996.  The corresponding maximum one-hour 
integrated demand during that period was 313.0 MW on December 31, 1996.  
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 in Year      Purchased in Month
                                   Ended 12/31/96 (a)       of Annual Peak
                                  ___________________    ___________________
                                     MWh         %(b)       KW          %(b)
WHOLLY OWNED PLANTS
  Hydro                            150,586.2    7.4        35,300       8.3
  Diesel and Gas Turbine             5,530.0    0.3        63,660      15.0

JOINTLY OWNED PLANTS
  Wyman #4                           5,941.5    0.3         7,030       1.7
  Stony Brook I                     10,291.7    0.5         7,990       1.9
  McNeil                            15,252.9    0.8         6,470       1.5

OWNED IN ASSOCIATION W/OTHERS
  Vermont Yankee Nuclear           565,383.9   27.9        95,680      22.5

NYPA LEASE TRANSMISSIONS
  State of Vermont (NYPA)            1,520.0    0.1           620       0.1

LONG-TERM PURCHASES
  Hydro-Quebec                     807,030.7   39.6       140,680      33.0
  Merrimack #2                     150,913.1    7.4        31,820       7.5
  Stony Brook I                     21,907.3    1.1        14,150       3.3
  Small Power Producers            125,552.2    6.2        24,630       5.8

SHORT-TERM PURCHASES               167,343.5    8.4           0.0       0.0
                                 ___________   ____       _______     _____
  Less System Sales Energy        (102,441.1)              (2,260)     (0.6)

  TOTAL                          1,924,811.9  100.00      425,770    100.00
                                 ===========  ======      =======    ======

    NOTE:  (a)  Excludes losses on off-system purchases, totaling 59,332 
MWh.
           (b)  Percentages may be adjusted to total 100%.


     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 531 MW.  Vermont Yankee has entered into power 
contracts with its sponsor utilities, including the Company, that expire 
at the end of the life of the unit.  Pursuant to 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 a share of its entitlement to 
the output of Vermont Yankee.  Accordingly, those utilities had 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.  As a result of the bankruptcy of one of those 
utilities, a portion of the entitlement has reverted back to the 
Company.  Accordingly, those utilities have an obligation to the Company 
to pay 2.338% 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, 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 to 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's 
assertions.  On July 31, 1991, Vermont Yankee reached a settlement with 
the State, and the State filed a withdrawal of its intervention.  The 
proceeding was dismissed on September 3, 1991.

     In New England, five nuclear units are currently under orders from 
the NRC not to operate until shown to be in compliance with applicable 
safety provisions.  In December 1996, a decision was made to retire one 
of these units, effective immediately, with several years remaining on 
its license.  The NRC recently issued Vermont Yankee's Systematic 
Assessment of Licensee Performance scores for the period July 16, 1995 
to January 18, 1997.  Operations, engineering and maintenance were rated 
good, while plant support was rated superior.  These scores are 
identical to Vermont Yankee's scores for the prior 18 month period.  In 
1996, Vermont Yankee elected to accelerate  certain safety and 
management related projects intended to improve efficiency of the plant 
and assure compliance with NRC regulations and the facility's operating 
license.

     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 September 7, 
1996, Vermont Yankee began a scheduled refueling outage which ended 
November 2, 1996.  Vermont Yankee's next scheduled refueling is March, 
1998.  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 $366,000,000, of which $160,000,000 has been funded.  At 
December 31, 1996, 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.

     During 1996, the Company incurred $28,500,000 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, 
1996 was $13,800,000.

     During the year ended December 31, 1996, the Company utilized 
565,383.9 MWh of Vermont Yankee energy to meet 27.9% of its retail and 
requirements wholesale (Rate W) sales.  The average cost of Vermont 
Yankee electricity in 1996 was 4.8 cents per KWh.  In 1996, Vermont Yankee 
had an annual capacity factor of 83.0%, compared to 85.0% in 1995 and 
96.1% in 1994.

     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 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 
1996 is $3,000,000. 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) to cover the costs of property damage, decontamination or 
premature decommissioning resulting from a nuclear incident.  All 
companies insured with NEIL are subject to retroactive assessments if 
losses exceed the accumulated funds available.  The maximum potential 
assessment against Vermont Yankee with respect to NEIL losses arising 
during the current policy year is $13,300,000.  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.  See Note B of Notes to Consolidated Financial 
Statements.


HYDRO-QUEBEC


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


     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 9.0% of the total power-supply 
benefits associated with the NEPOOL/Hydro-Quebec interconnection.  The 
Company, in turn, receives about one-third of the Vermont share of those 
benefits.

     The benefits of the interconnection include access to surplus 
hydroelectric energy from Hydro-Quebec at 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.  VETCO was 
organized to construct, own and operate those portions of the 
transmission facilities located in Vermont.  Total construction costs 
incurred by VETCO for Phase I were $47,850,000.  Of that amount, VELCO 
provided $10,000,000 of equity capital to VETCO through sales of VELCO 
preferred stock to the Vermont participants in the project.  The Company 
purchased $3,100,000 of VELCO preferred stock to finance the equity 
portion of PhaseEI.  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 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 690EMW to 2,000EMW, 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, 1996, the 
present value of the Company's obligation was $9,000,000.  The Company's 
projected future minimum payments under the Phase II support agreements 
are $474,013 for each of the years 1997-2001 and an aggregate of 
$6,636,181 for the years 2002-2020.  

     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, 1996, the capital structure 
of such corporations was 39.0% common equity and 61.0% long-term debt.  
See Note J of Notes to Consolidated Financial Statements.

     At times, the Company requests that portions of its power 
deliveries from Hydro-Quebec and other sources be routed through New 
York.  The Company's ability to do so could be adversely affected by the 
proposed tariff that NEPOOL has filed with the FERC, which incorporates 
a load-based method of capacity allocation for transmission interfaces 
between NEPOOL and the New York Power Pool.  A reduction of the 
Company's allocation of capacity on transmission interfaces with New 
York could adversely affect the Company's ability to import power to 
Vermont from outside New England which would impact the Company's power 
costs in the future.  See Item 7. MD&A - "Transmission Issues" and Note 
J of Notes to Consolidated Financial Statements.

     Hydro-Quebec Power Supply Contracts.  Under an arrangement 
negotiated in January 1996, the Company received cash payments from 
Hydro-Quebec of $3,000,000 in 1996 and will receive $1,100,000 in 1997.  
The Company will shift certain transmission requirements and make 
certain minimum payments for periods in which power is not purchased.  
In addition, in November 1996, the Company entered into a Memorandum of 
Understanding with Hydro-QuEbec under which Hydro-QuEbec will pay 
$8,000,000 in exchange for certain power purchase elections.  See Item 
7. MD&A - "Power Supply Expenses" and Notes J and K-2 of Notes to 
Consolidated Financial Statements.

    In 1996, the Company utilized 430,958.9 MWh under Schedule B, 
300,359.7 MWh under Schedule C3, and 75,712.1 MWh under the tertiary 
energy contract to meet 39.6% of its retail and requirements wholesale 
sales.  The average cost of Hydro-Quebec electricity in 1996 was 4.0 cents 
per KWh.


     New York Power Authority (NYPA).  The Department allocates NYPA 
power to the Company which, in turn, delivers the power to its 
residential and farm customers.  The Company purchased at wholesale 
1,520.0 MWh to meet 0.1% of its retail and requirements wholesale sales 
of NYPA power at an average cost of 0.8 cents per KWh in 1996.  Under the 
allocation currently made by NYPA of NYPA power to states neighboring 
New York, residential and farm customers in the Company's service 
territory will be entitled to 0.3 MW annually.


     Merrimack Unit #2.  Merrimack Unit #2 is a coal-fired steam plant 
of 320.0 MW capacity located in Bow, New Hampshire, and owned by 
Northeast Utilities.  The Company is entitled to 28.48 MW of capacity 
and related energy from the unit under a 30-year contract expiring May 
1, 1998.  During the year ended December 31, 1996, the Company utilized 
150,913.1 MWh from the unit to meet  7.4% of its total retail and 
requirements wholesale sales.  The average cost of electricity from this 
unit was 3.8 cents per KWh in 1996.  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 Stony Brook, a 352.0-
MW combined-cycle intermediate generating station 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 31.0 MW of capacity.  In addition 
to this entitlement, the Company has contracted for 14.2 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 1996, the Company utilized 32,199.0 MWh from this plant to 
meet 1.6% of its retail and requirements wholesale sales at an average 
cost of 7.6 cents (purchased power).  See Note I-4 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 620 MW.  
The construction of this plant was sponsored by Central Maine Power 
Company.  The Company has a joint-ownership share of 1.1% (6.8 MW) in 
the Wyman #4 unit, which began commercial operation in December 1978.

     During 1996, the Company utilized 5,941.5 MWh from this unit to 
meet 0.3% of its retail and requirements wholesale sales at an average 
cost of 6.1 per kWh, based only on operation, maintenance, and fuel 
costs incurred during 1996.  See Note I-4 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 53.0 MW.  The Company has an 11% or 5.9 MW interest in the 
J. C. McNeil plant, which began operation in June 1984.  During 1996, 
the Company utilized 15,252.9 MWh from this unit to meet 0.8% of its 
retail and requirements wholesale sales at an average cost of 5.4 cents per 
kWh, based only on operation, maintenance, and fuel costs incurred 
during 1996.  In 1989, the plant added the capability to burn natural 
gas on an as-available/interruptible service basis.  See Note I-4 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 Electric Power 
Producers, Inc. (VEPPI), 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 32.7% or 49.1 MW.

     The rated capacity of the qualifying facilities currently selling 
power to VEPPI 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 for and value of additional qualifying facilities.

     In 1996, the Company, through both its direct contracts and VEPPI, 
purchased 125,552.2 MWh of qualifying facilities production to meet 6.2% 
of its retail and requirements wholesale sales at an average cost of 
10.7 cents per KWh.


     Short-Term Opportunity Purchases and Sales.  The Company has made 
arrangements with several utilities in New England and New York under 
which 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 1996, the Company purchased 167,343.5 MWh, meeting 8.2% of 
the Company's retail and requirements wholesale sales, at an average 
cost of 2.7 cents per kWh.


     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 NEPOOL, but which is lower than 
the reserve which would be required if the Company were not a NEPOOL 
participant.


     Company Hydroelectric Power.  The Company wholly owns and operates 
eight hydroelectric generating facilities located on river systems 
within its service area, the largest of which has a generating output of 
8.8 MW.  In 1996, these plants provided 150,586.2 MWh of low-cost 
energy, meeting 7.4% of the Company's retail and requirements wholesale 
sales at an average cost of 2.9 cents per kWh, based on total embedded costs.  
See "State and Federal Regulation - Licensing."


     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.  In 1986, the Company entered into an 
agreement for the sale to United Illuminating 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 1996, the Company's retail and requirements wholesale 
sales were provided by the following fuel sources:  50.4% from hydro 
(7.4% Company-owned, 0.1% NYPA, 39.6% Hydro-Quebec and 3.3% small power 
producers), 27.9% from nuclear, 7.4% from coal, 3.7% from wood, 1.1% 
from natural gas, and 1.1% from oil.  The remaining 8.4% 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 
actual date for these disposal services is expected to be delayed many 
years.

     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 1996, Vermont Yankee accumulated 
approximately $78,000,000 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 (80EMW).  The Company did not experience difficulty in obtaining oil 
for its own units during 1996, and, while no assurance can be given, 
does not anticipate any such difficulty during 1997.  None of the 
utilities from which the Company expects to purchase oil- or gas-fired 
capacity in 1997 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 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.

     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 
221,529 tons of wood chips and mill residue and 23,340,000 cubic feet of 
gas in 1996.  The McNeil plant is forecasting consumption of wood chips 
for 1997 to be 180,000 tons and gas consumption of 136,000,000 cubic 
feet.

     The Stony Brook combined-cycle generating station is capable of 
burning either natural gas or oil in two of its turbines.  Natural gas 
is supplied to the plant subject to its availability.  During periods of 
extremely cold weather, the supplier reserves the right to discontinue 
deliveries to the plant in order to satisfy the demand of its 
residential customers.  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.


     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 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, located in the southern 
Vermont towns of Searsburg and Readsboro, is estimated to be 
$11,000,000.  The eleven wind turbines have a rating of 6 MW and are 
expected to begin to generate electricity for the Company in 1997.

     The Company is a utility leader in wind power research.  The 
CompanyOs 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 other 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% 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.


ENERGY EFFICIENCY


     The Company develops and implements energy efficiency services, 
known as 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 also provide customers with options and choices with 
respect to their use and cost of electric service.

     In 1996, the Company focused its energy efficiency services on lost 
opportunity programs that encourage customers to install energy 
efficient equipment when they are planning to replace or buy new 
equipment.  This strategy has helped the Company to reduce its cost-per-
kilowatthour-saved by 51% since 1992.  The current cost of saving a 
kilowatthour is approximately 2.2 cents.  In 1996, the Company's energy 
efficiency programs saved 10,399 megawatthours of energy, 14% above 
targeted savings for the year.  During the past five years the Company's 
efficiency programs have achieved a cumulative annual savings of 64,047 
MWh.

     One of the highlights of the Company's 1996 energy efficiency 
initiatives was the successful completion of the Mad River Valley Energy 
Project.  The project reduced the peak demand in the Mad River Valley 
(Vermont) and helped postpone the need for a costly transmission 
upgrade.  The Company is currently examining other areas of its 
distribution system that may need upgrading in the near future and is 
including energy efficiency as one of the options to help mitigate 
costs.

     In 1996, the Company spent approximately $2,400,000 on energy 
efficiency programs, approximately 1.5% of its retail revenue.


     Rate Design.  The Company seeks to design rates to encourage the 
shifting of electrical use from peak hours to off 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's rate design 
objectives are to provide a stable pricing structure and to accurately 
reflect the cost of providing electric services.  This rate structure 
helps to achieve these goals.  Since inefficient use of electricity 
increases its cost, customers who are charged prices that reflect the 
cost of providing electrical service have real incentives to follow the 
most efficient usage patterns.  Included in the VPSB's order approving 
this rate design was a requirement that the Company's largest customers 
be charged time-of-use rates on a phased-in basis by 1994.  By year end 
December 31, 1996, approximately 1,350 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 its current rate design with the 
VPSB.  The parties, including the Department, IBM and a low-income 
advocacy group, entered into a settlement that was approved by the VPSB 
on December 2, 1994.  Under the settlement, the revenue allocation to 
each rate class was adjusted to reflect class-by-class cost changes 
since 1987, the differential between the winter and summer rates was 
reduced, the customer charge was increased for most classes, and usage 
charges were adjusted to be closer to the associated marginal costs.


     Dispatchable and Interruptible Service Contracts.  In 1996, the 
Company had interruptible/dispatchable power contracts with three major 
ski areas, interruptible-only contracts with five customers and 
dispatchable-only contracts with an additional twenty-four customers.  
The interruptible portion of the contracts allow the Company to control 
power supply capacity charges by reducing the Company's capacity 
requirements.  During 1996, 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 customer's demand 
during these periods is not considered in calculating the monthly 
billing.  This program provides customers with discretionary use of 
portions of their load and the opportunity to maximize their energy 
value, while, 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.


CONSTRUCTION AND CAPITAL REQUIREMENTS


     The Company's capital expenditures for 1994 through 1996 and 
projection for 1997 are set forth in Item 7. MD&A - "Liquidity and 
Capital Resources-Construction."  Construction projections are subject 
to continuing review and may be revised from time-to-time in accordance 
with changes in the Company's financial condition, load forecasts, the 
availability and cost of labor and materials, licensing and other 
regulatory requirements, changing environmental standards and other 
relevant factors.

     For the period 1994-1996, internally generated funds, after payment 
of dividends, provided approximately 60% of total capital requirements 
for construction, sinking fund obligations and other requirements.  
Internally generated funds provided 39% of such requirements for 1996, 
inclusive of an optional redemption of $7,200,000 of first mortgage 
bonds made by the Company.  The Company anticipates that for 1997, 
internally generated funds will provide approximately 87% of total 
capital requirements for regulated operations, the remainder to be 
derived from bank loans.

     In January 1996, a portion of the proceeds from the sale of 
$24,000,000 of the Company's first mortgage bonds in December 1995 was 
used to refund $7,200,000 of the Company's 10.7% first mortgage bonds.

     In October 1996, the Company issued $12,000,000 of its 7.32%, Class 
E, Series 1, preferred stock.  In November 1996, the Company sold
$10,000,000 of its first mortgage bonds at an interest rate of 7.18% and in 
December 1996, the Company sold $4,000,000  of its first mortgage bonds 
at an interest rate of 7.05%.  The proceeds from these transactions were 
used to repay short-term debt, to retire fixed income securities and for 
other general corporate purposes.

     In connection with the foregoing, see Item 7. MD&A - "Liquidity and 
Capital Resources."


ENVIRONMENTAL MATTERS


     The Company has been notified by the Environmental Protection 
Agency (EPA) that it is one of several potentially responsible parties 
for clean up at the Pine Street marsh site in Burlington, Vermont.  For 
information regarding the Pine Street Marsh and other environmental 
matters see Item 7. MD&A - "Environmental Matters" and Note I-2 of Notes 
to Consolidated Financial Statements.


UNREGULATED BUSINESSES


     The Company has had a plan of diversification into unregulated 
businesses that complements the Company's basic utility operations.  The 
diversification plan has involved the establishment of several 
subsidiaries, including Green Mountain Resources, Inc., which is engaged 
in the competitive marketing of energy products.  For information 
regarding unregulated businesses, see Item 7. MD&A- "Future Outlook - 
Unregulated Businesses."



EXECUTIVE OFFICERS

Executive Officers of the Company as of March 28, 1997:

      Name                Age
Thomas C. Boucher          42    Vice President, Business Strategy and
                                 Development since May 1996.  Vice President, 
                                 Energy Resources and Planning from 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.

Christopher L. Dutton      48    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.

Robert J. Griffin          40    Controller since October 7, 1996.  
                                 Manager of General Accounting from 1990 to 
                                 1996.

Francis J. Heald           55    President of Green Mountain Propane Gas 
                                 Company since June 1996.  Prior to joining 
                                 the Company, he was Executive Vice President 
                                 and General Manager of Pico Ski Resort, Inc.

Richard B. Hieber          58    Vice President, Electric Operations and 
                                 Engineering since September 1, 1996.  Prior 
                                 to joining the Company, he was President and 
                                 Chief Executive Officer of Stone & Webster 
                                 Management Consultants, Inc. from 1992 to 
                                 1996 and Senior Vice President from 1991 to 
                                 1992.

Douglas G. Hyde            54    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.  President of 
                                 Green Mountain Resource, Inc.

Donna S. Laffan            47    Corporate Secretary since December 
                                 1993.  Assistant Secretary from 1986 to 1993.

John J. Lampron            52    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.

Craig T. Myotte            42    Assistant Vice President-Engineering 
                                 and Operations since 1994.  Assistant Vice 
                                 President-Operations and Maintenance from 
                                 1991 to 1994.

Edwin M. Norse             51    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 from October 1993 to June 1996.


Walter S. Oakes            50    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.

Karen K. O'Neill           45    Assistant Vice President-Organizational 
                                 Development and Human Resources since June 
                                 1994.  Assistant General Counsel from 1989 to 
                                 1994.

Stephen C. Terry           54    Vice President and General Manager, 
                                 Retail Energy Services since January 1995.  
                                 Vice President-External Affairs from 1991 to 
                                 January 1995.

Jonathan H. Winer          45    President of Mountain Energy, Inc. 
                                 since March 1997.  Vice President and Chief 
                                 Operating Officer from 1989 to March 1997.

Robert C. Young            59    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.

Peter H. Zamore            44    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 of the Company, 
Mountain Energy, Inc., Green Mountain Resources, Inc. or Green Mountain 
Propane Gas Company, as appropriate, for one-year terms and serve at the 
pleasure of such boards 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 73.2 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 17.6624% (93.8 MW of a total 531 MW) of the capacity of 
Vermont Yankee, a 1.1% (6.8 MW of a total 620 MW) joint-ownership share 
of the Wyman #4 plant located in Maine, an 8.8% (31.0 MW of a total 352 
MW) joint-ownership share of the Stony Brook I intermediate units 
located in Massachusetts and an 11% (5.9 MW of a total 53 MW) joint-
ownership share of the J.C.EMcNeil wood-fired steam plant located in 
Burlington, Vermont.  See Item 1. Business - "Power Resources" for plant 
details and the table hereinafter set forth for generating facilities 
presently available.


TRANSMISSION AND DISTRIBUTION


     The Company had, at December 31, 1996, 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 includes about 2,384 miles of overhead lines, 2.4 kV 
to 34.5 kV, and about 432 miles of underground cable of 2.4 kV to 
34.5 kV.  At such date, the Company owned approximately 153,275 kVa of 
substation transformer capacity in transmission substations, 446,050 kVa 
of substation transformer capacity in distribution substations and 
1,260,901 kVa of transformers for step-down from distribution to 
customer use.

     The Company owns 33.8% of the Highgate transmission intertie, a 
225-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 Item 1. Business - "Power Resources."

                                                                     
                                                                       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       16.1

Jointly Owned  Steam    Vernon, VT         Vermont Yankee    Nuclear   93.8(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                                                 255.6

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

(2)   For a discussion of the impact of various power supply sales on 
the availability of generating facilities, see Item 1. Business - 
"Power Resources - 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-3 of Notes to Consolidated Financial 
Statements.


ITEM 3.  LEGAL PROCEEDINGS


     See the discussion Item 7. MD&A - "Environmental Matters" 
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 under the symbol "GMP".  The following 
tabulation shows the high and low sales prices for the Common Stock on 
the New York Stock Exchange during 1996 and 1995:



                                            HIGH         LOW

        1996           First Quarter       $29 1/8      $26 7/8
                       Second Quarter       27 7/8       22 7/8
                       Third Quarter        26 3/8       23 1/2
                       Fourth Quarter       25 1/8       22 3/4

        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

     The number of common stockholders of record as of March 14, 1997 
was 8,716.

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

                    First       Second       Third       Fourth
                    Quarter     Quarter      Quarter     Quarter

      1996             53 cents   53 cents     53 cents    53 cents
      1995             53 cents   53 cents     53 cents    53 cents


     Dividend Policy -- The Company's current dividend policy is based 
on the continued validity of three assumptions:  The ability to achieve 
earnings growth, the receipt of an allowed rate of return that 
accurately reflects the Company's cost of capital, and the retention of 
its exclusive franchise. 

     There is a strong movement in Vermont to restructure the electric 
utility industry, to be implemented in 1998, in order to permit 
competition in the generation and retail sale of electricity.  Such 
restructuring is expected, among other things, to lead to a loss of the 
Company's current exclusive franchise for selling electricity at retail, 
even though the Company currently expects that it would retain its 
exclusive franchise to provide distribution service.  Also, a business 
operating in a competitive environment, including any unregulated 
activities by the Company, would by its nature engender a different type 
of earnings growth and volatility than is found in a regulated entity.  
Should restructuring be approved in Vermont, it is likely that the 
Company will reconsider its dividend policy and make appropriate changes 
so that anticipated payout levels are more commensurate with the risk of 
any new business activities to be undertaken and consistent with the 
capital needs of its businesses.  See Item 7. MD&A "Future Outlook - 
Competition and Restructuring" and Note C of Notes to Consolidated 
Financial Statements for discussion of limitations on dividends.

<TABLE>
<CAPTION>

SELECTED FINANCIAL DATA  (In thousands except per share amounts)

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

                                            1996         1995         1994         1993         1992
                                          ---------    ---------    ---------    ---------    ---------

<S>                                       <C>          <C>          <C>          <C>          <C>
Operating Revenues........................$179,009     $161,544     $148,197     $147,253     $145,240
Operating Expenses........................ 162,882      146,249      133,680      132,427      128,828
                                          ---------    ---------    ---------    ---------    ---------
  Operating Income........................  16,127       15,295       14,517       14,826       16,412
                                          ---------    ---------    ---------    ---------    ---------
Other Income
  AFUDC - equity..........................     175           27          263          273          186
  Other...................................   3,055        3,607        3,418        2,360        2,073
                                          ---------    ---------    ---------    ---------    ---------
    Total other income....................   3,230        3,634        3,681        2,633        2,259
                                          ---------    ---------    ---------    ---------    ---------
Interest Charges
  AFUDC - borrowed funds..................    (468)        (547)        (539)        (357)        (202)
  Other...................................   7,866        7,973        7,735        7,185        7,021
                                          ---------    ---------    ---------    ---------    ---------
    Total interest charges................   7,398        7,426        7,196        6,828        6,819
                                          ---------    ---------    ---------    ---------    ---------

Net Income................................  11,959       11,503       11,002       10,631       11,852

Dividends on Preferred Stock..............   1,010          771          794          811          831
                                          ---------    ---------    ---------    ---------    ---------
Net Income Applicable to Common Stock..... $10,949      $10,732      $10,208       $9,820      $11,021
                                          =========    =========    =========    =========    =========
Common Stock Data
  Earnings per share......................   $2.22        $2.26        $2.23        $2.20        $2.54
  Cash dividends declared per share.......   $2.12        $2.12        $2.12        $2.11        $2.08
  Weighted average shares outstanding.....   4,933        4,747        4,588        4,457        4,345



Financial Condition as of December 31
-------------------------------------
                                            1996         1995         1994         1993         1992
                                          ---------    ---------    ---------    ---------    ---------

Assets

 Utility Plant, Net.......................$189,853     $181,999     $175,987     $171,411     $164,723
 Other Investments........................  20,634       20,248       20,751       22,528       21,700
 Current Assets...........................  30,901       30,216       28,798       26,215       28,067
 Deferred Charges.........................  43,224       42,951       35,659       33,893       19,012
 Non-Utility Assets.......................  39,927       37,868       33,416       28,626       23,716
                                          ---------    ---------    ---------    ---------    ---------
  Total Assets............................$324,539     $313,282     $294,611     $282,673     $257,218
                                          =========    =========    =========    =========    =========

Capitalization and Liabilities

 Common Stock Equity......................$111,554     $106,408     $101,319      $97,149      $92,645
 Redeemable Cumulative Preferred Stock....  19,310        8,930        9,135        9,385        9,575
 Long-Term Debt, Less Current Maturities..  94,900       91,134       74,967       79,800       67,644
 Capital Lease Obligation.................   9,006        9,778       10,278       11,029       11,950
 Curent Liabilities.......................  21,037       32,629       40,441       37,925       30,099
 Deferred Credits and Other...............  54,968       52,041       49,434       40,214       33,264
 Non-Utility Liabilities..................  13,764       12,362        9,037        7,171       12,041
                                          ---------    ---------    ---------    ---------    ---------
  Total Capitalization and Liabilities....$324,539     $313,282     $294,611     $282,673     $257,218
                                          =========    =========    =========    =========    =========

</TABLE>


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

     This section presents management's assessment of Green Mountain 
Power Corporation's (the Company) financial condition and the principal 
factors having an impact on the results of its operations.  This 
discussion should be read in conjunction with the consolidated financial 
statements and notes thereto contained in this annual report.  This 
section contains forward-looking statements as defined under the 
securities laws.  Actual results could differ materially from those 
projected.  This section, particularly under "Future Outlook - 
Competition and Restructuring" and "Risk Factors," lists some of the 
reasons why results could differ materially from those projected.


EARNINGS SUMMARY


     Earnings per average share of common stock in 1996 were $2.22 as 
compared with $2.26 in 1995 and $2.23 in 1994. The 1996 earnings 
represent an earned return on average common equity of 10.0 percent. In 
both 1995 and 1994, the earned return on average common equity was 10.3 
percent.

     The 1996 decrease in earnings was primarily due to increased 
mandatory purchases of power from independent power producers resulting 
from greater production from in-state hydroelectric plants and unusually 
warm weather in December that adversely affected the Company's electric 
operating revenues and sales of propane by the Company's wholly-owned 
subsidiary, Green Mountain Propane Gas Company.

     The principal factors contributing to the increase in 1995 earnings 
were 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 energy generation and 
efficiency projects.


FUTURE OUTLOOK


     Competition and Restructuring -- The electric utility business is 
being subjected to rapidly increasing competitive pressures stemming 
from a combination of trends, including the presence of surplus 
generating capacity, a disparity in electric rates among and within 
various regions of the country, improvements in generation efficiency, 
increasing demand for customer choice, and new regulations and 
legislation intended to foster competition.  To date, this competition 
has been most prominent in the bulk power market, in which non-utility 
generators have significantly increased their market share.

     Electric utilities historically have had exclusive franchises for 
the retail sale of electricity in specified service territories.  As a 
result, competition for retail customers has been limited to (i) 
competition with alternative fuel suppliers, primarily for heating and 
cooling; (ii) competition with customer-owned generation; and (iii) 
direct competition among electric utilities to attract major new 
facilities to their service territories.  These competitive pressures 
have led the Company and other utilities to offer, from time to time, 
special discounts or service packages to certain large customers.

     In states across the country, including the New England states, 
there has been an increasing number of proposals to allow retail 
customers to choose their electricity suppliers, with incumbent 
utilities required to deliver that electricity over their transmission 
and distribution systems (also known as "retail wheeling").  Increased 
competitive pressure in the electric utility industry may restrict the 
Company's ability to charge prices high enough to recover embedded 
costs, such as the cost of purchased power obligations or of generation 
facilities owned by the Company.  The amount by which such costs might 
exceed market prices is commonly referred to as "stranded costs".

     Regulatory and legislative authorities at the federal level and 
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 Vermont Public Service Board 
(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 14 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 electric 
utility industry.  The Governor's announcement included proposed 
legislative adoption of restructuring principles, a VPSB proceeding to 
address the issue, the submission by Vermont electric utilities of 
detailed plans by May 1, 1996, and implementation of restructuring by 
the beginning of 1998.  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.

     On October 16, 1996, the VPSB issued a Draft Report and Order which 
proposed the commencement of competitive retail sales of electricity in 
early 1998, while distribution and transmission functions would remain 
subject to regulation.  The Company and other parties responded to the 
Draft Report and Order in November 1996, and the VPSB issued its Final 
Order on December 31, 1996.

     The Final Order requires that Vermont investor-owned utilities 
divide their competitive retail and regulated distribution and 
transmission functions into separate corporate subsidiaries in order to 
achieve a functional separation of regulated and unregulated businesses, 
and provides for competition for all customer classes to be completed by 
the end of 1998.  In view of this change in structure as well as the 
unknown relative level of competition each corporation may face, the 
Company cannot predict the future cost or availability of capital for 
the new subsidiary corporations.  Furthermore, most of the assets of the 
Company are encumbered by a lien of the Company's First Mortgage 
Indenture.  The Company cannot predict with certainty at this time the 
cost and feasibility of obtaining approval from the existing 
bondholders, to the extent that it is determined that such approvals are 
necessary, in order to achieve functional separation.

     The Final Order proposes an approach that takes into account 
multiple factors that the VPSB believes will "create the opportunity for 
full recovery of stranded costs provided they are legitimate, 
verifiable, otherwise recoverable, prudently incurred and non-
mitigable," but the Final Order also states the VPSB's belief that "an 
opportunity for full recovery must be explicitly tied to successful 
mitigation."  The Final Order further provides that, where a utility has 
successfully mitigated its stranded costs, the opportunity should exist 
for substantial or full recovery of stranded costs when the magnitude of 
the post-mitigation stranded costs, among other things, allows for rates 
that are comparable to regional rates.

     The Final Order calls for a multi-step process that would involve 
(1) a rigorous estimate of stranded costs (which in turn would require 
an estimate of future power costs) and a determination of the extent to 
which stranded costs can be mitigated, (2) an adjustment of stranded 
costs based on mitigation of such costs and changes in the market price 
of power, and (3) a stranded cost reconciliation proceeding.  The 
process would consider each utility's estimate of stranded costs and the 
success of its mitigation efforts on a case by case basis.

     The Final Order proposes that allowed stranded cost recovery be 
accomplished through the use of a non-bypassable access charge, or 
Competitive Transition Charge (CTC), collected by the regulated 
distribution company.  The Final Order also endorses the securitization 
of stranded costs through the assignment of CTC receipts as a means of 
achieving lower-cost financing and the Final Order supports legislative 
action to achieve these savings.

     The Company, Central Vermont Public Service Corporation (CVPS), 
representatives of the Governor of Vermont and the Department are in the 
process of negotiating a Memorandum of Understanding (MOU) that would 
outline agreed-upon positions among the parties relative to the recovery 
of stranded costs, distribution company rates, corporate unbundling and 
societal benefit programs.  The parties to the MOU mutually would 
support those provisions in connection with any proposed legislation 
before the Vermont General Assembly and in any regulatory proceeding 
before the VPSB.  If all of the terms of the MOU are not included in 
final restructuring legislation and in an implementing VPSB Order, the 
MOU will be of no force or effect.

     Although not executed as of March 6, 1997, it is likely that the 
MOU will include the following financial terms:

	If the Company were able to reduce its power costs by $105 million 
(on a net present value basis assuming a 10% discount rate), then 
it would be conclusively deemed to have adequately mitigated 
stranded costs for the purpose of recovering its remaining stranded 
costs.  The closer the Company is to the mitigation target, the 
greater the likelihood that the Company will recover all of its 
remaining stranded costs.

	The CTC would be fixed initially at $30/MWh for the first two years 
of retail competition. Any under-collections or over-collections of 
the CTC, respectively, would be added to or subtracted from the 
unrecovered stranded cost balance.  The CTC would be adjusted 
annually thereafter to achieve recovery of stranded costs by the 
end of 2012.

	Unbundled distribution subsidiary rates would be frozen for 1998 
and 1999 and adjusted by 70% of the change in the consumer price 
index for calendar years 2000 through 2004.  Some portion of the 
frozen and subsequent rates would be dependent on achieving 
mutually agreed upon performance targets regarding quality of 
service.  The distribution subsidiary would also be able to 
petition the VPSB for relief due to significant factors out of the 
control of the distribution subsidiary, such as, but not limited 
to, a change in income tax rates, the need for significant capital 
expenditures to meet material customer expansions, natural 
catastrophes or significant changes in load growth.

     Proposals are currently being debated before the Vermont General 
Assembly that would allow all classes of customers in Vermont to choose 
their power supplier beginning in 1998.  The terms of most of the 
proposed legislation are generally consistent with the approach set 
forth in the Final Order regarding eligibility for stranded cost 
recovery, although some would permit less stranded cost recovery.

     There is no assurance that any restructuring legislation will be 
enacted by the Vermont General Assembly, or if legislation is enacted, 
that it will be consistent with the terms of the Final Order or the MOU.

     Risk Factors -- The major risk factors affecting the impact of 
electric industry restructuring upon the Company, including the recovery 
of stranded costs, are: (i) regulatory and legal decisions, (ii) the 
market price of power, and (iii) the amount of market share retained by 
the Company.  There can be no assurance that a final restructuring plan 
ordered by VPSB, the courts, or through legislation will include a CTC 
that would allow for full recovery of stranded costs and include a fair 
return on those costs as they are being recovered.  If laws are enacted 
or regulatory decisions are made that do not offer an opportunity 
adequately to recover stranded costs, the Company believes it has legal 
arguments to challenge such laws or decisions.

     The largest category of the Company's stranded costs are future 
costs under long-term power purchase contracts.  The Company intends to 
pursue compliance with the steps outlined in the Final Order and 
aggressively to pursue mitigation efforts in order to maximize its 
recovery of these costs.  The magnitude of stranded costs for the 
Company is largely dependent upon the future market price of power.  The 
Company has discussed various market price scenarios with interested 
parties for the purpose of identifying stranded costs.  Preliminary 
market price assumptions, which are likely to change, have resulted in 
estimates of the Company's stranded costs of between $330 million and 
$564 million, on a net present value basis, discounted at a rate of 10%.

     If retail competition is implemented in Vermont and elsewhere, the 
Company is unable to predict the impact of this competition on its 
revenues, on the Company's ability to retain existing customers and 
attract new customers, or on the margins that will be realized on retail 
sales of electricity.

     Historically, electric utility rates have been based on a utility's 
costs.  As a result, electric utilities are subject to certain 
accounting standards that are not applicable to other business 
enterprises in general.  Statement of Financial Accounting Standards 
(SFAS) 71, Accounting for Certain Types of Regulation, requires 
regulated entities, in appropriate circumstances, to establish 
regulatory assets and liabilities, and thereby defer the income 
statement impact of certain costs and revenues that are expected to be 
realized in future rates.

     As described in Note A.2 in the Notes to Consolidated Financial 
Statements, the Company complies with the provisions of SFAS 71.  In the 
event the Company determines that it no longer meets the criteria for 
following SFAS 71, the accounting impact would be an extraordinary, non-
cash charge to operations of an amount that could be material.  Criteria 
that give rise to the discontinuance of SFAS 71 include (1) increasing 
competition that restricts the Company's ability to establish prices to 
recover specific costs and (2) a change in the manner in which rates are 
set by regulators from cost-based regulation to another form of 
regulation.

     The Company believes that the provisions of both the Final Order 
and MOU, if implemented, would meet the criteria for continuing 
application of SFAS 71 as to those costs for which recovery is 
permitted.  Because the Company is unable to predict what form enacted 
legislation will take, however, it cannot predict if or to what extent 
SFAS 71 will continue to be applicable in the future.

     SFAS 121, Accounting for the Impairment of Long Lived Assets, which 
was implemented by the Company on January 1, 1996, requires that any 
assets, including regulatory assets, that 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 regulatory assets which are no longer probable of 
recovery.  As of December 31, 1996, based upon the regulatory 
environment within which the Company currently operates, SFAS 121 did 
not have an impact on the Company's financial position or results of 
operations.  Competitive influences or regulatory developments may 
impact this status in the future.

     Thus, the Company cannot predict whether restructuring legislation 
enacted by the Vermont General Assembly or any subsequent report or 
actions of, or proceedings before, the VPSB or Vermont General Assembly 
would have a material adverse effect on the Company's operations, 
financial condition or credit ratings.  The Company's failure to recover 
a significant portion of its purchased power costs, or to retain and 
attract customers in a competitive environment, would likely have a 
material adverse effect on the Company's business, including its 
operating results, cash flows and ability to pay dividends at current 
levels.

     Unregulated Businesses -- For several years, the Company has had a 
plan of diversification into unregulated businesses that complements the 
Company's basic utility operations.  The following is a discussion of 
the Company's unregulated enterprises, including its newest subsidiary, 
which is engaged in the competitive retail marketing of energy products.

     Mountain Energy, Inc., which has invested in energy-related 
businesses, earned $1.32 million in 1996, a slight decrease from 1995's 
net income of $1.38 million.  The 1996 results contributed 27 cents of 
earnings per share to the Company's consolidated results as compared to 
29 cents in 1995.

     Since its formation in 1989, Mountain Energy has invested more than 
$17 million in nine operating energy projects, including two California 
wind projects, hydroelectric projects in California and New Hampshire, a 
gas cogeneration facility in Illinois and energy efficiency 
installations in Maine, New York, New Jersey, Massachusetts and Hawaii.

     In March 1997, Mountain Energy broadened its investment portfolio 
by acquiring a 35 percent ownership interest in Micronair, LLC, which 
owns certain patent rights to a wastewater treatment system that 
provides an innovative and efficient solution to the sludge disposal 
issues facing the United States.  The Micronairr system enhances both 
the processing and energy efficiency at wastewater facilities, virtually 
eliminating sludge as a byproduct.  This environmentally and 
economically desirable result has already been demonstrated in several 
commercial facilities.

     Green Mountain Propane Gas Company, which sells propane gas at 
retail in Vermont and New Hampshire, experienced a $335,000 loss in 1996 
as compared to a $347,000 loss in 1995.  The loss in 1996 was due 
primarily to strong competition, low margins due to significant 
wholesale price fluctuations, increased producer pipeline restrictions 
beginning in November 1996 and warmer than normal weather in December 
1996.  In 1995, the loss was due primarily to warmer than normal weather 
in the first quarter of 1995 and reduced margins due to strong 
competition.  In both 1996 and 1995, the losses reduced the Company's 
consolidated earnings by 7 cents per share.

     The Company's unregulated rental water heater business earned 
$379,000 in 1996, an increase from 1995's net income of $308,000. The 
increase in income in 1996 was attributable to an increase in the rental 
rate charged to customers.  The 1996 results contributed 8 cents of 
earnings per share to the Company's consolidated results as compared to 
6 cents in 1995.

     Green Mountain Resources, Inc. (GMRI) was formed in April 1996 to 
explore opportunities in competitive retail energy markets.  In 1996, 
GMRI, together with subsidiaries of Hydro-Quebec, Consolidated Natural 
Gas Corporation and Noverco, Inc., participated in the retail sales of 
energy in pilot programs in New Hampshire and Massachusetts through 
Green Mountain Energy Partners L.L.C. (GMEP).

     The State of New Hampshire has undertaken an experiment to provide 
retail customer choice in the purchase of electricity.  The New 
Hampshire pilot program is one of the nation's first significant 
attempts to test the viability of retail electric competition.  GMEP has 
been competing in New Hampshire since May 1996 with approximately two 
dozen other suppliers to serve 17,000 eligible customers.  The pilot 
program will extend two years, with service that began in June 1996.

     The Commonwealth of Massachusetts authorized Bay State Gas 
Company's Pioneer Valley Customer Choice Residential Pilot Program (the 
Bay State Gas Pilot), in which GMEP is participating.  The Bay State Gas 
Pilot permits the retail sale of natural gas to up to 10,000 eligible 
residential customers and will extend for two years with service that 
began in November 1996.

     GMRI experienced a $579,000 loss in 1996, its first year of 
operation.  The loss experienced was consistent with the Company's 
expectation and reflects a limited number of pilot customers coupled 
with significant price competition on the part of energy providers 
participating in the retail pilots.  The 1996 results reduced the 
Company's consolidated earnings by 12 cents per share.  This loss was 
mitigated to a large extent by offsetting payments the Company received 
from GMEP for work performed on its behalf.

     The Company believes that participation in these pilot programs 
will enhance the capability of GMRI to compete in additional markets 
that are opened for retail electric and natural gas customer choice. 
GMRI may decide to participate in other retail energy programs that are 
developed through GMEP or other entities that may be formed in the 
future.


RESULTS OF OPERATIONS


Operating Revenues and MWh Sales--Operating revenues and megawatthour 
(MWh) sales for the years 1996, 1995 and 1994 consisted of:

                                          1996         1995         1994
                                          ----         ----         ---- 
                                              (Dollars in Thousands)
Operating Revenues:
   Retail . . . . . . . . . . . . .   $ $154,916   $ 140,676     $ 131,444 
   Sales for Resale . . . . . . . .       20,667      17,541        13,521 
   Other  . . . . . . . . . . . . .        3,426       3,327         3,232 
                                      ----------   ---------     ---------
Total Operating Revenues  . . . . .   $  179,009   $ 161,544     $ 148,197
                                      ==========   =========     ========= 
MWh Sales:
   Retail . . . . . . . . . . . . .    1,775,711   1,723,117     1,691,867 
   Sales for Resale . . . . . . . .      701,835     620,655       367,424 
                                       ---------   ---------     ---------
Total MWh Sales  . .  . . . . . . .    2,477,546   2,343,772     2,059,291
                                       =========   =========     =========  
Average Number of Customers:
   Residential  . . . . . . . . . .       70,198      69,659        68,811 
   Commercial & Industrial  . . . .       11,853      11,736        11,635 
   Other  . . . . . . . . . . . . .           75          76            76 
                                          ------      ------        ------
Total Customers . . . . . . . . . .       82,126      81,471        80,522 
                                          ======      ======        ======

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

                                                    1995          1994
                                                     to            to 
                                                    1996          1995
                                                    ----          ----
                                                       (In Thousands)
Operating Revenues:
   Retail Rates . . . . . . . . . . . . . . .    $  9,654       $ 6,619 
   Retail Sales Volume  . . . . . . . . . . .       4,586         2,613 
   Resales and Other Revenues . . . . . . . .       3,225         4,115 
                                                  -------        ------
Increase in Operating Revenues  . . . . . . .     $17,465       $13,347
                                                  =======       =======

     In 1996, total electricity sales increased 5.7 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 10.8 percent in 1996 primarily due to 
retail rate increases of 9.25 percent and 5.25 percent that went into 
effect in June 1995 and June 1996, respectively, and the increase in 
electricity sales mentioned above. Total retail revenues increased 10.1 
percent in 1996 primarily due to the retail rate increases mentioned 
above. Wholesale revenues increased 17.8 percent in 1996 primarily due 
to the regional market conditions mentioned above.

     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 previously mentioned. 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.

     IBM, the Company's single largest customer, operates manufacturing 
facilities in Essex Junction, Vermont. IBM's electricity requirements 
for its main plant and an adjacent plant accounted for 13.2, 12.9 and 
13.7 percent of the Company's operating revenues in 1996, 1995 and 1994, 
respectively. No other retail customer accounted for more than one 
percent of the Company's revenue.

     In February 1995, the Company and IBM entered into an Economic 
Development Agreement (EDA) that established the price to be paid by IBM 
at its Essex Junction facility for incremental electric usage during 
1995, 1996 and 1997.  The contract, which is intended to promote growth 
in IBM's operations and create jobs in the Company's service area, 
applies only to that portion of IBM's load that exceeds its 1994 
consumption level.  Most of IBM's electric usage is billed under the 
Company's tariff rate.  The EDA price, although lower than the Company's 
tariff rate, exceeds the Company's marginal costs of providing this 
incremental electric service to IBM.  The VPSB approved the EDA in June 
1995.  The Company believes that the EDA benefits the Company because it 
encourages the incremental purchase of electricity by IBM at a price 
above the Company's marginal cost of providing such incremental service.

     Power Supply Expenses -- Power supply expenses constituted 61.5 
percent, 60.1 percent and 59.2 percent of total operating expenses for 
the years 1996, 1995 and 1994, respectively. These expenses increased by 
$12.3 million (14.0 percent) in 1996 and by $8.7 million (11.0 percent) 
in 1995.

     Power supply expenses increased in 1996 primarily due to higher 
costs for power purchased from Hydro-Quebec, increases in mandatory 
purchases from independent power producers and purchases of additional 
power to service increased electricity sales.

     Vermont Yankee's operating expenses for 1996 exceeded the level of 
such expenses incurred during 1995 by approximately $1.3 million, of 
which approximately $230,000 was allocated to the Company.  In 1996, 
Vermont Yankee elected to accelerate certain safety and management 
related projects intended to improve efficiency of the plant and assure 
compliance with Nuclear Regulatory Commission regulations and the 
facility's operating license.

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

     Under an arrangement negotiated in January 1996, the Company 
received cash payments from Hydro-Quebec of $3.0 million in 1996 and 
will receive $1.1 million in 1997.  Consistent with allowed ratemaking 
treatment, the $3.0 million payment reduced purchase power expense by 
$1.75 million in 1996; the balance of the payment will reduce power 
costs in 1997.  The $1.1 million payment will reduce purchase power 
expense ratably over the period beginning June 1997 and ending May 1998.

     In response, the Company will shift up to 40 megawatts of its 
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 from 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 on a net 
present value basis.

     In November 1996, the Company entered into a Memorandum of 
Understanding with Hydro-Quebec providing for the payment to the Company 
of $8.0 million in 1997 in exchange for Hydro-Quebec's right to elect, 
on or before September 1, 1997, one of two options to purchase power.  
Under the first option, for the period commencing November 1, 1997 and 
effective through the remaining term of the 1987 power supply agreement 
between the Company and Hydro-Quebec (the 1987 Agreement), which expires 
in 2015, Hydro-Quebec can exercise an option to purchase on an annual 
basis, at energy prices established in accordance with the 1987 
Agreement, an amount of energy equivalent to the Company's firm capacity 
entitlements in the 1987 Agreement, delivered at up to an approximately 
10.5 percent capacity factor, or 105,000 MWh.  Under the second option, 
for the period commencing November 1, 1997 and effective through the 
remaining term of the 1987 Agreement, Hydro-Quebec can exercise an 
option to purchase on an annual basis, at energy prices established in 
accordance with the 1987 Agreement, an amount of energy equivalent to 
the Company's firm capacity entitlements in the 1987 Agreement, 
delivered at up to an approximately 5.25 percent capacity factor, or 
52,500 MWh.  Hydro-Quebec also would have the right under the second 
option to elect to purchase up to 600,000 MWh of power from the Company 
over the remaining term of the 1987 Agreement, commencing November 1, 
1997, at the energy prices established in accordance with the 1987 
Agreement, subject to certain annual and hourly volume limitations.

     On December 31, 1996, the Company received an accounting order from 
the VPSB that provides for recognition in 1997 revenues of the present 
value payment of $8 million.  The accounting order also continues the 
limitation on the return on equity from utility operations of 11.25 
percent which had been a part of the Company's last two rate settlements 
through December 31, 1997.  The Company estimates that the future costs 
associated with the Memorandum of Understanding to be approximately $8.0 
million on a net present value basis.  Consistent with allowed 
ratemaking treatment, the $8.0 million payment will be recognized in 
income in the third and fourth quarters of 1997.

     Other Operating Expenses -- Other operating expenses decreased 2.8 
percent in 1996 primarily due to a decrease in salaries resulting from a 
reduction in the workforce and to a decrease in medical insurance claims 
experienced by the Company.

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

     Transmission Expenses -- Transmission expenses increased 9.7 
percent in 1996 primarily due to higher tariff rates under an 
interconnection agreement between CVPS and the Company discussed below.  
This increase was offset to a large extent by revenues generated by the 
same interconnection agreement.

     On August 28, 1996, the Company received a bill totaling 
approximately $1.9 million from CVPS for service at certain transmission 
interconnections that are the subject of a 1993 interconnection 
agreement between the Company and CVPS.  The bill covered the period 
October 1993 through June 1996.

     In September 1996, the Company charged approximately $700,000 of 
the CVPS invoice to transmission rent expense.  The Company disputes the 
amount of the CVPS billing and estimates its liability in the range of 
$1.0 million to $1.3 million, inclusive of amounts already expensed.

     The Company has submitted a bill totaling approximately $500,000 to 
CVPS for its services under the same interconnection agreement, and 
credited this amount to transmission services in September 1996.  CVPS 
disputes approximately $100,000 of the amount billed by the Company.

     On December 31, 1996, the Company received an accounting order from 
the VPSB requiring that amounts deferred under the interconnection 
agreement be expensed over the remaining eleven years of the agreement.  
The interconnection agreement contains an arbitration clause for the 
settlement of disputes.  The Company has requested arbitration and is 
unable to predict the ultimate outcome of that proceeding.

     Transmission expenses decreased 4.8 percent in 1995 primarily due 
to cost reduction measures implemented by Vermont Electric Power Company 
(VELCO), a corporation engaged in the transmission of electric power 
within the State of Vermont in which the Company has an equity interest.

     Maintenance Expenses -- Maintenance expenses increased 6.0 percent 
in 1996 due principally to a scheduled increase in plant maintenance.

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

     Depreciation and Amortization -- Depreciation and amortization 
expenses increased 15.3 percent in 1996 primarily due to the 
amortization of expenditures related to energy conservation programs and 
the Pine Street Marsh environmental matter (See Note I of the Notes to 
Consolidated Financial Statements) and to the depreciation of 
expenditures related to additional investment in the Company's 
distribution facilities.

     Depreciation and amortization expenses increased 32.1 percent in 
1995 for the same reasons.

     Income Taxes -- The effective federal income tax rates for the 
years 1996, 1995 and 1994 were 27.2 percent, 25.3 percent and 25.1 
percent, respectively.

     Other Income -- Other income decreased 11.1 percent in 1996 
primarily due to a $579,000 loss experienced by GMRI. The impact of the 
GMRI loss on consolidated earnings was mitigated to a large extent by 
offsetting payments received by the Company from GMEP for work performed 
on its behalf.

     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. These decreases were partially offset by a $557,000 increase in 
earnings of Mountain Energy, Inc.

     Dividends on Preferred Stock -- Dividends on preferred stock 
increased 31.0 percent in 1996 primarily due to the issuance of 120,000 
shares of the Company's 7.32 percent, Class E, Series 1 preferred stock 
in October 1996.

     Dividends on preferred stock decreased 2.9 percent in 1995 
primarily due 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.

     Interest Charges -- Interest charges were virtually unchanged in 
1996. An increase in interest charges related to a higher amount of 
long-term debt outstanding during the year and a decrease in the 
allowance for funds used during construction were slightly more than 
offset by a reduction in interest charges related to a lower amount of 
short-term debt outstanding during the year.

     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 the amount of long-term debt 
outstanding during 1995.


TRANSMISSION ISSUES


     Federal Open Access Tariff Orders -- On April 24, 1996, the Federal 
Energy Regulatory Commission (FERC) issued Orders 888 and 889 which, 
among other things, required the filing of open access transmission 
tariffs by electric utilities, and the functional separation by 
utilities of their transmission operations from power marketing 
operations.  Order 888 also supports the full recovery of legitimate and 
verifiable wholesale power costs previously incurred under federal or 
state regulation.  The Company is currently in the process of responding 
to the orders.  On July 9, 1996, the Company filed with the FERC the 
non-discriminatory open access tariffs required by Order 888.  The 
tariffs defined the Company's transmission system to include 
subtransmission facilities owned by the Company and the Company's 
entitlement to facilities owned by VELCO.  The Company's tariffs 
included charges related to the use of the VELCO transmission system by 
customers.  Other Vermont utilities required to make filings with the 
FERC under Order 888 followed the same course of action.  VELCO, in 
turn, submitted to the FERC a request for waiver of its obligation to 
file a separate open access transmission tariff.  On September 11, 1996, 
the FERC denied VELCO's waiver request.  The Company is also in the 
process of modifying its tariff to comply with various orders of the 
FERC and in addition complying with the FERC's regulations relating to 
OASIS, the electronic bulletin board to be used to post availability of 
transmission capacity.  

     In accordance with Order 889, the Company has also functionally 
separated its transmission operations and filed with the FERC a code of 
conduct for its transmission operations.  The Company does not 
anticipate any material adverse effects or loss of wholesale customers 
due to the FERC orders mentioned above.

     Proposed NEPOOL Transmission Tariff -- Under an allocation 
agreement among VELCO, Northeast Utilities and New England Power 
Corporation, VELCO currently has 14 percent of the capacity of 
transmission facilities between New England, New York and Canada.  
VELCO's capacity for such transmission facilities is allocated among 
Vermont electric utilities, including the Company.   NEPOOL has filed a 
proposed tariff with the FERC that incorporates a load-based method of 
capacity allocation for NEPOOL transmission facilities that would reduce 
the amount of capacity allocated to VELCO for such transmission 
facilities in the future.   A reduction of VELCO's allocation of 
capacity  on transmission interfaces with New York and Canada would 
adversely effect the Company's ability to import power to Vermont from 
outside New England which would impact the Company's power costs in the 
future.  VELCO and the Company have filed comments with the FERC seeking 
to change the effect of the proposed NEPOOL capacity allocation 
procedures but the Company is unable to predict at this time the outcome 
of these proceedings before the FERC.  


ENVIRONMENTAL MATTERS


     Public concern for the environment has resulted in increased 
government regulation of the licensing and operation of electric 
generation, transmission and distribution facilities.   The electric 
industry typically uses or generates a range of potentially hazardous 
products in its operations.  The Company must meet various land, water, 
air and aesthetic requirements as administered by local, state and 
federal regulatory agencies.    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 developments concerning the Pine Street Marsh 
site described below, 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.

     The Federal Comprehensive Environmental Response, Compensation, and 
Liability Act (CERCLA), commonly known as the "Superfund" law, generally 
imposes strict, joint and several liability, regardless of fault, for 
remediation of property contaminated with hazardous substances.  The 
Company has been notified by the Environmental Protection Agency (EPA) 
that it is one of several potentially responsible parties (PRPs) for 
cleanup of the Pine Street Marsh site in Burlington, Vermont, where coal 
tar and other industrial materials were deposited.  From the late 19th 
century until 1967, gas was manufactured at the Pine Street Marsh site 
by a number of enterprises, including the Company.  In 1990, the Company 
was one of the 14 parties that agreed to pay a total of $945,000 toward 
the EPA's past response under a confidential Consent Decree.  The 
Company remains a PRP for ongoing and future response costs.  In 
November 1992, the EPA proposed a cleanup plan estimated by the EPA to 
cost $47 million.  In June 1993, the EPA withdrew this cleanup plan in 
response to public concern about the plan and its cost.  The cost of any 
future cleanup plan, the magnitude of unresolved EPA cost recovery 
claims, and the Company's share of such costs are uncertain at this 
time.

     Since 1994, the EPA has established a coordinating council, with 
representatives of PRPs, environmental and community groups, the City of 
Burlington and the State of Vermont, presided over by a neutral 
facilitator.  The council has determined, by consensus, what additional 
studies were appropriate for the site, and is addressing the question of 
additional response activities.  The EPA, the State of Vermont and other 
parties have entered into two consent orders for completion of 
appropriate studies.  Work is continuing under the second of those 
orders.  On December 1, 1994, the Company and two other PRPs, New 
England Electric System (NEES) and  Vermont Gas Systems (VGS), entered 
into a confidential agreement with the State of Vermont, the City of 
Burlington and nearly all other landowner PRPs under which, subject to 
certain qualifications, 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.  In March 1996, the Company and 
NEES entered into a confidential agreement compromising past and future 
contribution and cost recovery claims of both parties relating to 
response costs.

     In December 1991, the Company brought suit against eight previous 
insurers seeking recovery of unrecovered past costs and indemnity 
against future liabilities associated with environmental problems at the 
site.  Discovery in the case, which was previously subject to a stay, is 
proceeding and is largely complete.  A trial in this litigation is 
scheduled for late 1997.  The Company has reached confidential final 
settlements with two of the defendants in this litigation and has 
obtained summary judgment declaring one non-settling insurer's duty to 
defend.

     The Company has deferred amounts received, under confidential 
settlement, 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 to 
investigate and remediate the site, 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, 1994 and 1995, 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 incurred between January 1, 
1991 and June 30, 1995 (in the total of approximately $8.7 million) for 
technical consultants and legal assistance in connection with the 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 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 in those 
proceedings reflected the Pine Street Marsh related expenditures 
referred to above.

     Management expects to seek and (assuming recovery 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.

     An authoritative accounting standard, Statement of Position (SOP) 
96-1, has been issued by the accounting profession addressing 
environmental remediation obligations.  This SOP is effective for years 
beginning in 1997, and addresses, among other things, regulatory 
benchmarks that are likely triggers of the accrual of estimated losses, 
the costs included in the measurement, including incremental costs of 
remediation efforts such as post-remediation monitoring and long-term 
operation and maintenance costs and costs of compensation and related 
benefits of employees devoting time to the remediation.  After reviewing 
the Company's current accounting policies and ratemaking treatment, 
management does not believe that this SOP will have a material adverse 
effect on the Company's financial position or results of operations upon 
adoption.


     Clean Air Act -- 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 
Act or proposals to make more stringent regulations under that Act.  
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.


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.  If restructuring does 
occur, the Company will reassess its capital expenditures for generation 
and other projects and the terms of financing thereof.

Capital expenditures over the past three years and projected for 
1997 are as follows:

<TABLE>
<CAPTION>

                                                                       Total Net
Actual  Generation  Transmission  Distribution   Conservation   Other  Expenditures

(Dollars in thousands and net of AFUDC and Customer Advances For Construction)

 <S>     <C>          <C>            <C>            <C>         <C>       <C>
 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
 1996     6,289*         528          8,422          3,090       3,394     21,723
Forecasted 
 1997    $2,680       $1,355         $8,591         $2,300      $7,504    $22,430
*Includes $4.978 million for wind project

</TABLE>

     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 that the Company secured to replace power 
supply that will be lost in the near future, and the cost of energy 
efficiency programs that the Company 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 for utility 
operations of 11.25 percent.  In the event that the target return on 
equity is exceeded, the Company would accelerate the amortization of 
certain demand side management expenditures in the next year for which 
rate recovery otherwise would have been sought.  The agreement was 
approved by the VPSB on June 9, 1995.

     In September 1995, the Company filed a 12.7 percent retail rate 
increase application 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.  Early in 1996, the Company settled this rate case with the 
Department and other parties.

     The settlement became possible when the Company negotiated a new 
arrangement with Hydro-Quebec that will reduce the Company's net power-
supply costs below the amounts anticipated in the rate increase request.  
The settlement provided:  projected additional annual revenues of $7.6 
million; an overall increase in retail rates of 5.25 percent effective 
June 1, 1996; target return on equity for utility operations of 11.25 
percent (with a continuation of the amortization of any amount in excess 
of the target rate of return in the following year, as described above); 
and recovery of $1.3 million of costs associated with the Pine Street 
Marsh site, amortized over five years.  The VPSB approved the settlement 
in an order dated May 23, 1996.  In 1996, the rate of return on utility 
operations was 11.8% and in 1995 was 11.3%.  An accounting order 
received from the VPSB on December 31, 1996 continues the limitation on 
return on equity from utility operations through December 31, 1997.


     Dividend Policy -- The Company's current dividend policy is based 
on the continued validity of three assumptions:  The ability to achieve 
earnings growth, the receipt of an allowed rate of return that 
accurately reflects the Company's cost of capital, and the retention of 
its exclusive franchise.  As discussed under "Future Outlook-Competition 
and Restructuring," there is a strong movement in Vermont to restructure 
the electric utility industry, to be implemented in 1998, in order to 
permit competition in the generation and retail sale of electricity.  
Such restructuring would, among other things, lead to a loss of the 
Company's current exclusive franchise for selling electricity at retail, 
even though the Company would retain its exclusive franchise to provide 
distribution service.  Also, a business operating in a competitive 
environment, including any unregulated activities by the Company, would 
by its nature engender a different type of earnings growth and 
volatility than is found in a regulated entity.  Should restructuring be 
approved in Vermont, it is likely that the Company will reconsider its 
dividend policy and make appropriate changes so that anticipated payout 
levels are more commensurate with the risk of any new business 
activities to be undertaken and consistent with the capital needs of its 
businesses.


     Financing and Capitalization -- For the period 1994 through 1996, 
internally generated funds, after payment of dividends, provided 
approximately 60 percent of total capital requirements for construction, 
sinking funds and other requirements.  The Company anticipates that for 
1997, internally generated funds will provide approximately 87 percent 
of total capital requirements for regulated operations.

     In January 1996, a portion of the proceeds from the sale of $24 
million of the Company's first mortgage bonds in December 1995 was used 
to refund $7.2 million of the Company's 10.7 percent first mortgage 
bonds.

     In October 1996, the Company issued $12 million of its 7.32 
percent, Class E, Series 1, preferred stock.  In November 1996, the 
Company sold $10 million of its first mortgage bonds at an interest rate 
of 7.18 percent and in December 1996, the Company sold $4 million of its 
first mortgage bonds at an interest rate of 7.05 percent.  The proceeds 
from these transactions were used to repay short-term debt, to retire 
fixed income securities and for other general corporate purposes.

     At December 31, 1996, the Company's capitalization consisted of 
48.8 percent common equity, 42.8 percent long-term debt and 8.4 percent 
preferred equity.  The Company has a comprehensive capital plan to 
increase the equity component of its capital structure.

     The rating of the Company's first mortgage bonds by Standard & 
Poor's remains at "BBB+."  In 1996, a rating of "BBB" was assigned to 
the Company's preferred stock.  Standard & Poor's "outlook" of the 
Company remains "stable."

     The rating of the Company's first mortgage bonds by Duff & Phelps 
was lowered in September 1996 from "A-" to "BBB+."  The rating of the 
Company's preferred stock was also lowered from "BBB+" to "BBB."  These 
ratings reflect Duff & Phelps' assessment that the electric utility 
industry in the region is becoming increasingly more competitive and 
that the Company is highly dependent upon purchased power agreements 
with escalating fixed payment obligations.  Duff & Phelps, however, 
concluded that the Company has low cost structures, access to a good 
transmission system and a strong marketing-oriented focus.

     The rating of the Company's first mortgage bonds by Moody's 
Investment Services remains at "Baa2."  In 1996, a rating of "baa3" was 
assigned to the Company's preferred stock by Moody's.  Moody's "outlook" 
for the Company remains "stable."

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


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

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES

Page
Financial Statements

Consolidated Statements of Income
    For the Years Ended December 31, 1996, 1995 and 1994                  38

Consolidated Statements of Cash Flows For the
    Years Ended December 31, 1996, 1995 and 1994                          39

Consolidated Balance Sheets as of
    December 31, 1996 and 1995                                           40-41

Consolidated Capitalization Data as of
    December 31, 1996 and 1995                                            42

Notes to Consolidated Financial Statements                               43-61

Quarterly Financial Information                                           54

Report of Independent Public Accountants                                  62

Schedules

For the Years Ended December 31, 1996, 1995 and 1994:

    II  Valuation and Qualifying Accounts and Reserves                    63

             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                                       62 & 74

<TABLE>
<CAPTION>

                            CONSOLIDATED STATEMENTS OF INCOME

        GREEN MOUNTAIN POWER CORPORATION   For the Years Ended December 31




                                                                      1996                1995                1994
                                                                -----------------    ---------------     ---------------
                                                                         (In thousands, except amounts per share)

<S>                                                                     <C>                <C>                 <C>
Operating Revenues..............................................        $179,009           $161,544            $148,197
                                                                -----------------    ---------------     ---------------
Operating Expenses
  Power Supply 
     Vermont Yankee Nuclear Power Corporation...................          30,596             30,222              30,300
     Company-owned generation...................................           3,330              3,786               3,113
     Purchases from others......................................          66,320             53,915              45,777
  Other operating...............................................          17,615             18,120              17,296
  Transmission.................................................           10,833              9,874              10,374
  Maintenance...................................................           4,463              4,210               4,465
  Depreciation and amortization.................................          16,280             14,116              10,683
  Taxes other than income.......................................           6,982              6,428               6,277
  Income taxes..................................................           6,463              5,578               5,395
                                                                -----------------    ---------------     ---------------
     Total operating expenses...................................         162,882            146,249             133,680
                                                                -----------------    ---------------     ---------------
       Operating Income.........................................          16,127             15,295              14,517
                                                                -----------------    ---------------     ---------------

Other Income
  Equity in earnings of affiliates and 
     non-utility operations.....................................           2,880              3,513               3,112
  Allowance for equity funds used during construction...........             175                 27                 263
  Other income and deductions, net..............................             175                 94                 306
                                                                -----------------    ---------------     ---------------
    Total other income..........................................           3,230              3,634               3,681
                                                                -----------------    ---------------     ---------------
      Income before interest charges............................          19,357             18,929              18,198
                                                                -----------------    ---------------     ---------------

Interest Charges
  Long-term debt................................................           6,872              6,546               6,868
  Other.........................................................             994              1,427                 867
  Allowance for borrowed funds used during 
     construction............................................               (468)              (547)               (539)
                                                                -----------------    ---------------     ---------------
    Total interest charges......................................           7,398              7,426               7,196
                                                                -----------------    ---------------     ---------------
Net Income......................................................          11,959             11,503              11,002

Dividends on preferred stock....................................           1,010                771                 794
                                                                -----------------    ---------------     ---------------
Net Income Applicable to Common Stock...........................         $10,949            $10,732             $10,208
                                                                =================    ===============     ===============

Common Stock Data
  Earnings per share............................................           $2.22              $2.26               $2.23

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

  Weighted average shares outstanding...........................           4,933              4,747               4,588


                       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


                                                                         1996          1995          1994
                                                                       ---------     ---------     ---------
                                                                                  (In thousands)

<S>                                                                     <C>           <C>           <C>
Operating Activities:
  Net Income........................................................... $11,959       $11,503       $11,002
  Adjustments to reconcile net income to net cash
    provided by operating activities:
      Depreciation and amortization....................................  16,280        14,116        10,683
      Dividends from associated companies less equity income...........     254           660           202
      Allowance for funds used during construction.....................    (643)         (574)         (803)
      Deferred purchased power costs...................................  (5,917)      (12,935)         (536)
      Amortization of purchased power costs............................   5,187         6,036         4,178
      Deferred income taxes............................................   1,937         3,715         1,585
      Amortization of investment tax credits...........................    (282)         (283)         (283)
      Environmental proceedings costs, net.............................  (1,720)       (1,351)        7,103
      Conservation expenditures........................................  (3,207)       (3,960)       (6,388)
      Changes in:
        Accounts receivable............................................     347        (2,841)         (426)
        Accrued utility revenues.......................................    (139)         (510)          126
        Fuel, materials and supplies...................................    (309)            2          (473)
        Prepayments and other current assets...........................    (354)        1,562        (1,982)
        Accounts payable...............................................     221         2,191        (2,327)
        Taxes accrued..................................................     415          (871)        1,044
        Interest accrued...............................................    (465)         (106)         (117)
        Other current liabilities......................................   1,065           (22)          (65)
      Other............................................................   1,738           (95)        2,383
                                                                       ---------     ---------     ---------
    Net cash provided by operating activities..........................  26,367        16,237        24,906
                                                                       ---------     ---------     ---------

Investing Activities:
    Construction expenditures.......................................... (17,541)      (15,314)      (13,536)
    Investment in non-utility property.................................  (2,203)       (6,121)       (1,220)
                                                                       ---------     ---------     ---------
      Net cash used in investing activities............................ (19,744)      (21,435)      (14,756)
                                                                       ---------     ---------     ---------
Financing Activities:
    Issuance of preferred stock........................................  12,000          --            --
    Reduction in preferred stock.......................................  (1,620)         (205)         (250)
    Issuance of common stock...........................................   4,642         4,404         3,671
    Short-term debt, net...............................................  (7,400)      (11,799)        1,198
    Issuance of long-term debt.........................................  14,000        25,917          --
    Reduction in long-term debt........................................ (16,201)       (4,833)       (1,800)
    Cash dividends..................................................... (11,455)      (10,818)      (10,504)
                                                                       ---------     ---------     ---------
      Net cash provided by (used in) financing activities..............  (6,034)        2,666        (7,685)
                                                                       ---------     ---------     ---------

    Net increase (decrease) in cash and cash equivalents...............     589        (2,532)        2,465
    Cash and cash equivalents at beginning of year.....................     160         2,692           227
                                                                       ---------     ---------     ---------
Cash and Cash Equivalents at End of Year...............................    $749          $160        $2,692
                                                                       =========     =========     =========

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

</TABLE>

<TABLE>
<CAPTION>

                          CONSOLIDATED BALANCE SHEETS

                   GREEN MOUNTAIN POWER CORPORATION    December 31


                                                         1996               1995
                                                       ---------          ---------
                                                              (In thousands)
ASSETS

<S>                                                    <C>                <C>
Utility Plant 
    Utility plant, at original cost....................$248,135           $239,291
    Less accumulated depreciation......................  81,286             75,797
                                                       ---------          ---------
      Net utility plant................................ 166,849            163,494
    Property under capital lease.......................   9,006              9,778
    Construction work in progress......................  13,998              8,727
                                                       ---------          ---------
      Total utility plant, net......................... 189,853            181,999
                                                       ---------          ---------
Other Investments
    Associated companies, at equity ...................  15,769             16,024
    Other investments .................................   4,865              4,224
                                                       ---------          ---------
      Total other investments..........................  20,634             20,248
                                                       ---------          ---------
Current Assets
    Cash...............................................     238                 84
    Accounts receivable, customers and others,
      less allowance for doubtful accounts.............  17,733             18,081
    Accrued utility revenues...........................   6,662              6,523
    Fuel, materials and supplies, at average cost......   3,621              3,312
    Prepayments........................................   2,206              1,890
    Other..............................................     441                326
                                                       ---------          ---------
      Total current assets.............................  30,901             30,216
                                                       ---------          ---------
Deferred Charges
    Demand side management programs....................  16,409             18,367
    Environmental proceedings costs....................   7,991              7,893
    Purchased power costs..............................   9,163              8,433
    Other..............................................   9,661              8,258
                                                       ---------          ---------
      Total deferred charges...........................  43,224             42,951
                                                       ---------          ---------
Non-Utility
    Cash and cash equivalents..........................     511                 76
    Other current assets...............................   3,979              4,055
    Property and equipment.............................  11,226             11,478
    Intangible assets..................................   2,555              2,580
    Equity investment in energy-related businesses.....  12,494             10,999
    Other assets.......................................   9,162              8,680
                                                       ---------          ---------
      Total non-utility assets.........................  39,927             37,868
                                                       ---------          ---------
Total Assets...........................................$324,539           $313,282
                                                       =========          =========

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



                   GREEN MOUNTAIN POWER CORPORATION    December 31

                                                         1996               1995
                                                       ---------          ---------
                                                              (In thousands)

CAPITALIZATION AND LIABILITIES

Capitalization (See Capitalization Data)
    Common Stock Equity 
      Common stock..................................... $16,790            $16,168
      Additional paid-in capital.......................  68,226             64,206
      Retained Earnings................................  26,916             26,412
      Treasury stock, at cost..........................    (378)              (378)
                                                       ---------          ---------
        Total common stock equity...................... 111,554            106,408
    Redeemable cumulative preferred stock..............  19,310              8,930
    Long-term debt, less current maturities ...........  94,900             91,134
                                                       ---------          ---------
        Total capitalization........................... 225,764            206,472
                                                       ---------          ---------

Capital Lease Obligation ..............................   9,006              9,778
                                                       ---------          ---------

Current Liabilities
    Current maturuties of long-term debt...............   3,034              7,833
    Short-term debt....................................   1,016              8,416
    Accounts payable, trade, and accrued liabilities...   6,140              5,529
    Accounts payable to associated companies...........   6,621              7,011
    Dividends declared.................................     381                194
    Customer deposits..................................     689                816
    Taxes Accrued......................................     986                571
    Interest accrued...................................   1,382              1,847
    Other..............................................     788                412
                                                       ---------          ---------
        Total current liabilities......................  21,037             32,629
                                                       ---------          ---------
Deferred Credits
    Accumulated deferred income taxes..................  26,726             25,292
    Unamortized investment tax credits.................   4,825              5,107
    Other..............................................  23,417             21,642
                                                       ---------          ---------
        Total deferred credits.........................  54,968             52,041
                                                       ---------          ---------

Non-Utility
    Current liabilities................................   1,752              1,124
    Other liabilities..................................  12,012             11,238
                                                       ---------          ---------
        Total non-utility liabilities..................  13,764             12,362
                                                       ---------          ---------
Total Capitalization and Liabilities...................$324,539           $313,282
                                                       =========          =========

  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        1996         1995         1996       1995
                                                                      -----------    ----------   ----------    ---------  ---------
                                                                                                                     (In thousands)
<S>                                                                   <C>            <C>          <C>            <C>        <C>   
Common Stock,$3.33 1/3 par value (Note C)..........................   10,000,000     5,037,143    4,850,496      $16,790    $16,168
                                                                                                                =========  =========
     -----------------------------------------------------------------------------------------------------------------

                                                                                            Outstanding
                                                           Authorized   Issued          1996         1995         1996       1995
                                                           ---------- -----------    ----------   ----------    ---------  ---------
                                                                                                                    (In thousands)
<S>                                                            <C>        <C>            <C>          <C>           <C>        <C>
Redeemable Cumulative Preferred Stock,
 $100 par value (Note D)
   4.75%,Class B, redeemable at
     $101 per share........................................    15,000     15,000         2,850        3,000         $285       $300
   7%,Class C, redeemable at
     $101 per share........................................    15,000     15,000         4,650        5,100          465        510
   9.375%,Class D,Series 1,
     redeemable at $101 per share..........................    40,000     40,000         9,600       11,200          960      1,120
   8.625%,Class D,Series 3,
     redeemable at $103.835 per share......................    70,000     70,000        56,000       70,000        5,600      7,000
   7.32%,Class E,Series 1,.................................   200,000    120,000       120,000          --        12,000        --
                                                                                                                ---------  ---------
Total Preferred Stock......................................                                                      $19,310     $8,930
                                                                                                                =========  =========


LONG-TERM DEBT (Note E)                                                                                           1996       1995
                                                                                                                ---------  ---------
                                                                                                                   (In thousands)
<S>                                                                                                             <C>          <C>
First Mortgage Bonds
  5 1/8% Series due 1996........................................................................................$   --       $3,000
  6.84% Series due 1997 - Cash sinking fund,$1,333,000
      annually..................................................................................................   1,334      2,667
  7% Series due 1998............................................................................................   3,000      3,000
  10.7% Series due 2000.........................................................................................    --        9,000
  5.71% Series due 2000.........................................................................................   5,000      5,000
  6.21% Series due 2001.........................................................................................   8,000      8,000
  6.29% Series due 2002.........................................................................................   8,000      8,000
  6.41% Series due 2003.........................................................................................   8,000      8,000
  10.0% Series due 2004 - Cash sinking fund,$1,700,000
      annually..................................................................................................  13,600     15,300
  7.05% Series due 2006.........................................................................................   4,000       --
  7.18% Series due 2006.........................................................................................  10,000       --
  6.7% Series due 2018..........................................................................................  15,000     15,000
  9.64% Series due 2020.........................................................................................   9,000      9,000
  8.65% Series due 2022 - Cash sinking fund,commences 2012......................................................  13,000     13,000
                                                                                                                ---------  ---------
Total Long-term Debt Outstanding................................................................................  97,934     98,967
  Less Current Maturities (due within one year).................................................................   3,034      7,833
                                                                                                                ---------  ---------
Total Long-term Debt, Net....................................................................................... $94,900    $91,134
                                                                                                                =========  =========

                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-
quarter of its population.  The most significant portion of the Company's net 
income is derived from its regulated electric utility operation, which 
purchases and generates electric power and distributes it to 82,500 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 energy 
generation and efficiency projects across the United States.  In 1996, the 
Company's wholly-owned, unregulated subsidiary, Green Mountain Resources Inc., 
was created to participate, along with the wholly-owned subsidiaries of three 
energy companies -- Hydro-Quebec, Consolidated Natural Gas Company, and 
Noverco, Inc. - in pilot programs in New Hampshire and Massachusetts to test 
the viability of retail electric competition through a limited liability 
company (Green Mountain Energy Partners L.L.C.).  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,
                                           -------------------------------- 
                                                   1996         1995
                                                   ----         ----
                                                     (In thousands)
   Revenues  . . . . . . . . . . . . . . .       $11,997      $11,905
   Expenses. . . . . . . . . . . . . . . .        11,207       10,416
                                                 -------      -------
   Net Income  . . . . . . . . . . . . . .       $   790      $ 1,489
                                                 =======      =======

     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.  Criteria that give rise to the discontinuance of SFAS 71 include 
(1) increasing competition that restricts the Company's ability to establish 
prices to recover specific costs, and (2) a change in the manner in which 
rates are set by regulators from cost-based regulation to another form of 
regulation.  In the event that the Company no longer meets the criteria under 
SFAS 71, the Company would be required to writeoff related regulatory assets 
and liabilities.

     SFAS 121, Accounting for the Impairment of Long Lived Assets, which 
became 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 regulatory 
assets which are no longer probable of recovery.  As of December 31, 1996, 
based upon the regulatory environment within which the Company currently 
operates, SFAS 121 did not have a material impact on the Company's financial 
position or results of operations.  Competitive influences or regulatory 
developments may impact this status in the future.  See Management's 
Discussion and Analysis of Financial Condition and Results of Operations for a 
discussion of electric utility restructuring which may impact the Company's 
application of SFAS 71 and 121.


     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:
                                                1996        1995        1994 
                                                ----        ----        ----
                                                       (In thousands)
   Interest . . . . . . . . . . . . . . . .    $8,104      $7,940     $7,714 
   Income Taxes (Net of refunds)  . . . . .    $3,727      $2,949     $3,088 


     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.


     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 and adjusted for 
salvage value and cost of removal of the Company's retirements.

     The annual depreciation provision was approximately 3.6 percent of total 
depreciable property at the beginning of each year 1996, 1995 and 1994.


     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.  The Company 
defers and amortizes certain purchased power costs related to its obligations 
under the Hydro-Quebec contracts.

     At December 31, 1996, other deferred charges totaled $9.7 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, transmission interconnection 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 13.2, 12.9 and 13.7 percent of 
operating revenues in 1996, 1995 and 1994, 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:
                                                       1996     1995     1994
                                                       ----     ----     ----
                                                        (Dollars in thousands)
Service cost-benefits earned during the period  .    $  689   $  687   $  768
Interest cost on projected benefit obligations  .     1,912    1,671    1,633
Actual return on plan assets  . . . . . . . . . .    (4,383)  (6,447)  (1,296)
Net amortization and deferral . . . . . . . . . .     1,756    4,232     (906)
Effect of voluntary retirement program  . . . . .       416      765      ---
Adjustment due to actions of regulator  . . . . .      (366)    (878)    (174)
                                                      -------  -------  -------
Net periodic pension cost funded and recognized .     $  24     $ 30    $  25 
                                                      =======  =======  =======

Assumptions used to determine pension costs and the related benefit obligation 
in 1996, 1995 and 1994 were:
   Discount rate . . . . . . . . . . . . . . . .       8.0%    8.0%     7.5%*
   Rate of increase in future compensation levels      5.0%    5.0%     5.0% 
   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:
                                                  1996     1995       1994 
                                                  ----     ----       ----
                                                         (In thousands)
Actuarial present value of benefit obligations:
   Accumulated benefit obligations,
     including vested benefits of $21,146,
     $19,107 and $18,184, respectively . . . . ($21,376) ($19,431)  ($18,479)
                                                =========  ========  ========
   Projected benefit obligations for
     service rendered to date  . . . . . . . . ($25,615)  ($21,974) ($21,363)
Plan assets at fair value  . . . . . . . . . .   31,286     28,685    24,171 
                                                ---------  --------- ---------
Assets in excess of projected
   benefit obligations . . . . . . . . . . . .    5,671      6,711     2,808 
Unrecognized net gain from past
   experience different from that assumed  . .   (4,734)    (5,188)     (285)
Prior service cost not yet recognized in net
   periodic pension cost . . . . . . . . . . .    1,474      1,506     1,642 
Unrecognized net asset at transition
   being recognized over 16.47 years . . . . .   (1,477)    (1,706)   (1,934)
Adjustment due to actions of regulator . . . .     (934)    (1,323)   (2,231)
                                                 --------   --------   -------
Prepaid pension cost included in other assets    $   ---   $   ---   $   ---
                                                 ========   ========  ========

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

     The Company also has a supplemental pension plan for certain employees.  
Pension costs for the years ended December 31, 1996, 1995 and 1994 were 
$494,000, $397,000 and $381,000, respectively, under this plan.  This plan is 
funded in part through insurance contracts.


     11. 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 1996 reflect the following 
components and assumptions:
                                                  1996     1995        1994   
                                                  ----     ----        ----
                                                       (In thousands)
Accumulated postretirement benefit obligation:
   Current retirees . . . . . . . . . . . .    ($ 4,563) ($ 4,594)  ($ 3,497)
   Participants currently eligible  . . . .        (772)    (681)    (1,863)
   All others . . . . . . . . . . . . . . .      (3,837)   (3,384)    (3,785)
Total accumulated postretirement benefit
   obligation . . . . . . . . . . . . . . .      (9,172)   (8,659)    (9,145)
Plan assets at fair value . . . . . . . . .       6,327     5,465      3,433 
Accumulated postretirement benefit
   obligation in excess of plan assets  . .      (2,845)   (3,194)    (5,712)
Unrecognized prior service cost . . . . . .        (867)     (929)       --- 
Unrecognized transition obligation  . . . .       5,630     5,982      6,485 
Unrecognized net gain . . . . . . . . . . .      (1,879)   (1,687)    (1,777)
                                                --------   -------   --------
Prepaid (accrued) postretirement benefit
   cost . . . . . . . . . . . . . . . . . .       $  39     $ 172    ($1,004)
                                                =======    =======   ========


     Net periodic postretirement benefit cost for 1996 includes the following 
components:

                                                   1996     1995      1994
                                                   ----     ----      ---- 
                                                      (In thousands)
Service cost . . . . . . . . . . . . . . . .    $  247    $  224    $   407 
Interest cost  . . . . . . . . . . . . . . .       698       697        864 
Actual return on plan assets . . . . . . . .      (870)     (586)      (127)
Deferred asset loss/(gain) . . . . . . . . .       407       264       (107)
Recognition of transition obligation,
   net of amortization . . . . . . . . . . .       245       234        361 
                                                -------    -----    -------
Total net periodic postretirement
   benefit cost  . . . . . . . . . . . . .       $ 727   $  833     $ 1,398 
                                                =======   ======    =======

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

                                                  1996      1995      1994
                                                  ----      ----      ----
Discount rate to determine postretirement
  benefit costs .  . . . . . . . . . . . . .      8.0%      8.5%      7.5%
Discount rate to determine postretirement
  benefit obligation . . . . . . . . . . . .      8.0%      8.5%      8.5%
Expected long-term rate of return on assets       8.5%      7.5%      7.5%

     For measurement purposes, a 6.0 percent annual rate of increase in the 
per capita cost of covered benefits was assumed for 1996; 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, 1996 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, 1996 by $211,000.


     12. Fair Value of Financial Instruments.  If the first mortgage bonds and 
preferred stock outstanding at December 31, 1996 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, 1996 balance sheet by 3 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.


     13. Deferred Credits.  At December 31, 1996, the Company had other 
deferred credits and long-term liabilities of $23.4 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:
                                  Percent Ownership       Investment in Equity
                                at December 31, 1996          December 31,    
                                --------------------      --------------------
                                                            1996         1995
                                                            ----         ----
                                                             (In thousands)
VELCO - Common . . . . . . . . .          29.5%          $  1,834      $ 1,811
      - Preferred  . . . . . . .          30.0%             1,118        1,278
                                                            -----        -----
Total VELCO  . . . . . . . . . .                            2,952        3,089
Vermont Yankee - Common  . . . .          17.9%             9,768        9,631
New England Hydro-Transmission -
     Common  . . . . . . . . . .          3.18%             1,205        1,296
New England Hydro-Transmission
     Electric - Common . . . . .          3.18%             1,891        2,008
                                                          -------      -------
                                                          $15,816      $16,024
                                                          =======      ======= 

     Undistributed earnings in associated companies totaled $714,000 at 
December 31, 1996.


     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 $7.7 million, $7.6 million 
and $7.9 million for the years 1996, 1995 and 1994, 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,       
                                                  -------------------------
                                                  1996       1995      1994
                                                  ----       ----      ---- 
                                                        (In thousands)
Company's equity in net income . . . . . . .    $  383     $  377   $   386
                                                =======   =======   =======
Total assets . . . . . . . . . . . . . . . .   $74,065    $71,668   $69,724
Less:
   Liabilities and long-term debt  . . . . .    64,159     61,238    58,850
                                                -------   -------   -------
Net assets . . . . . . . . . . . . . . . . .    $9,906    $10,430   $10,874
                                                =======   =======   =======
Company's equity in net assets . . . . . . .    $2,952    $ 3,089   $ 3,232
                                                =======   =======   =======


     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 531 megawatts.  
Vermont Yankee's current estimate of decommissioning costs is approximately 
$366 million, of which $160 million has been funded.  At December 31, 1996, 
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 1996, the Company incurred $28.5 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, 1996 was 
$13.8 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 expected 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 
$3.0 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) to cover the costs of property damage, decontamination or premature 
decommissioning resulting from a nuclear incident.  All companies insured with 
NEIL are subject to retroactive assessments if losses exceed the accumulated 
funds available.  The maximum potential assessment against Vermont Yankee with 
respect to NEIL losses arising during the current policy year is 
$13.3 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,
                                                  -------------------------
                                                  1996      1995       1994  
                                                  ----      ----       ----
                                                        (In thousands)
Earnings:
   Operating revenues . . . . . . . . . . .     $181,715   $180,437   $162,757
   Net income applicable to common stock   .       6,985      6,790      6,588
   Company's equity in net income . . . .  .       1,232      1,171      1,143
Total assets  . . . . . . . . . . . . . . .     $565,000   $531,293   $512,142
Less:
   Liabilities and long-term debt . . . . .      510,202    477,350    457,669
                                                --------  --------    --------  
Net assets  . . . . . . . . . . . . . . . .     $ 54,798  $ 53,943    $ 54,473
                                                ========  ========    ========
Company's equity in net assets  . . . . . .     $  9,768  $  9,631    $  9,766
                                                ========  ========    ========


C. COMMON STOCK EQUITY


     The Company maintains a Dividend Reinvestment and Stock Purchase Plan 
(DRIP) under which 509,139 shares were reserved and unissued at December 31, 
1996.  The Company also funds an Employee Savings and Investment Plan (ESIP).  
At December 31, 1996, there were 149,900 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 1996, 7,035 shares of common stock were awarded under this 
program.  At December 31, 1996, there were 31,039 shares reserved and unissued 
under the Compensation Program.

     Changes in common stock equity for the years ended December 31, 1994, 
1995 and 1996 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, 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

Common Stock Issuance:
  DRIP...................................    149,968         500       3,188                                           3,688
  ESIP...................................     29,644          99         668                                             767
  Compensation Program:
    Restricted Shares....................      2,392           8          59                                              67
    Stock Grant..........................      4,643          15         105                                             120
Net Income...............................                                         11,959                              11,959
Cash Dividends on Capital Stock:
  Common Stock      -$2.12 per share.....                                        (10,445)                            (10,445)
  Preferred Stock   -$4.75 per share.....                                            (14)                                (14)
                    -$7.00 per share.....                                            (35)                                (35)
                    -$9.375 per share....                                           (101)                               (101)
                    -$8.625 per share....                                           (543)                               (543)
                    -$7.32 per share.....                                           (317)                               (317)
                                         ------------------------------------------------------------------------------------
BALANCE, December 31, 1996...............  5,037,143     $16,790     $68,226     $26,916      15,856       ($378)   $111,554
                                         ====================================================================================

</TABLE>

     Dividend Restrictions.  Certain restrictions on the payment of cash 
dividends on common stock are contained in the Company's indenture relating to 
long-term debt and in the Restated Articles of Association.  Under the most 
restrictive of such provisions, $20.5 million of retained earnings were free 
of restrictions at December 31, 1996.

     The properties of the Company include several hydroelectric projects 
licensed under the Federal Power Act, with license expiration dates ranging 
from 1999 to 2025.  At December 31, 1996, $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 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 are $1,650,000 for the years 
1997-1999, $1,640,000 for 2000 and $235,000 for 2001.

     Certain classes of preferred stock are redeemable at the option of the 
Company or, in the case of voluntary liquidation, at various prices on various 
dates.  The prices include the par value of the issue plus any accrued 
dividends and a redemption premium.  The redemption premium for Class B, C and 
D, Series 1, is $1.00 per share.  The redemption premium for the Class D, 
Series 3, is $2.877 per share until 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.

     In October 1996, the Company issued $12.0 million of its 7.32 percent, 
Class E, Series 1, preferred stock.

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)
1997 . . . . . . . . . . . . . .   $1,700     $1,334      $3,034
1998 . . . . . . . . . . . . . .    1,700      3,000       4,700
1999 . . . . . . . . . . . . . .    1,700      ---         1,700
2000 . . . . . . . . . . . . . .    1,700      5,000       6,700
2001 . . . . . . . . . . . . . .    1,700      8,000       9,700	


     Non-Utility.  At December 31, 1996, Green Mountain Propane Gas Company, 
the Company's propane subsidiary, had long-term debt of $2,900,000, which was 
secured by substantially all of the subsidiary's assets, and Mountain Energy, 
Inc., the Company's subsidiary that invests in energy generation and 
efficiency projects, had unsecured long-term debt of $1,749,103.  The annual 
sinking fund requirements and maturities for the next four years are:
                                   Sinking
                                    Funds     Maturities    Total
                                   -------    ----------    -----
                                           (In thousands)
1997 . . . . . . . . . . . . .     $1,167      $  ---      $1,167
1998 . . . . . . . . . . . . .      1,167         ---       1,167
1999 . . . . . . . . . . . . .        167         900       1,067
2000 . . . . . . . . . . . . .         83       1,166       1,249


F. SHORT-TERM DEBT


     Utility.  At December 31, 1996, the Company had lines of credit with six 
banks totaling $40.0 million, with borrowings outstanding of $1.0 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, 1996 and December 31, 1995 was 5.7 percent and 6.3 percent, respectively.


     Non-Utility.  At December 31, 1996, Green Mountain Propane Gas Company, 
the Company's propane subsidiary, had a line of credit with a bank for 
$1.5 million, with $275,000 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, 1996 and 1995, the net regulatory assets were $1,194,000 and 
$690,000, respectively.

     The temporary differences which gave rise to the net deferred tax 
liability at December 31, 1996 and December 31, 1995, were as follows:

                                       	At December 31,  At December 31,
                                               1996                1995      
                                         ---------------    ---------------
                                                  (In thousands)
Deferred Tax Assets
 Contributions in aid of construction         $ 7,094           $ 6,361  
 Deferred compensation and
   post-retirement benefits . . . . . .         2,944             2,931  
 Alternative minimum tax credit  . . .           (552)             (661) 
 Excess deferred taxes . . . . . . . .          1,891             1,990  
 Unamortized investment tax credits  .          2,025             2,151  
 Other . . . . . . . . . . . . . . . .          2,719             2,982  
                                              -------           -------
                                              $16,121           $15,754
                                              -------           -------  
Deferred Tax Liabilities
 Property-related and other  . . . . .        $30,553           $28,009  
 Demand side management costs  . . . .          5,856             6,685  
 Deferred purchased power costs  . . .          3,716             2,901  
 Reversal of previously flowed-through
   tax depreciation  . . . . . . . . .          2,133             2,816  
 AFUDC equity basis adjustment . . . .            589               635  
                                             --------          ---------
                                               42,847            41,046 
                                             --------          --------- 
Net accumulated deferred income tax
   liability . . . . . . . . . . . . .       ($26,726)         ($25,292) 
                                             =========         =========

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 Ended December 31,
                                                 --------------------------
                                                 1996       1995       1994
                                                 ----       ----       ----
                                                       (In thousands)
Net change in deferred income tax
  liability per above table . . . . . . . . .   $1,434     $3,210    $1,080
Change in income tax related regulatory
  assets and liabilities. . . . . . . . . . .      504        503       505
Change in alternative minimum tax credit  . .      109        168    (1,578)
IRS audit adjustment, 1989 - 90 . . . . . . .       --        255        --
                                                 ------     ------    ------
Deferred income tax expense for the period  .   $2,047     $4,136     $   7
                                                 ======     ======    ======

The components of the provision for income taxes are as follows:
                                            	    Year Ended December 31,
                                                   ------------------------
                                                  1996       1995      1994
                                                  ----       ----      ----
                                                        (In thousands)
Current state income taxes . . . . . . .         $  990     $  365    $1,205
Deferred state income taxes  . . . . . .            459        897        70
Current federal income taxes . . . . . .          3,708      1,359     4,466
Deferred federal income taxes  . . . . .          1,588      3,239       (63)
Investment tax credits -- net  . . . . .           (282)      (282)     (283)
                                                 -------    -------   -------
Income taxes charged to operations . . .         $6,463     $5,578    $5,395
                                                 =======    =======   =======

     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,
                                                 ---------------------------
                                                 1996       1995        1994
                                                 ----       ----        ----
                                                (Dollars in thousands)
Income before income tax . . . . . . .         $18,422    $17,081     $16,398
Federal statutory rate . . . . . . . .              34%        34%        34%
Computed "expected" federal
  income taxes . . . . . . . . . . . .         $ 6,263    $ 5,808     $ 5,575
Increase (decrease) in taxes
  resulting from:
  Tax versus book depreciation . . . .             327        327         327
  Dividends received and paid credit .            (524)      (616)       (499)
  AFUDC - equity funds . . . . . . . .             (59)        (9)        (89)
  Amortization of ITC  . . . . . . . .         	  (282)      (282)       (283)
  State tax benefit  . . . . . . . . .            (493)      (429)       (433)
  Excess deferred taxes  . . . . . . .             (60)       (60)        (60)
  Taxes attributable to subsidiaries .            (140)      (401)       (268)
  Other  . . . . . . . . . . . . . . .             (18)       (22)       (150)
                                                -------    -------     -------
Total federal income taxes . . . . . .          $5,014      $4,316      $4,120
                                                =======    =======     =======
Effective federal income tax rate  . .            27.2%      25.3%      25.1%

     Non-Utility.  The Company's non-utility subsidiaries had accumulated 
deferred income taxes of $4.7 million on their balance sheets at December 31, 
1996, largely attributable to property-related transactions.

     The components of the provision for income taxes for the non-utility 
operations are:
                                            Year Ended December 31,
                                            -----------------------
                                            1996     1995    1994
                                             ----    ----    ----
                                                  (In thousands)
State income taxes . . . . . . . . . .      $154     $165    $123
Federal income taxes . . . . . . . . .       207      613     444
Investment tax credits . . . . . . . .       (45)     (45)    (45)
                                            -----    -----   ----- 
Income taxes charged to operations . .      $316     $733    $522
                                            =====    =====   =====
                                           

     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 22.4 percent, 29.7 percent, and 29.0 percent for the years ended December 
31, 1996, 1995 and 1994, 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.

                                            1996 Quarter Ended
                                            ------------------
                                 March     June     Sept.    Dec.     Total
                                 -----     ----     -----    ----     -----
                                   (Amounts in thousands, except per share)
Operating Revenues . . . . . . $48,415  $40,467   $44,423  $45,704  $179,009
Operating Income . . . . . . .   5,073    1,859     4,419    4,776    16,127
Net Income . . . . . . . . . .   4,065    1,024     3,474    3,396    11,959
Net Income Applicable to
  Common Stock . . . . . . . .   3,875      834     3,315    2,925    10,949
Earnings per Average Share of
  Common Stock . . . . . . . .   $0.80    $0.17     $0.67    $0.58     $2.22
Weighted Average Number of
  Common Shares Outstanding  .   4,860    4,911     4,959    5,003     4,933


                                            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


I. 	COMMITMENTS AND CONTINGENCIES


     1. Industry Restructuring.  The electric utility business is being 
subjected to rapidly increasing competitive pressures stemming from a 
combination of trends, including the presence of surplus generating capacity, 
a disparity in electric rates among and within various regions of the country, 
improvements in generation efficiency, increasing demand for customer choice, 
and new regulations and legislation intended to foster competition.

     On December 31, 1996, the VPSB issued an Order which proposed the 
commencement of competitive retail sales of electricity in early 1998.  The 
Vermont General Assembly is debating proposals that would allow retail 
competition in Vermont in 1998.

     The Company, Central Vermont Public Service Corporation, representatives 
of the Governor of Vermont and the Department are in the process of 
negotiating a Memorandum of Understanding that would outline agreed-upon 
positions among the parties relative to the numerous issues involving the 
industry restructuring.

     For a complete discussion, see Management's Discussion and Analysis of 
Financial Condition and Results of Operations - "Future Outlook".


     2. Environmental Matters.  Public concern for the environment has 
resulted in increased government regulation of the licensing and operation of 
electric generation, transmission and distribution facilities.   The electric 
industry typically uses or generates a range of potentially hazardous products 
in its operations.  The Company must meet various land, water, air and 
aesthetic requirements as administered by local, state and federal regulatory 
agencies.    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 developments 
concerning the Pine Street Marsh site described below, 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.

     The Federal Comprehensive Environmental Response, Compensation, and 
Liability Act (CERCLA), commonly known as the "Superfund" law, generally 
imposes strict, joint and several liability, regardless of fault, for 
remediation of property contaminated with hazardous substances.  The Company 
has been notified by the Environmental Protection Agency (EPA) that it is one 
of several potentially responsible parties (PRPs) for cleanup of the Pine 
Street Marsh site in Burlington, Vermont, where coal tar and other industrial 
materials were deposited.  From the late 19th century until 1967, gas was 
manufactured at the Pine Street Marsh site by a number of enterprises, 
including the Company.  In 1990, the Company was one of the 14 parties that 
agreed to pay a total of $945,000 of the EPA's past response costs under a 
Consent Decree.  The Company remains a PRP for ongoing and future response 
costs.  In November 1992, the EPA proposed a cleanup plan estimated by the EPA 
to cost $47 million.  In June 1993, the EPA withdrew this cleanup plan in 
response to public concern about the plan and its cost.  The cost of any 
future cleanup plan, the magnitude of unresolved EPA cost recovery claims, and 
the Company's share of such costs are uncertain at this time.

     Since 1994, the EPA has established a coordinating council, with 
representatives of PRPs, environmental and community groups, the City of 
Burlington and the State of Vermont presided over by a neutral facilitator.  
The council has determined, by consensus, what additional studies were 
appropriate for the site, and is addressing the question of additional 
response activities.  The EPA, the State of Vermont and other parties have 
entered into two consent orders for completion of appropriate studies.  Work 
is continuing under the second of those orders.  On December 1, 1994, the 
Company, and two other PRPs, New England Electric System (NEES) and  Vermont 
Gas Systems (VGS), entered into a confidential agreement with the State of 
Vermont, the City of Burlington and nearly all other landowner PRPs under 
which, subject to certain qualifications, 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.  In March 1996, the Company and NEES entered 
into a confidential agreement compromising past and future contribution and 
cost recovery claims of both parties relating to response costs.

     In December 1991, the Company brought suit against eight previous 
insurers seeking recovery of unrecovered past costs and indemnity against 
future liabilities associated with environmental problems at the site.  
Discovery in the case, which was previously subject to a stay, is proceeding 
and is largely complete.  A trial in this litigation is scheduled for late 
1997.  The Company has reached confidential final settlements with two of the 
defendants in this litigation and has obtained summary judgment declaring one 
insurer's duty to defend.

     The Company has deferred amounts received, under confidential settlement, 
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 to investigate and remediate the site, 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, 1994 and 1995, 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 incurred between January 1, 1991 and June 30, 1995 
(in the total of approximately $8.7 million) for technical consultants and 
legal assistance in connection with the 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 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 in 
those proceedings reflected the Pine Street Marsh related expenditures 
referred to above.

     Management expects to seek and (assuming recovery 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.

     An authoritative accounting standard, Statement of Position (SOP) 96-1, 
has been issued by the accounting profession addressing environmental 
remediation obligations.  This SOP is effective for years beginning in 1997, 
and addresses, among other things, regulatory benchmarks that are likely 
triggers of the accrual of estimated losses, the costs included in the 
measurement, including incremental costs of remediation efforts such as post-
remediation monitoring and long-term operation and maintenance costs and costs 
of compensation and related benefits of employees devoting time to the 
remediation.  After reviewing the Company's current accounting policies and 
ratemaking treatment, management does not believe that this SOP will have a 
material adverse effect on the Company's financial position or results of 
operations upon adoption.


     3. 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 1997 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.


     4. Jointly-Owned Facilities.  The Company had joint-ownership interests 
in electric generating and transmission facilities at December 31, 1996, as 
follows:

                            Ownership   Share of      Utility   Accumulated
                             Interest   Capacity       Plant    Depreciation
                            ---------   --------      -------   ------------
                               (In %)     (In MW)        (In thousands)
Highgate  . . . . . . . . . .   33.8       67.6       $ 9,734      $3,056
McNeil  . . . . . . . . . . .   11.0        5.9       $ 8,633      $3,323
Stony Brook (No. 1) . . . . .    8.8       31.0       $10,039      $5,919
Wyman (No. 4) . . . . . . . .    1.1        6.8       $ 2,384      $1,309
Metallic Neutral Return (1) .   59.4        ---       $ 1,563      $  368
(1)	Neutral conductor for NEPOOL/Hydro-Quebec Interconnection

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


     5. Rate Matters.  1994 Retail Rate Case - 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 that the Company secured 
to replace power supply that will be lost in the near future, and the cost of 
energy efficiency programs that the Company 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 for utility operations 
of 11.25 percent.  In the event that the target return on equity is exceeded, 
the Company would accelerate the amortization of certain demand side 
management expenditures in the next year for which rate recovery otherwise 
would have been sought.  The agreement was approved by the VPSB on June 9, 
1995.

     1995 Retail Rate Case - In September 1995, the Company filed a 12.7 
percent retail rate increase 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.  Early in 
1996, the Company settled this rate case with the Department and other 
parties, enabling the Company to conduct its business and achieve satisfactory 
financial results without the drain on human resources and the additional 
costs that rate litigation imposes.

     The settlement became possible when the Company negotiated a new 
arrangement with Hydro-Quebec that will reduce the Company's net power-supply 
costs below the amounts anticipated in the rate increase request.  The 
settlement provided:  projected additional annual revenues of $7.6 million; an 
overall increase in retail rates of 5.25 percent effective June 1, 1996; 
target return on equity for utility operations of 11.25 percent (with a 
continuation of the amortization of any amount in excess of the target rate of 
return in the following year, as described above); and recovery of $1.3 
million of costs associated with the Pine Street site, amortized over five 
years.  The VPSB approved the settlement in an order dated May 23, 1996.  In 
1996, the rate of return on utility operations was 11.8% and in 1995 was 
11.3%.  An accounting order received from the VPSB on December 31, 1996 
continues the limitation on return on equity from utility operations through 
December 31, 1997.


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


J. 	OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT


     Agreements executed in 1985 among the Company, VELCO and other NEPOOL 
members and Hydro-Quebec provided for the construction of the second phase 
(Phase II) of the interconnection between the New England electric systems and 
that of Hydro-Quebec.  Phase II expands the Phase I facilities from 690 
megawatts to 2,000 megawatts and provides for transmission of Hydro-Quebec 
power from the Phase I terminal in northern New Hampshire to Sandy Pond, 
Massachusetts.  Construction of Phase II commenced in 1988 and was completed 
in late 1990.  The Company is entitled to 3.2 percent of the Phase II power-
supply benefits.  Total construction costs for Phase II were approximately 
$487 million.  The New England participants, including the Company, have 
contracted to pay monthly their proportionate share of the total cost of 
constructing, owning and operating the Phase II facilities, including capital 
costs.  As a supporting participant, the Company must make support payments 
under thirty-year agreements.  These support agreements meet the capital lease 
accounting requirements under SFAS 13.  At December 31, 1996, the present 
value of the Company's obligation is $9.0 million.

Projected future minimum payments under the Phase II support agreements are as 
follows:
               Year ending December 31,
               1997 . . . . . . . . . . .  $  474,013
               1998 . . . . . . . . . . .     474,013
               1999 . . . . . . . . . . .     474,013
               2000 . . . . . . . . . . .     474,013
               2001 . . . . . . . . . . .     474,013
               Total for 2002-2020  . . .   6,636,181
                                           ----------
                                           $9,006,246
                                           ==========

     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 1996 follows:

                                                    Stony      Vermont
                                     Merrimack      Brook      Yankee
                                     ---------      -----      -------
                                           (Dollars in thousands)
Plant capacity . . . . . . . . . . .  320.0 MW    352.0 MW    531.0 MW
Company's share of output  . . . . .      9.5%        4.0%       17.3%
Contract period  . . . . . . . . . . 1968-1998         (1)         (2)
Company's annual share of:
  Interest . . . . . . . . . . . . .    $  650      $  232     $ 1,829
  Other debt service . . . . . . . .       365         307         ---
  Other capacity . . . . . . . . . .     1,953         319      26,697
                                        ------      ------     -------
Total annual capacity  . . . . . . .    $2,968      $  858     $28,526
                                        ======      ======     =======

Company's share of long-term debt  .    $  907      $4,538     $13,845
                                        ======      ======     =======
(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, the 
details of which are described in the table below, the Company purchases 
capacity and associated energy produced by the Hydro-Quebec system.  Such 
contracts obligate the Company to pay certain fixed capacity costs whether or 
not energy purchases above a  minimum level set forth in the contracts are 
made.  Such minimum energy purchases must be made whether or not other, less 
expensive energy sources might be available.  These contracts are intended to 
complement the other components in the Company's power supply to achieve the 
most economic power-supply mix reasonably available.

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

     During 1994, the Company negotiated an arrangement with Hydro-Quebec that 
reduces the cost impacts associated with the purchase of Schedules B and C3 
under the 1987 Contract, over the November 1995 through October 1999 period 
(the July 1994 Agreement).  Under the July 1994 Agreement, the Company, in 
essence, will take delivery of the amounts of energy as specified in the 1987 
Contract, but the associated fixed costs will be significantly reduced from 
those specified in the 1987 Contract.

     As part of the July 1994 Agreement, 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-Quebec 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 kilowatt-hour of 
Schedules B and C3 combined was cut from 6.4 to 4.2 cents per kilowatt-hour, a 
34 percent (or $16 million) cost reduction.  Over the four-year period covered 
by the arrangement, combined unit costs will be lowered from 6.4 to 5.3 cents 
per kilowatt-hour, reducing unit costs by 17 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-Quebec 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 January and November 1996 agreements (described 
below) including historic and projected charges for the years indicated, 
follows:

                                           The 1987 Contract
                                      Schedule B      Schedule C3
                                      ----------      -----------
                                        (Dollars in thousands)

Capacity Acquired . . . .      	        68 MW            46 MW
Contract Period . . . . .              1995-2015        1995-2015
Minimum Energy Purchase
 (annual load factor) . .                 75%               75%

Annual Energy Charge  . .               $10,584          $7,190
                        	                (1996)          (1996)

                                        $15,100        $10,416
                                      (1997-2015)*    (1997-2015)*

Annual Capacity Charge .                $9,637          $1,712
                                        (1996)           (1996)

                                        $17,124        $10,892
                                      (1997-2015)*    (1997-2015)*

Average Cost per KWH . .                 4.7 cents       3.0 cents
                                        (1996) **       (1996)**

                                         7.0 cents       6.4 cents
                                      (1997-2015)***  (1997-2015)***
*  Estimated average.
** Excludes amortization of payments to Hydro-Quebec for the July 1994
   Agreement.
***Estimated average in nominal dollars, levelized over the period indicated.
   Includes amortization of payments to Hydro-Quebec for the July 1994
   Agreement.

     Under an agreement negotiated in January 1996 (the January 1996 
Agreement), Hydro-Quebec provided a cash payment to the Company of $3.0 
million in 1996 and will provide a cash payment of $1.1 million in 1997.  In 
return, the Company has agreed, under certain circumstances, to shift up to 40 
megawatts of the Schedule C3 deliveries from the NEPOOL/Hydro-Quebec 
interconnection facilities to an alternate transmission path, using the freed-
up transmission path for an incremental purchase.  The Company will purchase 
an annual minimum quantity of energy for the Company's use or resale for the 
period of September 1996 through June 2001.  The purchase price will vary 
based upon conditions in effect when the purchases are made, or on the resale 
conditions at the time.  Should the Company not satisfy its obligation to 
purchase the quantity of energy in any calendar year, it must pay a 
cancellation fee or rollover its residual purchase obligation into the 
succeeding calendar year period.  Although the level of benefits to the 
Company will depend on various factors, the Company estimates that the January 
1996 Agreement will provide a minimum benefit of $1.8 million on a net present 
value basis.  During 1996, the Company purchased or sold to others, 87.8% of 
the minimum purchase obligation for that year.  The remainder of the 
requirement has been rolled over into the 1997 calendar year energy purchase 
obligation.

     Under a Memorandum of Understanding negotiated in November 1996, Hydro-
Quebec will provide cash payments of $8.0 million to the Company in 1997.  In 
return for this payment, the Company is providing Hydro-Quebec with the choice 
of selecting one of two alternatives, described below:
Alternative A:  For the period commencing November 1, 1997 and effective 
through the remaining term of the 1987 Contract, which expires in 2015, Hydro-
Quebec can exercise an option to purchase up to 105,000 MWh on an annual 
basis, at energy prices established in accordance with the 1987 Contract, for 
an amount of energy equivalent to the Company's firm capacity entitlements in 
the 1987 Contract.  The cumulative amount of energy purchased over the 
remaining term of the 1987 Contract shall not exceed 1,900,000 MWh.  Hydro-
Quebec may not exercise its annual rights to purchase power in the amounts 
specified under the November 1996 Agreement during those years in which Hydro-
Quebec exercises its rights to curtail energy deliveries in accordance with 
the July 1994 Agreement. 
Alternative B:  For the period commencing November 1, 1997 and effective 
through the remaining term of the 1987 Contract, Hydro-Quebec can exercise an 
option to purchase up to 52,500 MWh on an annual basis, at energy prices 
established in accordance with the 1987 Contract, for an amount of energy 
equivalent to the Company's firm capacity entitlements in the 1987 Contract.  
The cumulative amount of energy purchased over the remaining term of the 1987 
Contract shall not exceed 950,000 MWh.  Unlike Alternative A, Hydro-Quebec's 
option to curtail energy deliveries pursuant to the July 1994 Agreement can be 
exercised in addition to the purchase option under Alternative B.  Finally, 
for the period commencing January 1, 1998 and effective though the remaining 
term of the 1987 Contract under Alternative B, Hydro-Quebec can exercise an 
option on an annual basis to purchase up to 600,000 MWh at the 1987 Contract 
energy price. Hydro-Quebec can purchase no more than 200,000 MWh in any given 
year.  

     Consistent with allowed ratemaking treatment, the $8.0 million payment 
will be recognized in income in the third and fourth quarters of 1997.


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, 1996 and 1995, and the related 
consolidated statements of income and cash flows for each of the three 
years in the period ended December 31, 1996.  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, 1996 and 1995, and 
the consolidated results of its operations and its cash flows for each 
of the three years in the period ended December 31, 1996, in conformity 
with generally accepted accounting principles.


/s/ ARTHUR ANDERSEN LLP



Boston, Massachusetts
January 31, 1997


<TABLE>
<CAPTION>

Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1996, 1995 and 1994

                                                                  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)
  1996.................................          $0       $     --         $   --           $   --                  $0
  1995.................................          $0       $     --         $   --           $   --                  $0
  1994.................................    $684,430       $     --         $   --             $684,430              $0


Injuries and Damages
  1996.................................    $103,301          $572,000      $   --             $437,409        $237,892
  1995.................................    $513,720           $38,000      $   --             $448,419        $103,301
  1994.................................    $105,660           $35,000         $394,430         $21,370        $513,720


Bad Debt Reserve (3)
  1996.................................    $417,684          $677,272          $72,344 (2)    $669,276        $498,024
  1995.................................    $402,923          $371,564          $48,696 (2)    $405,499        $417,684
  1994.................................    $639,853          $243,974          $53,076 (2)    $533,980        $402,923

(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," 
"Board Compensation, Other Relationship, Meetings and Committees," "Section 
16(a) Beneficial Ownership Reporting Compliance," "Executive Compensation," 
"Compensation Committee Report on Executive Compensation," "Performance 
Graphs," "Pension Plan Information" and "Securities Ownership of Certain 
Beneficial Owners and Management" in the Company's definitive proxy statement 
relating to its annual meeting of stockholders to be held on May 15, 1997.  
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 1997.


PART IV

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           37
statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.

<TABLE>
<CAPTION>

ITEM 14(a)(3).                   EXHIBITS

                                                                 Incorporated by Reference from                
Exhibit                                                                           SEC Docker 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-a-2      Amendment to 3-a above, dated as of October 11, 1996.     3-a-2       Form 10-Q Sept. 1996
                                                                                 (1-8291)

*3-b        By-laws of the Company, as amended                       
             February 10, 1997.                                                  

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

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

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

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

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

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

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

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

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

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

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

4-b-12     Twelfth Supplemental 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              4-b-16     Form 10-K 1995
              December 1, 1995.                                                 (1-8291)

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

10-b-36    Agreement with respect to use of Quebec                   10-b-36         33-8164
             Interconnection dated as of December 1, 1981,
             among participating New England utilities 
             for use of transmission interconnection
             between New England and Hydro-Quebec.

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

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

10-b-41    VETCO Capital Funds Support Agreement dated as            10-b-41        33-8164
             of July 15, 1982, between VELCO and 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
             between Niagara 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-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-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 D. G. Hyde, E. M. Norse,        10-d-5a     Form 10-K 1990
             C. L. Dutton, S. C. Terry and T.C. Boucher.                         (1-8291)

10-d-6     Severance Agreements with W. S. Oakes,                    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-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-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-d-18   Severance Agreement with R. B. Hieber                     10-d-18     
                                                                                 

*10-d-19   Severance Agreement with R. J. Griffin                    10-d-19     
                                                                                 

*10-d-20   Severance Agreement with K. W. Hartley                    10-d-20     
                                                                                 

*21        Subsidiaries of the Registrant

*23-a-1    Consent of Arthur Andersen LLP

*24        Power of Attorney

*27        Financial Data Schedule

____________________
* Filed herewith



ITEM 14(b)	

	A report on Form 8-K was filed on December 11, 1996 setting forth the 
computation of the Company's ratio of earnings to fixed charges and preferred 
stock dividends.



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/ Douglas G. Hyde
                                             Douglas G. Hyde, President
                                             and Chief Executive Officer

Date:  March 28, 1997

     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/ Douglas G. Hyde          President and Director              March 28, 1997
   Douglas G. Hyde            (Principal Executive Officer)

 /s/ Christopher L. Dutton    Vice President, Treasurer and       March 28, 1997
   Christopher L. Dutton      Chief Financial Officer (Principal 
                              Financial Officer)

 /s/ Robert J. Griffin        Controller                          March 28, 1997
   Robert J. Griffin          (Principal Accounting Officer)

     *Thomas P. Salmon        Chairman of the Board 

    *Robert E. Boardman       )

     *Nordahl L. Brue         )

    *William H. Bruett        )

     *Merrill O. Burns        )

  *Lorraine E. Chickering     )

     *John V. Cleary          )
                                    Directors
    *Richard I. Fricke        )

     *Euclid A. Irving        )

    *Martin L. Johnson        )

      *Ruth W. Page           )

*By: /s/ Christopher L. Dutton_                                  March 28, 1997
     Christopher L. Dutton
     (Attorney - in - Fact)




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 31, 1997.  
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 37 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 31, 1997                     /s/  Arthur Andersen LLP


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