SECURITIES AND EXCHANGE COMMISSION

                           Washington, D. C.  20549

                     

                         FORM 10-K/A, Amendment No.1

                  For the fiscal year ended December 31, 1995

                         Commission file number  1-8291

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


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

    For the transition period from ________________ to __________________


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

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

    25 Green Mountain Drive 
     South Burlington, VT                                05403
_________________________________                      __________
(Address of principal executive offices)               (Zip  Code)

Registrant's telephone number, including area code   (802) 864-5731       
                                                     ________________

Securities registered pursuant to Section 12(b) of the Act:

     Title of Each Class             Name of each exchange on which registered

COMMON STOCK, PAR VALUE                       NEW YORK STOCK EXCHANGE
  $3.33-1/3 PER SHARE

________________________________________________________________________
Securities registered pursuant to Section 12 (g) of the Act:  None
________________________________________________________________________

     Indicate by check mark whether the registrant (1) has filed all 
reports required to be filed by Section 13 or 15(d) of the Securities 
Exchange Act of 1934 during the preceding 12 months (or for such shorter 
period that the registrant was required to file such reports), and (2) 
has been subject to such filing requirements for the past 90 days.  Yes  
__X__     No _____



     Indicate by check mark if disclosure of delinquent filers pursuant 
to Item 405 of Regulation S-K is not contained herein, and will not be 
contained, to the best of registrant's knowledge, in definitive proxy or 
information statements incorporated by reference in Part III of this 
Form 10-K or any amendment to this Form 10-K. _X_

     The aggregate market value of the voting stock held by 
nonaffiliates of the registrant as of March 15, 1996, was 
$132,671,421.00 based on the closing price for the Common Stock on the 
New York Stock Exchange as reported by The Wall Street Journal.

     The number of shares of Common Stock outstanding on March 15, 1996, 
was 4,868,676.


DOCUMENTS INCORPORATED BY REFERENCE

	The Company's Definitive Proxy Statement relating to its Annual 
Meeting of Stockholders to be held on May 16, 1996, to be filed with the 
Commission pursuant to Regulation 14A under the Securities Exchange Act 
of 1934, is incorporated by reference in  Items 10, 11, 12 and 13 of 
Part III of this Form 10-K.

PART 1

ITEM 1.  BUSINESS

THE COMPANY

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

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

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

     The principal territory served by the Company comprises an area 
roughly 25 miles in width extending 90 miles across north central 
Vermont between Lake Champlain on the west and the Connecticut River on 
the east.  Included in this territory are the cities of Montpelier, 
Barre, South Burlington, Vergennes and Winooski, as well as the Village 
of Essex Junction and a number of smaller towns and communities.  The 
Company also distributes electricity in four noncontiguous areas located 
in southern and southeastern Vermont that are interconnected with the 
Company's principal service area through the transmission lines of VELCO 
and others.  Included in these areas are the communities of Vernon 
(where the Vermont Yankee plant is located), Bellows Falls, White River 
Junction, Wilder, Wilmington and Dover.  The Company also supplies at 
wholesale a portion of the power requirements of several municipalities 
and cooperatives in Vermont and one utility in another state.  The 
Company is obligated to meet the changing electrical requirements of 
these wholesale customers, in contrast to the Company's obligation to 
other wholesale customers, which is limited to specified amounts of 
capacity and energy established by contract.

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

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


RECENT RATE DEVELOPMENTS

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

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

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

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


CONSTRUCTION

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

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


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

*Includes $8.771 million projected for wind project.

</TABLE>

     Construction projections are subject to continuing review and may 
be revised from time-to-time in accordance with changes in the Company's 
financial condition, load forecasts, the availability and cost of labor 
and materials, licensing and other regulatory requirements, changing 
environmental standards and other relevant factors.

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

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

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

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

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

<TABLE>
<CAPTION>


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


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

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



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

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


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


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


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

</TABLE>


DEMAND-SIDE MANAGEMENT

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

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

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

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

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



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

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


     Rate Design.  The Company seeks to design rates to encourage the 
shifting of electrical use from peak hours.  Since 1976, the Company has 
offered optional time-of-use rates for residential and commercial 
customers.  Currently, approximately 2,500 of the Company's residential 
customers continue to be billed on the original 1976 time-of-use rate 
basis.   In 1987, the Company received regulatory approval for a rate 
design that permitted it to charge prices for electric service that 
reflected as accurately as possible the cost burden imposed by each 
customer class.  The Company depends on fair pricing to keep customers 
satisfied and to make predictable the customer use of its power supply 
so that it can keep control of its costs.  This rate structure helps to 
achieve these goals.  Since inefficient use of electricity increases its 
cost, customers who are charged prices that reflect the cost of 
providing electrical service have real incentives to follow the most 
efficient usage patterns.  Included in the VPSB's order approving this 
rate design was a requirement that the Company's largest customers be 
charged time-of-use rates on a phased-in basis by 1994.  Approximately 
1,400 of the Company's largest customers, comprising 48% of retail 
revenues, were successfully converted to time-of-use rates.  In May 
1994, the Company filed a new rate design case with the VPSB.  The 
parties, including the Department, IBM and a low-income advocacy group, 
entered into a settlement that was approved by the VPSB on December 2, 
1994.  Under the settlement, the revenue allocation to each rate class 
was adjusted to reflect class-by-class cost changes since 1987, the 
differential between the winter and summer rates was reduced, the 
customer charge was increased for most classes, and usage charges were 
adjusted to be closer to the associated marginal costs.


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


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


POWER RESOURCES

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

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

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

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

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

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

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

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

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

     Vermont Yankee.  The Company and Central Vermont Public Service 
Corporation acted as lead sponsors in the construction of the Vermont 
Yankee nuclear plant, a boiling-water reactor designed by General 
Electric Company.  The plant, which became operational in 1972, has a 
generating capacity of 535 MW.  Vermont Yankee has entered into power 
contracts with its sponsor utilities, including the Company, that expire 
at the end of the life of the unit.  Pursuant to its Power Contract, the 
Company is required to pay 20% of Vermont Yankee's operating expenses 
(including depreciation and taxes), fuel costs (including charges in 
respect of estimated costs of disposal of spent nuclear fuel), 
decommissioning expenses, interest expense and return on common equity, 
whether or not the Vermont Yankee plant is operating.  In 1969, the 
Company sold to other Vermont utilities 2.735% of its entitlement to the 
output of Vermont Yankee.  Accordingly, those utilities have an 
obligation to the Company to pay 2.735% of Vermont Yankee's operating 
expenses, fuel costs, decommissioning expenses, interest expense and 
return on common equity.  Vermont Yankee has also entered into capital 
funds agreements with its sponsor utilities that expire on December 31, 
2002.  Under its Capital Funds Agreement, the Company is required, 
subject to obtaining necessary regulatory approvals, to provide 20% of 
the capital requirements of Vermont Yankee not obtained from outside 
sources.

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

     During periods when Vermont Yankee is unavailable, the Company 
incurs replacement-power costs in excess of those costs that the Company 
would have incurred for power purchased from Vermont Yankee.  
Replacement power is available to the Company from NEPOOL and through 
special contractual arrangements with  other utilities.  Replacement-
power costs adversely affect cash flow and, absent deferral, 
amortization and recovery through rates, would adversely affect reported 
earnings.  Routinely, in the case of scheduled outages for refueling, 
the VPSB has permitted the Company to defer, amortize and recover these 
excess replacement power costs for financial reporting and ratemaking 
purposes over the period until the next scheduled outage.  Vermont 
Yankee has adopted an 18-month refueling schedule.  On March 16, 1995, 
Vermont Yankee began a scheduled refueling outage which ended May 3, 
1995.  Vermont Yankee's next scheduled refueling is August 1996.  In the 
case of unscheduled outages of significant duration resulting in 
substantial unanticipated costs for replacement power, the VPSB 
generally has authorized deferral, amortization and recovery of such 
costs.  

     Vermont Yankee's current estimate of decommissioning is 
approximately $347,000,000, of which $141,000,000 has been funded.  At 
December 31, 1995, the Company's portion of the net unfunded liability 
was $36,000,000, which it expects will be recovered through rates over 
Vermont Yankee's remaining operating life.  As a sponsor of Vermont 
Yankee, the Company also is obligated to provide 20% of capital 
requirements not obtained by outside sources. 


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

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

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

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

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

     Insurance has been purchased from Nuclear Electric Insurance 
Limited (NEIL II and NEIL III) to cover the costs of property damage, 
decontamination or premature decommissioning resulting from a nuclear 
incident.  All companies insured with NEIL II and III are subject to 
retroactive assessments if losses exceed the accumulated funds 
available.  The maximum potential assessment against Vermont Yankee with 
respect to NEIL II losses arising during the current policy year is 
$14,000,000 and the NEIL III maximum retroactive assessment is 
$7,000,000.  Vermont Yankee's liability for the retrospective premium 
adjustment for any policy year ceases six years after the end of that 
policy year unless prior demand has been made.


     HYDRO-QUEBEC:

     Highgate Interconnection.  On September 23, 1985, the Highgate 
transmission facilities, which were constructed to import energy from 
Hydro-Quebec in Canada, began commercial operation.  The transmission 
facilities at Highgate include a 200-MW AC-to-DC-to-AC converter 
terminal and seven miles of 345-kV transmission line.  VELCO built and 
operates the converter facilities, which are jointly owned by a number 
of Vermont utilities, including the Company.  On February 11, 1995, the 
transmission facilities maximum capability was upgraded from 200 MW to 
225 MW.


     NEPOOL/Hydro-Quebec Interconnection.  VELCO and certain other 
NEPOOL members have entered into agreements with Hydro-Quebec providing 
for the construction in two phases of a direct interconnection between 
the electric systems in New England and the electric system of Hydro-
Quebec in Canada.  The Vermont participants in this project, which has a 
capacity of 2,000 MW, will derive about 9% of the total power-supply 
benefits associated with the NEPOOL/Hydro-Quebec interconnection.  The 
Company, in turn, receives about one-third of the Vermont share of those 
benefits.

     The benefits of the interconnection include access to surplus 
hydroelectric energy from Hydro-Quebec at a cost below that of the 
replacement cost of power and energy otherwise available to the New 
England participants; energy banking, under which participating New 
England utilities will transmit relatively inexpensive energy to Hydro-
Quebec during off-peak periods and will receive equal amounts of energy, 
after adjustment for transmission losses, from Hydro-Quebec during peak 
periods when replacement costs are higher; and provision for emergency 
transfers and mutual backup to improve reliability for both the Hydro-
Quebec system and the New England systems.


     Phase I.  The first phase (Phase I) of the NEPOOL/Hydro-Quebec 
Interconnection consists of transmission facilities having a capacity of 
690 MW that traverse a portion of eastern Vermont and extend to a 
converter terminal located in Comerford, New Hampshire.  These 
facilities entered commercial operation on October 1, 1986.  Vermont 
Electric Transmission Company, Inc. (VETCO), a wholly owned subsidiary 
of VELCO, was organized to construct, own and operate those portions of 
the transmission facilities located in Vermont.  Total construction 
costs incurred by VETCO for Phase I were $47,850,000.  Of that amount, 
VELCO provided $10,000,000 of equity capital to VETCO through sales of 
VELCO preferred stock to the Vermont participants in the Project.  The 
Company purchased $3,100,000 of VELCO preferred stock to finance the 
equity portion of Phase I.  The remaining $37,850,000 of construction 
cost was financed by VETCO's issuance of $37,000,000 of long-term debt 
in the fourth quarter of 1986 and the balance of $850,000 was financed 
by short-term debt.

     Under the Phase I contracts, each New England participant, 
including the Company, is required to pay monthly its proportionate 
share of VETCO's total cost of service, including its capital costs, as 
well as a proportionate share of the total costs of service associated 
with those portions of the transmission facilities to be constructed in 
New Hampshire by a subsidiary of New England Electric System.


     Phase II.  Agreements executed in 1985 among the Company, VELCO and 
other NEPOOL members and Hydro-Quebec, provided for the construction of 
the second phase (Phase II) of the interconnection between the New 
England electric system and that of Hydro-Quebec.  Phase II expands the 
Phase I facilities from 690 MW to 2,000 MW, and provides for 
transmission of Hydro-Quebec power from the Phase I terminal in northern 
New Hampshire to Sandy Pond, Massachusetts.  Construction of Phase II 
commenced in 1988 and was completed in late 1990.  The Phase II 
facilities commenced commercial operation November 1, 1990, initially at 
a rating of 1,200 MW, and increased to a transfer capability of 2,000 MW 
in July 1991.  The Hydro-Quebec-NEPOOL Firm Energy Contract  provides 
for the import of economical  Hydro-Quebec energy into New England.  The 
Company is entitled to 3.2% of the Phase II power-supply benefits.  
Total construction costs for Phase II were approximately $487,000,000.  
The New England participants, including the Company, have contracted to 
pay monthly their proportionate share of the total cost of constructing, 
owning and operating the Phase II facilities, including capital costs.  
As a supporting participant, the Company must make support payments 
under 30-year agreements.  These support agreements meet the capital 
lease accounting requirements under SFAS 13.  At December 31, 1995, the 
present value of the Company's obligation was $9,800,000.  The Company's 
projected future minimum payments under the Phase II support agreements 
are $488,924 for each of the years 1996-2000 and an aggregate of 
$7,333,867 for the years 2001-2020.  

     The Phase II portion of the project is owned by New England Hydro-
Transmission Electric Company, Inc. and New England Hydro-Transmission 
Corporation, subsidiaries of New England Electric System, in which 
certain of the Phase II participating utilities, including the Company, 
own equity interests.  The Company owns approximately 3.2% of the equity 
of the corporations owning the Phase II facilities.  During construction 
of the Phase II project, the Company, as an equity sponsor, was required 
to provide equity capital.  At December 31, 1995, the capital structure 
of such corporations was 38% common equity and 62% long-term debt.


     Hydro-Quebec Power Supply Contracts.  Under various contracts 
approved by the VPSB, the details of which are described in the table 
below, the Company purchases capacity and associated energy produced by 
the Hydro-Quebec system.  Such contracts obligate the Company to pay 
certain fixed capacity costs whether or not energy purchases above a 
minimum level set forth in the contracts are made.  Such minimum energy 
purchases must be made whether or not other, less expensive energy 
sources might be available.  These contracts are intended to complement 
the other components in the Company's power supply to achieve the most 
economic power-supply mix reasonably available.

<TABLE>
<CAPTION>

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

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

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

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

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

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

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

</TABLE>

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

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

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

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

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

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

     All of the Company's contracts with Hydro-Quebec call for the 
delivery of system power and are not related to any particular 
facilities in the Hydro-Quebec system.  Consequently, there are no 
identifiable debt-service charges associated with any particular Hydro-
Quebec facility that can be distinguished from the overall charges paid 
under the contracts.

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

     In 1995, the Company utilized 190,779.7 MWh of Hydro-Quebec energy 
under the July 1984 contract, 52,816.4 MWh under the December 1987 
contract Schedule A, 99,017.5 Mwh under Schedule B, 49,036.0 Mwh under 
Schedule C3, and 332,430.6 MWh under the tertiary energy contract to 
meet 37.9% of its retail and requirements wholesale sales.  The average 
cost of Hydro-Quebec electricity in 1995 was 3.2 cents per KWh.  See
Notes J and K-2 of Notes to Consolidated Financial Statements.     


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

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

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


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


     Stony Brook I.  The Massachusetts Municipal Wholesale Electric 
Company (MMWEC) is principal owner and operator of a 343.0-MW combined-
cycle intermediate generating station -- Stony Brook I -- located in 
Ludlow, Massachusetts, which commenced commercial operation in November 
1981.  The Company entered into a Joint Ownership Agreement with MMWEC 
dated as of October 1, 1977, whereby the Company acquired an 8.8% 
ownership share of the plant, entitling the Company to 30.2 MW of 
capacity.  In addition to this entitlement, the Company has contracted 
for 13.8 MW of capacity for the life of the Stony Brook I plant, for 
which it will pay a proportionate share of MMWEC's share of the plant's 
fixed costs and variable operating expenses.  The three units that 
comprise Stony Brook I are primarily oil-fired.  Two of the units are 
also capable of burning natural gas.  The natural gas system at the 
plant was modified in 1985 to allow two units to operate simultaneously 
on natural gas.

     During 1995, the Company utilized 35,778.0 MWh from this plant to 
meet 1.8% of its retail and requirements wholesale sales at an average 
cost of 5.4  per Kwh, the portion of these costs attributable to the 
30.2 MW joint ownership share are based only on operation, maintenance, 
and fuel costs incurred in 1995.  See Note I-3 and K-1 of Notes to 
Consolidated Financial Statements.


     Wyman Unit #4.  The W. F. Wyman Unit #4, which is located in 
Yarmouth, Maine, is an oil-fired steam plant with a capacity of 619 MW.  
The construction of this plant was sponsored by Central Maine Power 
Company.  The Company has a joint-ownership share of 1.1% (7.1 MW) in 
the Wyman #4 unit, which began commercial operation in December 1978.

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


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

     Small Power Production.  The VPSB has adopted rules that implement 
for Vermont the purchase requirements established by federal law in the 
Public Utility Regulatory Policies Act of 1978 (PURPA).  Under the 
rules, qualifying facilities have the option to sell their output to a 
central state purchasing agent under a variety of long- and short-term, 
firm and non-firm pricing schedules, each of which is based upon the 
projected Vermont composite system's power costs which would be required 
but for the purchases from small producers.  The state purchasing agent 
assigns the energy so purchased, and the costs of purchase, to each 
Vermont retail electric utility based upon its pro rata share of total 
Vermont retail energy sales.  Utilities may also contract directly with 
producers.  The rules provide that all reasonable costs incurred by a 
utility under the rules will be included in the utilities' revenue 
requirements for ratemaking purposes.

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

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

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

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


     Short-Term Opportunity Purchases and Sales.  The Company has made 
arrangements with several utilities in New England and New York whereby 
the Company may make purchases or sales of utility system power on short 
notice and generally for brief periods of time when it appears economic 
to do so.  Opportunity purchases are arranged when it is possible to 
purchase power from another utility for less than it would cost the 
Company to generate the power with its own sources.  Purchases also help 
the Company save on replacement-power costs during an outage of one of 
its base load sources.  Opportunity sales are arranged when the Company 
has surplus energy available at a price that is economic to other 
regional utilities at any given time.  The sales are arranged based on 
forecasted costs of supplying the incremental power necessary to serve 
the sale.  The price is set so as to recover the forecasted fuel and 
capacity costs.

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


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


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


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


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

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


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

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

     Vermont Yankee has a contract with the United States Department of 
Energy (DOE) for the permanent disposal of spent nuclear fuel.  Under 
the terms of this contract, in exchange for the one-time fee discussed 
below and a quarterly fee of 1 mil per KWh of electricity generated and 
sold, the DOE agrees to provide disposal services when a facility for 
spent nuclear fuel and other high-level radioactive waste is available, 
which is required by contract to be prior to January 31, 1998.

     The DOE contract obligates Vermont Yankee to pay a one-time fee of 
approximately $39,300,000 for disposal costs for all spent fuel 
discharged through April 7, 1983.  Although such amount has been 
collected in rates from  the Vermont Yankee participants, Vermont Yankee 
has elected to defer payment of the fee to the DOE as permitted by the 
DOE contract.  The fee must be paid no later than the first delivery of 
spent nuclear fuel to the DOE.  Interest accrues on the unpaid 
obligation based on the thirteen-week Treasury Bill rate and is 
compounded quarterly.  Through 1995, Vermont Yankee accumulated 
approximately $66,000,000 in an irrevocable trust to be used exclusively 
for defeasing this obligation at some future date, provided the DOE 
complies with the terms of the aforementioned contract.

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

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

     Wood for the McNeil plant is furnished to the Burlington Electric 
Department from a variety of sources under short-term contracts ranging 
from several weeks' to six months' duration.  The McNeil plant used 
196,626 tons of wood chips and mill residue and 130,703,000 cubic feet 
of gas in 1995.  The McNeil plant is forecasting consumption of wood 
chips for 1996 to be 150,000 tons and gas consumption of 300,000,000 
cubic feet.  Burlington Electric Department advises that, as of February 
24, 1996, there were 17,550 tons of wood chips in inventory for the 
McNeil plant.

     The Stony Brook combined-cycle generating station is capable of 
burning either natural gas or oil in two of its turbines.  Natural gas 
is supplied to the plant subject to its availability.  During periods of 
extremely cold weather, the supplier reserves the right to discontinue 
deliveries to the plant in order to satisfy the demand of its 
residential customers.  The Company assumes for planning and budgeting 
purposes that the plant will be supplied with gas during the months of 
April through November, and that it will run solely on oil during the 
months of December through March.  The plant maintains an oil supply 
sufficient to meet approximately one-half of its annual needs.


FUTURE POWER RESOURCES

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

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

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

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

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

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


STATE AND FEDERAL REGULATION

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

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

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

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

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

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

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


     Licensing.  Pursuant to the Federal Power Act, the FERC has granted 
licenses for the following hydro projects:

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

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

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

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

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

     Major project licenses provide that after an initial twenty-year 
period, a portion of the earnings of such project in excess of a 
specified rate of return is to be set aside in appropriated retained 
earnings in compliance with FERC Order #5, issued in 1978.  Although the 
twenty-year periods expired in 1985, 1969 and 1971 in the cases of the 
Essex, the Vergennes and the Waterbury projects, the amounts 
appropriated are not material.  


     Department of Public Service Twenty-Year Power Plan.  In December 
1994, the Department adopted an update of its twenty-year electrical 
power-supply plan (the Plan) for the State of Vermont.  The Plan 
includes an overview of statewide growth and development as they relate 
to future requirements for electrical energy; an assessment of available 
energy resources; and estimates of future electrical energy demand.

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


ENVIRONMENTAL MATTERS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


COMPETITION

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

     Legislative authority has existed since 1941 that would permit 
Vermont cities, towns and villages to own and operate public utilities.  
Since that time, no municipality served by the Company has established 
or, as far as is known to the Company, is presently taking steps to 
establish, a municipal public utility.

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

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

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

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

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


BUSINESS DEVELOPMENT

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

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

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

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


EMPLOYEES

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


SEASONAL NATURE OF BUSINESS

     The Company experiences its heaviest loads in the colder months of 
the year.  Winter recreational activities, longer hours of darkness and 
heating loads from cold weather usually cause the Company's peak 
electric sales to occur in December, January or February.  The 1995 peak 
of 297.1 MW occurred on February 6, 1995.  The Company's retail electric 
rates are seasonally differentiated.  Under this structure, retail 
electric rates produce average revenues per kilowatt hour during four 
peak season months (December through March) that are approximately 30% 
higher than during the eight off-season months (April through November).  
See discussion -- Demand-Side Management -- Rate Design.




EXECUTIVE OFFICERS

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

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

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

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

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

Glenn J. Purcell           62    Controller since September 1986.

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

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

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



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

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

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

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

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

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

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