SECURITIES AND EXCHANGE COMMISSION

                           Washington, D. C.  20549

                     

                                   FORM 10-K


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


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

For the transition period from ________________ to __________________

                   For the fiscal year ended December 31, 1997

                         Commission file number  1-8291

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

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

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

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

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

     Title of Each Class            Name of each exchange on which registered

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

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

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



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

     The aggregate market value of the voting stock held by non-
affiliates of the registrant as of March 13, 1998, was $94,094,396.88 
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 13, 1998, 
was 5,191,415.


                    DOCUMENTS INCORPORATED BY REFERENCE

	The Company's Definitive Proxy Statement relating to its Annual 
Meeting of Stockholders to be held on May 21, 1998, to be filed with the 
Commission pursuant to Regulation 14A under the Securities Exchange Act 
of 1934, is incorporated by reference in  Items 10, 11, 12 and 13 of 
Part III of this Form 10-K.

                                   PART I

ITEM 1.  BUSINESS
                                THE COMPANY

     Green Mountain Power Corporation (the Company) is a public utility 
operating company engaged in supplying electrical energy in the State of 
Vermont in a territory with approximately one quarter of the State's 
population.  It serves approximately 83,000 customers.  The Company was 
incorporated under the laws of the State of Vermont on April 7, 1893.

     For the year ended December 31, 1997, the Company's sources of 
revenue were derived as follows:  34.3% from residential customers, 
32.7% from small commercial and industrial customers, 21.1% from large 
commercial and industrial customers, 10.0% from sales to other 
utilities, and 1.9% from other sources.  For the same period, the 
Company's energy resources for retail and requirements wholesale sales 
were obtained as follows: 46.9% from hydroelectric sources (6.9% 
Company-owned, 0.1% New York Power Authority (NYPA), 36.8% Hydro-Quebec 
and 3.1% small power producers), 36.5% from nuclear generating sources 
(the Vermont Yankee plant described below), 9.2% from coal sources, 3.3% 
from wood, 0.9% from natural gas, 0.5% from oil, and 0.3% from wind.  
The remaining 2.4% was purchased on a short-term basis from other 
utilities and through the New England Power Pool (NEPOOL).  In 1997, 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 531-MW Vermont Yankee nuclear 
generating plant owned and operated by Vermont Yankee Nuclear Power 
Corporation (Vermont Yankee), in which the Company has a 17.9% equity 
interest.  For information concerning Vermont Yankee, see "Power 
Resources - Vermont Yankee."

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

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

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

     During the years ended December 31, 1997, 1996, and 1995, electric 
energy sales to International Business Machines Corporation (IBM), the 
Company's largest customer, accounted for 14.0%, 13.2% and 12.9%, 
respectively, of the Company's operating revenues in those years.  No 
other retail customer accounted for more than 1.0% of the Company's 
revenue.  Under the present regulatory system, the loss of IBM as a 
customer of the Company would require the Company to seek rate relief to 
recover the revenues previously paid by IBM from other customers in an 
amount sufficient to offset the fixed costs that IBM had been covering 
through its payments.


                                 EMPLOYEES


     The Company had 321 employees, exclusive of temporary employees, as 
of December 31, 1997.  In addition, subsidiaries of the Company had 48 
employees at year end.


                       SEASONAL NATURE OF BUSINESS


     The Company experiences its heaviest loads in the colder months of 
the year.  Winter recreational activities, longer hours of darkness and 
heating loads from cold weather usually cause the Company's peak 
electric sales to occur in December, January or February.  The Company's 
heaviest load in 1997 - 311.5 MW - occurred on December 22, 1997.  The 
Company's retail electric rates are seasonally differentiated.  Under 
this structure, retail electric rates produce average revenues per 
kilowatt hour during four peak season months (December through March) 
that are approximately 30% higher than during the eight off-season 
months (April through November).  See "Energy Efficiency - Rate Design."

<TABLE>
<CAPTION>

OPERATING STATISTICS
For the Years Ended December 31
                                                          1997          1996          1995          1994          1993
                                                       ----------    ----------    ----------    ----------    ----------


<S>                                                        <C>           <C>           <C>           <C>           <C>
Net System Capability During Peak Month (MW)
  Hydro (1)............................................    180.0         193.8         152.1         179.0         174.9
  Lease transmissions..................................      0.6           0.6           0.3           2.1           3.9
  Nuclear (1)..........................................     95.7          95.7          81.9         107.2         109.5
  Conventional steam...................................     53.0          52.9          77.8          67.1          92.6
  Internal combustion..................................     64.0          60.7          62.0          60.2          71.0
  Combined cycle.......................................     22.1          22.1          22.0          22.6          22.8
  Wind.................................................      1.5         --            --            --            --
                                                       ----------    ----------    ----------    ----------    ----------
    Total capability (MW)..............................    416.9         425.8         396.1         438.2         474.7
  Net system peak......................................    311.5         313.0         297.1         308.3         307.3
                                                       ----------    ----------    ----------    ----------    ----------
  Reserve (MW).........................................    105.4         112.8          99.0         129.9         167.4
                                                       ==========    ==========    ==========    ==========    ==========
  Reserve % of peak....................................     33.8%         36.0%         33.3%         42.1%         54.5%

Net Production (MWH)
  Hydro (1)............................................1,073,246     1,192,881     1,043,617       742,088       751,078
  Lease transmissions..................................    --            --            --            --           15,425
  Nuclear (1)..........................................  772,030       680,613       682,814       763,690       598,245
  Conventional steam...................................  560,504       705,331       673,982       651,105       748,626
  Internal combustion..................................    4,827         2,674         6,646         3,532         2,849
  Combined cycle.......................................  104,836        51,162        92,723        37,808        40,966
                                                       ----------    ----------    ----------    ----------    ----------
    Total production...................................2,515,443     2,632,661     2,499,782     2,198,223     2,157,189
  Less non-requirements sales to other utilities.......  524,192       663,175       582,942       328,794       271,224
                                                       ----------    ----------    ----------    ----------    ----------
  Production for requirements sales....................1,991,251     1,969,486     1,916,840     1,869,429     1,885,965
  Less requirements sales & lease transmissions (MWH)..1,870,913     1,814,371     1,760,830     1,730,497     1,749,454
                                                       ----------    ----------    ----------    ----------    ----------
  Losses and company use (MWH).........................  120,338       155,115       156,010       138,932       136,511
                                                       ==========    ==========    ==========    ==========    ==========
Losses as a percentage of total production.............     4.78%         5.89%         6.24%         6.32%         6.33%
System load factor (2).................................     71.6%         69.7%         71.2%         67.7%         68.7%

Sales and Lease Transmissions (MWH)
  Residential - GMP....................................  549,259       557,726       549,296       564,635       541,579
  Lease transmissons...................................    --            --            --            --           15,425
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................  549,259       557,726       549,296       564,635       557,004
  Commercial & industrial - small......................  645,331       630,839       608,688       604,686       593,560
  Commercial & industrial - large......................  608,051       584,249       556,278       521,400       529,372
  Other................................................    3,939         2,898         8,855         1,146         8,868
                                                       ----------    ----------    ----------    ----------    ----------
    Total retail sales and lease transmissions.........1,806,580     1,775,712     1,723,117     1,691,867     1,688,804
  Sales to municipals and cooperatives and
    other requirements sales...........................   64,333        38,659        37,713        38,630        60,650
                                                       ----------    ----------    ----------    ----------    ----------
    Total requirements sales...........................1,870,913     1,814,371     1,760,830     1,730,497     1,749,454
  Other sales for resale...............................  524,192       663,175       582,942       328,794       271,224
                                                       ----------    ----------    ----------    ----------    ----------
    Total sales and lease transmissions................2,395,105     2,477,546     2,343,772     2,059,291     2,020,678
                                                       ==========    ==========    ==========    ==========    ==========

Average Number of Electric Customers
  Residential..........................................   70,671        70,198        69,659        68,811        67,994
  Commercial and industrial - small....................   11,989        11,828        11,712        11,611        11,447
  Commercial and industrial - large....................       23            25            24            24            25
  Other................................................       75            75            76            76            74
                                                       ----------    ----------    ----------    ----------    ----------
    Total..............................................   82,758        82,126        81,471        80,522        79,540
                                                       ==========    ==========    ==========    ==========    ==========

Average Revenue per KWH (Cents)
  Residential including lease revenues.................    11.18         10.87         10.09          9.03          8.94
  Lease charges........................................      --            --            --            --           0.06
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................    11.18         10.87         10.09          9.03          9.00
  Commercial and industrial - small....................     9.10          8.96          8.42          8.00          7.97
  Commercial and industrial - large....................     6.22          6.28          5.86          6.02          5.96
  Total retail including lease revenues................     8.94          8.92          8.36          7.96          7.86

Average Use and Revenue Per Residential Customer
  Kilowatt hours including lease transmissions.........    7,772         7,945         7,885         8,206         8,192
  Revenues including lease revenues....................     $869          $863          $796          $741          $733


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

</TABLE>

                          STATE AND FEDERAL REGULATION


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

     The Company's rate tariffs are uniform throughout its service area.  
The Company has entered into two economic development agreements, 
providing for reduced charges to large customers to be applied only to 
new load.  A third economic development agreement with IBM was part of 
the rate settlement approved by the VPSB on May 23, 1996.  See Item 7. 
Management's Discussion and Analysis of Financial Condition and Results 
of Operations (MD&A) - "Results of Operations - Operating Revenues and 
MWh Sales."

     The Company's wholesale rate on sales to three wholesale customers 
is regulated by the Federal Energy Regulatory Commission (FERC).  
Revenues from sales to these customers were approximately 0.8% of 
operating revenues for 1997.

     Late in 1989, the Company began serving a municipal utility, 
Northfield Electric Department, under its wholesale tariff.  This 
customer increased the Company's electricity sales by approximately 
23,406.4 MWh and peak requirements by approximately 5.5 MW.  Revenues in 
1997 from Northfield were $1,348,962.

     The Company provides transmission service to twelve customers 
within the State under rates regulated by the FERC; revenues for such 
services amounted to less than 1.0% of the Company's operating revenues 
for 1997.

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

     By reason of its relationship with Vermont Yankee, VELCO and 
Vermont Electric Transmission Company, Inc. (VETCO), a wholly owned 
subsidiary of VELCO, the Company has filed an exemption statement under 
Section 3(a)(2) of the Public Utility Holding Company Act of 1935, 
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.  The Plan includes an 
overview of statewide growth and development as they relate to future 
requirements for electrical energy; an assessment of available energy 
resources; and estimates of future electrical energy demand.

     The Company's Integrated Resource Plan (IRP) was published in June 
1996.  It was developed in a manner consistent with the Department's 
Plan.  The Company's 1996 IRP calls for a greater emphasis on 
distributed utility approaches that can best use the Company's assets, 
maximize the benefit of energy efficiency programs, and provide 
customers with the highest quality service.


                           RECENT RATE DEVELOPMENTS


     On June 16, 1997, the Company filed a request with the VPSB to 
increase retail rates by 16.7 percent and the target return on common 
equity from 11.25 percent to 13 percent.  The retail rate increase is 
needed to cover higher power supply costs and the Company's rising cost 
of capital.  For further information regarding recent rate developments, 
see Item 7. MD&A - "Liquidity and Capital Resources - Rates" and Note 
I.5 of Notes to Consolidated Financial Statements.


                        COMPETITION AND RESTRUCTURING


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

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

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

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


                              POWER RESOURCES


     The Company generated, purchased or transmitted 1,954,535.9 MWh of 
energy for retail and requirements wholesale customers for the twelve 
months ended December 31, 1997.  The corresponding maximum one-hour 
integrated demand during that period was 311.5 MW on December 22, 1997.  
This compares to the previous all-time peak of 322.6 MW on December 27, 
1989.  The following tabulation shows the source of such energy for the 
twelve-month period and the capacity in the month of the period system 
peak.  See also "Power Resources - Long-Term Power Sales."

                                   Net Generated and      Net Generated and
                                   Purchased in Year      Purchased in Month
                                   Ended 12/31/97 (a)       of Annual Peak
                                  ___________________    ___________________
                                     MWh         %         KW          %
WHOLLY OWNED PLANTS
  Hydro                            140,754.0    6.9        35,300       8.5
  Diesel and Gas Turbine             2,671.7    0.1        61,030      14.6
  Searsburg                          5,386.7    0.3         1,500       0.4

JOINTLY OWNED PLANTS
  Wyman #4                           3,386.1    0.2         7,030       1.7
  Stony Brook I                      7,339.2    0.4         7,990       1.9
  McNeil                            11,075.7    0.5         6,450       1.5

OWNED IN ASSOCIATION W/OTHERS
  Vermont Yankee Nuclear           748,068.8   36.5        95,680      22.9

NYPA LEASE TRANSMISSIONS
  State of Vermont (NYPA)            1,541.9    0.1           620       0.1

LONG-TERM PURCHASES
  Hydro-Quebec                     754,280.5   36.8       126,680      30.4
  Merrimack #2                     189,033.1    9.2        31,820       7.6
  Stony Brook I                     14,647.2    0.7        14,150       3.4
  Small Power Producers            121,938.4    5.9        24,860       6.0

SHORT-TERM PURCHASES                52,185.9    2.4         3,860       1.0
                                 ___________   ____       _______     _____
                                 2,052,309.2   100.0
  Less System Sales Energy        (97,773.8)                   

  NET OWN LOAD                   1,954,535.4              416,970    100.0
                                 ===========  ======      =======    ======

(a) Excludes losses on off-system purchases, totaling 36,716 MWh per GA-
35 MWh production report.


     Vermont Yankee.  The Company and Central Vermont Public Service 
Corporation acted as lead sponsors in the construction of the Vermont 
Yankee nuclear plant, a boiling-water reactor designed by General 
Electric Company.  The plant, which became operational in 1972, has a 
generating capacity of 531 MW.  Vermont Yankee has entered into power 
contracts with its sponsor utilities, including the Company, that expire 
at the end of the life of the unit.  Pursuant to its Power Contract, the 
Company is required to pay 20% of Vermont Yankee's operating expenses 
(including depreciation and taxes), fuel costs (including charges in 
respect of estimated costs of disposal of spent nuclear fuel), 
decommissioning expenses, interest expense and return on common equity, 
whether or not the Vermont Yankee plant is operating.  In 1969, the 
Company sold to other Vermont utilities a share of its entitlement to 
the output of Vermont Yankee.  Accordingly, those utilities had an 
obligation to the Company to pay 2.735% of Vermont Yankee's operating 
expenses, fuel costs, decommissioning expenses, interest expense and 
return on common equity.  As a result of the bankruptcy of one of those 
utilities, a portion of the entitlement has reverted back to the 
Company.  Accordingly, those utilities have an obligation to the Company 
to pay 2.338% of Vermont Yankee's operating expenses, fuel costs, 
decommissioning expenses, interest expense and return on common equity.

     Vermont Yankee has also entered into capital funds agreements with 
its sponsor utilities that expire on December 31, 2002.  Under its 
Capital Funds Agreement, the Company is required, subject to obtaining 
necessary regulatory approvals, to provide 20% of the capital 
requirements of Vermont Yankee not obtained from outside sources.

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

     In New England, five nuclear units are currently under orders from 
the NRC not to operate until shown to be in compliance with applicable 
safety provisions.  In December 1996 and August 1997, decisions were 
made to retire two New England nuclear units, Connecticut Yankee and 
Maine Yankee, effective immediately, with several years remaining on 
each license.  The NRC's most recently issued Vermont Yankee's 
Systematic Assessment of Licensee Performance scores are for the period 
July 16, 1995 to January 18, 1997.  Operations, engineering and 
maintenance were rated good, while plant support was rated superior.  
These scores are identical to Vermont Yankee's scores for the prior 18 
month-period.  

     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 21, 1998, 
Vermont Yankee began a scheduled refueling outage.  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 as approved by 
FERC is approximately $386,000,000, of which $193,000,000 has been 
funded.  At December 31, 1997, the Company's portion of the net unfunded 
liability was $34,000,000, which it expects will be recovered through 
rates over Vermont Yankee's remaining operating life.

     During 1997, the Company incurred $27,200,000 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, 
1997 was $16,000,000.

     During the year ended December 31, 1997, the Company utilized 
748,068.8 MWh of Vermont Yankee energy to meet 36.5% of its retail and 
requirements wholesale (Rate W) sales.  The average cost of Vermont 
Yankee electricity in 1997 was 4.4 cents per KWh.  In 1997, Vermont Yankee 
had an annual capacity factor of 93.5%, compared to 83.0% in 1996 and 
85.0% in 1995.

     
                                 INSURANCE


     The Price-Anderson Act currently limits public liability from a 
single incident  at a nuclear power plant to $8.9 billion.  Any 
liability beyond $8.9 billion are indemnified under an agreement with 
the NRC, but subject to congressional approval.  The first $200 million 
of liability coverage is the maximum provided by private insurance.  The 
Secondary Financial Protection Program is a retrospective insurance plan 
providing additional coverage up to $8.7 billion per incident by 
assessing premiums of $79.3 million against each of the 110 reactor 
units in the United States that are currently subject to the Progam, 
limited to a maximum assessment of $10 million per incident per nuclear 
unit in any one year.  The maximum assessment is expected to be adjusted 
at least every five years to reflect inflationary changes.

     The above insurance now covers all workers employed at nuclear 
facilities for bodily injury claims.  Vermont Yankee had previously 
purchased a Master Worker insurance policy with limits of $200 million 
with one automatic reinstatement of policy limits to cover workers 
employed on or after January 1, 1988.  Vermont Yankee no longer 
participates in this retrospectively based worker policy and has 
replaced this policy with the guaranteed cost coverage mentioned above.  
Vermont Yankee does, however, retain a potential obligation for 
retrospective adjustments due to past operations of several smaller 
facilities that did not join the new program.  These exposures will 
cease to exist no later than December 31, 2007.  Vermont Yankee's 
maximum restrospective obligation remains at $3.1 million.  The 
Secondary Financial Protection layer, as referenced above, would be in 
excess of the Master Worker policy.

     Insurance has been purchased from Nuclear Electric Insurance 
Limited (NEIL) to cover the costs of property damage, decontanmination 
or premature decommissioning resulting from a nuclear incident.  All 
companies insured with NEIL are subject to retroactive assessments if 
losses exceed the accumulated funds available.  The maximum potential 
assessment against Vermont Yankee with respect to NEIL losses arising 
during the current policy year is $11.0 million.  Vermont Yankee's 
liability for the retrospective premium adjustment for any policy year 
ceases six years after the end of that policy year unless prior demand 
has been made. 


HYDRO-QUEBEC


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


     NEPOOL/Hydro-Quebec Interconnection.  VELCO and certain other 
NEPOOL members have entered into agreements with Hydro-Quebec providing 
for the construction in two phases of a direct interconnection between 
the electric systems in New England and the electric system of Hydro-
Quebec in Canada.  The Vermont participants in this project, which has a 
capacity of 2,000 MW, will derive about 9.0% of the total power-supply 
benefits associated with the NEPOOL/Hydro-Quebec interconnection.  The 
Company, in turn, receives about one-third of the Vermont share of those 
benefits.

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


     Phase I.  The first phase (Phase I) of the NEPOOL/Hydro-Quebec 
Interconnection consists of transmission facilities having a capacity of 
690 MW that traverse a portion of eastern Vermont and extend to a 
converter terminal located in Comerford, New Hampshire.  These 
facilities entered commercial operation on October 1, 1986.  VETCO was 
organized to construct, own and operate those portions of the 
transmission facilities located in Vermont.  Total construction costs 
incurred by VETCO for Phase I were $47,850,000.  Of that amount, VELCO 
provided $10,000,000 of equity capital to VETCO through sales of VELCO 
preferred stock to the Vermont participants in the project.  The Company 
purchased $3,100,000 of VELCO preferred stock to finance the equity 
portion of 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 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, 1997, the 
present value of the Company's obligation was $8,300,000.  The Company's 
projected future minimum payments under the Phase II support agreements 
are $463,450 for each of the years 1998-2002 and an aggregate of 
$6,024,845 for the years 2003-2020.  

     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, 1997, the capital structure 
of such corporations was 39.0% common equity and 61.0% long-term debt.  
See Note J of Notes to Consolidated Financial Statements.

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


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

    In 1997, the Company utilized 405,383.2 MWh under Schedule B, 
276,031.2 MWh under Schedule C3, and  72,866.1 MWh under the tertiary 
energy contract to meet 36.8% of its retail and requirements wholesale 
sales.  The average cost of Hydro-Quebec electricity in 1997 was 3.7 cents 
per KWh.


     New York Power Authority (NYPA).  The Department allocates NYPA 
power to the Company which, in turn, delivers the power to its 
residential and farm customers.  The Company purchased at wholesale 
1,541.9 MWh to meet 0.1% of its retail and requirements wholesale sales 
of NYPA power at an average cost of 0.7 cents per KWh in 1997.  Under the 
allocation currently made by NYPA of NYPA power to states neighboring 
New York, residential and farm customers in the Company's service 
territory will be entitled to 0.3 MW annually.

     Merrimack Unit #2.  Merrimack Unit #2 is a coal-fired steam plant 
of 320.0 MW capacity located in Bow, New Hampshire, and owned by 
Northeast Utilities.  The Company is entitled to 28.48 MW of capacity 
and related energy from the unit under a 30-year contract expiring May 
1, 1998.  During the year ended December 31, 1997, the Company utilized 
189,033.1 MWh from the unit to meet  9.2% of its total retail and 
requirements wholesale sales.  The average cost of electricity from this 
unit was 3.4 cents per KWh in 1997.  See Note K-1 of Notes to Consolidated 
Financial Statements.

     Stony Brook I.  The Massachusetts Municipal Wholesale Electric 
Company (MMWEC) is principal owner and operator of Stony Brook, a 352.0-
MW combined-cycle intermediate generating station located in Ludlow, 
Massachusetts, which commenced commercial operation in November 1981.  
The Company entered into a Joint Ownership Agreement with MMWEC dated as 
of October 1, 1977, whereby the Company acquired an 8.8% ownership share 
of the plant, entitling the Company to 31.0 MW of capacity.  In addition 
to this entitlement, the Company has contracted for 14.2 MW of capacity 
for the life of the Stony Brook I plant, for which it will pay a 
proportionate share of MMWEC's share of the plant's fixed costs and 
variable operating expenses.  The three units that comprise Stony Brook 
I are primarily oil-fired.  Two of the units are also capable of burning 
natural gas.  The natural gas system at the plant was modified in 1985 
to allow two units to operate simultaneously on natural gas.

     During 1997, the Company utilized 21,986.4 MWh from this plant to 
meet 1.1% of its retail and requirements wholesale sales at an average 
cost of 9.5 cents (purchased power).  See Note I-4 and K-1 of Notes to 
Consolidated Financial Statements.

     Wyman Unit #4.  The W. F. Wyman Unit #4, which is located in 
Yarmouth, Maine, is an oil-fired steam plant with a capacity of 620 MW.  
The construction of this plant was sponsored by Central Maine Power 
Company.  The Company has a joint-ownership share of 1.1% (6.8 MW) in 
the Wyman #4 unit, which began commercial operation in December 1978.

     During 1997, the Company utilized 3,386.1 MWh from this unit to 
meet 0.2% of its retail and requirements wholesale sales at an average 
cost of 4.7 per kWh, based only on operation, maintenance, and fuel 
costs incurred during 1997.  See Note I-4 of Notes to Consolidated 
Financial Statements.


     McNeil Station.  The J. C. McNeil station, which is located in 
Burlington, Vermont, is a wood chip and gas-fired steam plant with a 
capacity of 53.0 MW.  The Company has an 11% or 5.9 MW interest in the 
J. C. McNeil plant, which began operation in June 1984.  During 1997, 
the Company utilized 11,075.7 MWh from this unit to meet 0.5% of its 
retail and requirements wholesale sales at an average cost of 5.2 cents per 
kWh, based only on operation, maintenance, and fuel costs incurred 
during 1997.  In 1989, the plant added the capability to burn natural 
gas on an as-available/interruptible service basis.  See Note I-4 of 
Notes to Consolidated Financial Statements.


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

     Currently, the state purchasing agent, Vermont Electric Power 
Producers, Inc. (VEPPI), is authorized to seek 150 MW of power from 
qualifying facilities under PURPA, of which the Company's current pro 
rata share would be approximately 32.7% or 49.1 MW.

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

     In 1997, the Company, through both its direct contracts and VEPPI, 
purchased 121,938.4 MWh of qualifying facilities production to meet 5.9% 
of its retail and requirements wholesale sales at an average cost of 
10.7 cents per KWh.


     Short-Term Opportunity Purchases and Sales.  The Company has made 
arrangements with several utilities in New England and New York under 
which the Company may make purchases or sales of utility system power on 
short notice and generally for brief periods of time when it appears 
economic to do so.  Opportunity purchases are arranged when it is 
possible to purchase power from another utility for less than it would 
cost the Company to generate the power with its own sources.  Purchases 
also help the Company save on replacement power costs during an outage 
of one of its base load sources.  Opportunity sales are arranged when 
the Company has surplus energy available at a price that is economic to 
other regional utilities at any given time.  The sales are arranged 
based on forecasted costs of supplying the incremental power necessary 
to serve the sale.   Prices are set so as to recover all of the 
forecasted fuel or production costs and to recover some if not all 
associated capacity costs.

     During 1997, the Company purchased 52,185.9 MWh, meeting 2.4% of 
the Company's retail and requirements wholesale sales, at an average 
cost of 2.7 cents per kWh.


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


     Company Hydroelectric Power.  The Company wholly owns and operates 
eight hydroelectric generating facilities located on river systems 
within its service area, the largest of which has a generating output of 
8.8 MW.  In 1997, these plants provided 140,754 MWh of low-cost energy, 
meeting 6.9% of the Company's retail and requirements wholesale sales at 
an average cost of 4.2 cents per kWh, based on total embedded costs.  See 
"State and Federal Regulation - Licensing."


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


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


     Fuel.  During 1997, the Company's retail and requirements wholesale 
sales were provided by the following fuel sources:  46.9% from hydro 
(6.9% Company-owned, 0.1% NYPA, 36.8% Hydro-Quebec and 3.1% small power 
producers), 36.5% from nuclear, 9.2% from coal, 3.3% from wood, 0.9% 
from natural gas, 0.5% from oil, and 0.3% from wind.  The remaining 2.4% 
was purchased on a short-term basis from other utilities and through 
NEPOOL.

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

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

     The DOE contract obligates Vermont Yankee to pay a one-time fee of 
approximately $39,300,000 for disposal costs for all spent fuel 
discharged through April 7, 1983.  Although such amount has been 
collected in rates from the Vermont Yankee participants, Vermont Yankee 
has elected to defer payment of the fee to the DOE as permitted by the 
DOE contract.  The fee must be paid no later than the first delivery of 
spent nuclear fuel to the DOE.  Interest accrues on the unpaid 
obligation based on the thirteen-week Treasury Bill rate and is 
compounded quarterly.  Through 1996, Vermont Yankee accumulated 
approximately $78,000,000 in an irrevocable trust to be used exclusively 
for defeasing this obligation at some future date, provided the DOE 
complies with the terms of the aforementioned contract.

     The Company does not maintain long-term contracts for the supply of 
oil for the oil-fired peaking unit generating stations wholly owned by 
it (80 MW).  The Company did not experience difficulty in obtaining oil 
for its own units during 1997, and, while no assurance can be given, 
does not anticipate any such difficulty during 1998.  None of the 
utilities from which the Company expects to purchase oil- or gas-fired 
capacity in 1997 has advised the Company of grounds for doubt about 
maintenance of secure sources of oil and gas during the year.

     Coal for Merrimack #2 is presently being purchased under a long-
term contract from Balley Mine in western Pennsylvania and occasionally 
on the spot market from northern West Virginia and southern Pennsylvania 
sources.

     Wood for the McNeil plant is furnished to the Burlington Electric 
Department from a variety of sources under short-term contracts ranging 
from several weeks' to six months' duration.  The McNeil plant used 
249,662 tons of wood chips and mill residue and 34,629,000 cubic feet of 
gas in 1997.  The McNeil plant is forecasting consumption of wood chips 
for 1998 to be 200,000 tons and gas consumption of 136,000,000 cubic 
feet.

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


     Wind Project.  The Company's 20 years of research and development 
work in wind generation was recognized in 1993 when the Company was 
selected by the DOE and the Electric Power Research Institute (EPRI) to 
build a commercial scale wind-powered facility.  The Company was awarded 
$3,500,000 by the DOE and EPRI to provide partial funding for the wind 
project.  The overall cost of the project, located in the southern 
Vermont town of Searsburg , is estimated to be $11,000,000.  The eleven 
wind turbines have a rating of 6 MW and were commissioned July 1, 1997.

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

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

	In 1997, the plant provided 5,387 MWh, meeting 0.3% of the 
Company's retail and requirements wholesale sales.


                             ENERGY EFFICIENCY


     In 1997, the Company continued to focus its energy efficiency 
services on lost opportunity programs which encouraged customers to 
install energy efficient equipment when they are planning to replace or 
buy new equipment.  This strategy, along with careful management, has 
helped the Company to further reduce its cost-per-kilowatthour saved by 
10% below its costs in 1996.  The current cost of saving per 
kilowatthour is approximately 2 cents which is a 56% reduction in costs 
since 1992.  In 1997, the Company's energy efficiency programs saved 
8,633 MWH, 64% above targeted savings for the year.  During the past 
five years, the Company's efficiency programs have achieved a cumulative 
savings of  71,217 megawatthours.

     In 1997, the Company worked with other Vermont utilities and the 
Department to develop a set of statewide energy efficiency programs.  
This effort should reduce the cost of delivering these programs and 
provide a more standardized service to customers throughout the State. 

     In 1997, the Company spent approximately $1,900,000 on energy 
efficiency programs, approximately 1.2% of retail revenue.


     Rate Design.  The Company seeks to design rates to encourage the 
shifting of electrical use from peak hours to off-peak hours.  Since 
1976, the Company has offered optional time-of-use rates for residential 
and commercial customers.  Currently, approximately 2,500 of the 
Company's residential customers continue to be billed on the original 
1976 time-of-use rate basis.   In 1987, the Company received regulatory 
approval for a rate design that permitted it to charge prices for 
electric service that reflected as accurately as possible the cost 
burden imposed by each customer class.  The Company's rate design 
objectives are to provide a stable pricing structure and to accurately 
reflect the cost of providing electric services.  This rate structure 
helps to achieve these goals.  Since inefficient use of electricity 
increases its cost, customers who are charged prices that reflect the 
cost of providing electrical service have real incentives to follow the 
most efficient usage patterns.  Included in the VPSB's order approving 
this rate design was a requirement that the Company's largest customers 
be charged time-of-use rates on a phased-in basis by 1994.  At year end 
December 31, 1997, approximately 1,350 of the Company's largest 
customers, comprising 48% of retail revenues, continue to receive 
service on mandatory time-of-use rates.  

     In May 1994, the Company filed its current rate design with the 
VPSB.  The parties, including the Department, IBM and a low-income 
advocacy group, entered into a settlement that was approved by the VPSB 
on December 2, 1994.  Under the settlement, the revenue allocation to 
each rate class was adjusted to reflect class-by-class cost changes 
since 1987, the differential between the winter and summer rates was 
reduced, the customer charge was increased for most classes, and usage 
charges were adjusted to be closer to the associated marginal costs.

     No rate redesign has taken place since the VPSB Order issued on 
December 2, 1994.


     Dispatchable and Interruptible Service Contracts.  In 1997, the 
Company had interruptible/dispatchable power contracts with three major 
ski areas, interruptible-only contracts with five customers and 
dispatchable-only contracts with an additional twenty-four customers.  
The interruptible portion of the contracts allow the Company to control 
power supply capacity charges by reducing the Company's capacity 
requirements.  During 1997, 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.  The customer's demand during these periods is not 
considered in calculating the monthly billing.  This program enables the 
Company and the customers to benefit from load control.  The Company 
shifts load from its high cost peak periods while the customer uses 
inexpensive power at a time when its use provides maximum value.  These 
programs are available by tariff for qualifying customers.


                    CONSTRUCTION AND CAPITAL REQUIREMENTS


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

     For the period 1995-1997, internally generated funds, after payment 
of dividends, provided approximately 62% of total capital requirements 
for construction, sinking fund obligations and other requirements.  
Internally generated funds provided 129% of such requirements for 1997.  
The Company anticipates that for 1998, internally generated funds will 
provide approximately 48% of total capital requirements for regulated 
operations, the remainder to be derived from bank loans.

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


                           ENVIRONMENTAL MATTERS


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


                           UNREGULATED BUSINESSES


     The Company has had a plan of diversification into unregulated 
businesses that complements the Company's basic utility operations.  The 
diversification plan has involved the establishment of several 
subsidiaries.  For information regarding unregulated businesses, see 
Item 7. MD&A- "Future Outlook - Unregulated Businesses."



                            EXECUTIVE OFFICERS

Executive Officers of the Company as of March 27, 1998:

      Name                Age

Nancy R. Brock            42    Chief Corporate Strategic Planning 
                                Officer since March, 1998.  Prior to joining 
                                the Company, she was Chief Financial Officer 
                                of SAL, Inc., 1997; and Senior Vice President 
                                and Chief Financial Officer for the 
                                Chittenden Corporation from 1988 to 1996.

Christopher L. Dutton      49   President, Chief Executive Officer and 
                                Chairman of the Executive Committee of the 
                                Corporation since August 1997.  Vice 
                                President, Finance and Administration, Chief 
                                Financial Officer and Treasurer from 1995 to 
                                1997.  Vice President and General Counsel 
                                from 1993 to January 1995.  Vice President, 
                                General Counsel and Corporate Secretary from 
                                1989 to 1993.

Robert J. Griffin          41   Controller since October 7, 1996.  
                                Manager of General Accounting from 1990 to 
                                1996.

Richard B. Hieber          59   Senior Vice President and Chief 
                                Operating Officer since August 1997.  Vice 
                                President, Electric Operations and 
                                Engineering from 1996 to 1997.  Prior to 
                                joining the Company, he was President and 
                                Chief Executive Officer of Stone & Webster 
                                Management Consultants, Inc. from 1992 to 
                                1996 and Senior Vice President from 1991 to 
                                1992.

Donna S. Laffan            48   Corporate Secretary since December 
                                1993.  Assistant Secretary from 1986 to 1993.

John J. Lampron            53   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.

Michael H. Lipson          53   General Counsel since August 1997.  
                                Assistant General Counsel from 1990 to 1997.  
                                Prior to joining the Company, he  was a 
                                partner with Miller, Eggleston and Rosenberg 
                                Ltd.

Craig T. Myotte            43   Assistant Vice President-Engineering 
                                and Operations since 1994.  Assistant Vice 
                                President-Operations and Maintenance from 
                                1991 to 1994.

Edwin M. Norse             52   Vice President, Chief Financial Officer 
                                and Treasurer since August 1997.  Vice 
                                President and General Manager, Energy 
                                Resources and Sales from 1995 to 1997.  Vice 
                                President, Chief Financial Officer and 
                                Treasurer from 1986 to January 1995.  
                                President-Green Mountain Propane Gas Company 
                                from October 1993 to June 1996.

Walter S. Oakes            51   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.

Mary G. Powell             37   Vice President, Human Resources and 
                                Organizational Development since March, 1998.  
                                Prior to joining the Company, she was Senior 
                                Vice President, Human Resources and Senior 
                                Vice President Community Banking, Senior Vice 
                                President Human Resources Administration, and 
                                Vice president of Human Resources for KEYCORP 
                                from October 1992 to March 1998.

Stephen C. Terry           55   Senior Vice President, Corporate 
                                Development since August, 1997.  Vice 
                                President and General Manager, Retail Energy 
                                Services from 1995 to 1997.  Vice President-
                                External Affairs from 1991 to January 1995.

Jonathan H. Winer          46   President of Mountain Energy, Inc. 
                                since March 1997.  Vice President and Chief 
                                Operating Officer of Mountain Energy, Inc. 
                                from 1989 to March 1997.

Robert C. Young            60   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.

     Officers are elected by the Board of Directors of the Company, 
Mountain Energy, Inc., or Green Mountain Resources, Inc., as 
appropriate, for one-year terms and serve at the pleasure of such boards 
of directors.


ITEM 2.  PROPERTY
                             GENERATING FACILITIES

     The Company's Vermont properties are located in five areas and are 
interconnected by transmission lines of VELCO and New England Power 
Company.  The Company wholly owns and operates eight hydroelectric 
generating stations with a total nameplate rating of 36.1 MW and an 
estimated claimed capability of 35.7 MW.  It also owns two gas-turbine 
generating stations with an aggregate nameplate rating of 59.9 MW and an 
estimated aggregate claimed capability of 73.2 MW.  The Company has two 
diesel generating stations with an aggregate nameplate rating of 8.0 MW 
and an estimated aggregate claimed capability of 8.6 MW.  The Company 
has a wind generating facility with a name plate rating of 6.1 MW.

     The Company also owns 17.9% of the outstanding common stock, and is 
entitled to 17.6624% (93.8 MW of a total 531 MW) of the capacity, of 
Vermont Yankee, a 1.1% (6.8 MW of a total 620 MW) joint-ownership share 
of the Wyman #4 plant located in Maine, an 8.8% (31.0 MW of a total 352 
MW) joint-ownership share of the Stony Brook I intermediate units 
located in Massachusetts and an 11% (5.9 MW of a total 53 MW) joint-
ownership share of the J. C. McNeil wood-fired steam plant located in 
Burlington, Vermont.  See Item 1. Business - "Power Resources" for plant 
details and the table hereinafter set forth for generating facilities 
presently available.


                         TRANSMISSION AND DISTRIBUTION


     The Company had, at December 31, 1997, approximately 1.5 miles of 
115 kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4 
miles of 44 kV and 265.4 miles of 34.5 kV transmission lines.  Its 
distribution system includes about 2,399 miles of overhead lines of 
2.4 kV to 34.5 kV, and about 445 miles of underground cable of 2.4 kV to 
34.5 kV.  At such date, the Company owned approximately 153,275 kVa of 
substation transformer capacity in transmission substations, 446,050 kVa 
of substation transformer capacity in distribution substations and 
1,070,604 kVa of transformers for step-down from distribution to 
customer use.

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

     The Company also owns 29.5% of the common stock and 30% of the 
preferred stock of VELCO, which operates a high-voltage transmission 
system interconnecting electric utilities in the State of Vermont.


                              PROPERTY OWNERSHIP


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

     Transmission and distribution facilities which are not located in 
or over public highways are, with minor exceptions, located either on 
land owned in fee or pursuant to easements which, in nearly all cases, 
are perpetual.  Transmission and distribution lines located in or over 
public highways are so located pursuant to authority conferred on public 
utilities by statute, subject to regulation by state or municipal 
authorities.


                        INDENTURE OF FIRST MORTGAGE


     The Company's interests in substantially all of its properties and 
franchises are subject to the lien of the mortgage securing its First 
Mortgage Bonds.

                         GENERATING FACILITIES OWNED


     The following table gives information with respect to generating 
facilities presently available in which the Company has an ownership 
interest.  See also Item 1. Business - "Power Resources."

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

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

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

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

               Gas      Berlin, VT         Berlin #5         Oil       56.6
               Turbine  Colchester, VT     Gorge #16         Oil       16.1

               Wind     Searsburg, VT                        Wind       1.2
Jointly Owned  Steam    Vernon, VT         Vermont Yankee    Nuclear   93.8(2)
                        Yarmouth, ME       Wyman #4          Oil        7.1
                        Burlington, VT     McNeil            Wood       6.6(3)

               Combined Ludlow, MA         Stony Brook #1    Oil/Gas   31.0(2)
                                                                      _____
Total Winter Capability                                               256.3

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

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

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


                            CORPORATE HEADQUARTERS


     For a discussion of the Company's operating lease for its Corporate 
Headquarters building, see Note I-3 of Notes to Consolidated Financial 
Statements.


ITEM 3.  LEGAL PROCEEDINGS


     See the discussion Item 7. MD&A - "Environmental Matters" 
concerning a notice received by the Company in 1982 under the 
Comprehensive Environmental Response, Compensation, and Liability Act of 
1980.


ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.


     None.


                                   PART II

ITEM 5.    MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
           STOCKHOLDER MATTERS

     Outstanding shares of the Common Stock are listed and traded on the 
New York Stock Exchange under the symbol "GMP".  The following 
tabulation shows the high and low sales prices for the Common Stock on 
the New York Stock Exchange during 1997 and 1996:



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

        1997           First Quarter        25 1/4       22 5/8
                       Second Quarter       24 5/8       22 3/8
                       Third Quarter        26 1/4       18 7/8
                       Fourth Quarter       19 1/4       17 9/16

     The number of common stockholders of record as of March 11, 1998 
was 7,883.

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

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

      1996       53 cents     53 cents      53 cents     53 cents
      1997       53 cents     53 cents    27.5 cents   27.5 cents


     Dividend Policy - On September 17, 1997, the Company's Board of 
Directors announced a reduction in the quarterly dividend from $.053 per 
share to $0.275 per share on the Company's common stock.

     Historically, the Company has based its dividend policy on the 
continued validity of three assumptions:  The ability to achieve 
earnings growth, the receipt of an allowed rate of return that 
accurately reflects the Company's cost of capital, and the retention of 
its exclusive franchise.  The Company's common stock dividend payout has 
ranged from 94 to 103 percent of earnings over the past five years.  The 
Company's revised dividend policy, which incorporates a target payout 
ratio of 60 to 70 percent, reflects the greater risks facing the Company 
as a result of the changing environment of the electric utility 
industry.  This policy contemplates a target payout that is in line with 
industry trends and is comparable to that of other companies in the 
utility industry.  The policy assumes fair and appropriate ratemaking.  
However, the VPSB's recent rate Order, if unchanged, will require the 
Company to reassess the current dividend level.  See Item 7. MD&A 
"Future Outlook - Competition and Restructuring" and Note C of Notes to 
Consolidated Financial Statements for discussion of limitations on 
dividends.

<TABLE>
<CAPTION>

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

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

                                            1997         1996         1995         1994         1993
                                          ---------    ---------    ---------    ---------    ---------
<S>                                       <C>          <C>          <C>          <C>          <C>
Operating Revenues........................$179,323     $179,009     $161,544     $148,197     $147,253
Operating Expenses........................ 163,808      162,882      146,249      133,680      132,427
                                          ---------    ---------    ---------    ---------    ---------
  Operating Income........................  15,515       16,127       15,295       14,517       14,826
                                          ---------    ---------    ---------    ---------    ---------
Other Income
  AFUDC - equity..........................     357          175           27          263          273
  Other...................................   1,216        3,055        3,607        3,418        2,360
                                          ---------    ---------    ---------    ---------    ---------
    Total other income....................   1,573        3,230        3,634        3,681        2,633
                                          ---------    ---------    ---------    ---------    ---------
Interest Charges
  AFUDC - borrowed funds..................    (315)        (468)        (547)        (539)        (357)
  Other...................................   7,965        7,866        7,973        7,735        7,185
                                          ---------    ---------    ---------    ---------    ---------
    Total interest charges................   7,650        7,398        7,426        7,196        6,828
                                          ---------    ---------    ---------    ---------    ---------

Net Income................................   9,438       11,959       11,503       11,002       10,631

Dividends on Preferred Stock..............   1,433        1,010          771          794          811
                                          ---------    ---------    ---------    ---------    ---------
Net Income Applicable to Common Stock.....  $8,005      $10,949      $10,732      $10,208       $9,820
                                          =========    =========    =========    =========    =========
Common Stock Data
  Earnings per share......................   $1.57        $2.22        $2.26        $2.23        $2.20
  Cash dividends declared per share.......   $1.61        $2.12        $2.12        $2.12        $2.11
  Weighted average shares outstanding.....   5,112        4,933        4,747        4,588        4,457



Financial Condition as of December 31
-------------------------------------
                                            1997         1996         1995         1994         1993
                                          ---------    ---------    ---------    ---------    ---------

Assets

 Utility Plant, Net.......................$196,720     $189,853     $181,999     $175,987     $171,411
 Other Investments........................  21,997       20,634       20,248       20,751       22,528
 Current Assets...........................  29,125       30,901       30,216       28,798       26,215
 Deferred Charges.........................  35,831       43,224       42,951       35,659       33,893
 Non-Utility Assets.......................  42,060       39,927       37,868       33,416       28,626
                                          ---------    ---------    ---------    ---------    ---------
  Total Assets............................$325,733     $324,539     $313,282     $294,611     $282,673
                                          =========    =========    =========    =========    =========

Capitalization and Liabilities

 Common Stock Equity......................$114,377     $111,554     $106,408     $101,319      $97,149
 Redeemable Cumulative Preferred Stock....  17,735       19,310        8,930        9,135        9,385
 Long-Term Debt, Less Current Maturities..  93,200       94,900       91,134       74,967       79,800
 Capital Lease Obligation.................   8,342        9,006        9,778       10,278       11,029
 Curent Liabilities.......................  25,286       21,037       32,629       40,441       37,925
 Deferred Credits and Other...............  53,723       54,968       52,041       49,434       40,214
 Non-Utility Liabilities..................  13,070       13,764       12,362        9,037        7,171
                                          ---------    ---------    ---------    ---------    ---------
  Total Capitalization and Liabilities....$325,733     $324,539     $313,282     $294,611     $282,673
                                          =========    =========    =========    =========    =========

</TABLE>

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

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


                             EARNINGS SUMMARY


     Earnings per average share of common stock in 1997 were $1.57 as 
compared with $2.22 in 1996 and $2.26 in 1995. The 1997 earnings 
represent an earned return on average common equity of 7.1 percent.  The 
earned return on average common equity in 1996 was 10.0 percent and 10.3 
percent in 1995.

     The 1997 decrease in earnings was primarily due to diminished 
results by two of the Company's wholly-owned subsidiaries.  Mountain 
Energy, Inc., the Company's subsidiary that has invested in energy 
generation and energy and wastewater efficiency projects, earned $1.2 
million less in 1997 than in 1996, primarily due to operating losses 
incurred by Micronair, LLC, a company in which Mountain Energy acquired 
a 71 percent interest in 1997, and a decline in rates paid for power 
generated by one of the California wind facilities in which it has 
invested.  Green Mountain Resources Inc.'s (GMRI) loss in 1997 was $1.4 
million greater than the loss in 1996 due primarily to the development 
costs of its investment in Green Mountain Energy Resources L.L.C. 
(GMER), the retail energy company in which the Company sold a 67 percent 
interest to an affiliate of the Sam Wyly family during the third quarter 
of 1997.  Subsequently, the Wyly family affiliate invested an additional 
$10 million in GMER, increasing its ownership percentage to 74.3 
percent.

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

                              FUTURE OUTLOOK


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

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

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

     Regulatory and legislative authorities at the federal level and 
among states across the country, including Vermont, are considering how 
to facilitate competition for electricity sales at the wholesale and 
retail levels.  On October 24, 1994, the Vermont Public Service Board 
(VPSB) and the Vermont Department of Public Service (the Department) 
convened a "Roundtable on Competition and the Electric Industry," 
consisting of representatives of affected parties.  On July 17, 1995, a 
subgroup of the Roundtable agreed on a set of 14 principles intended to 
guide the debate in Vermont concerning competition.  These principles, 
among other things, call for exploration of the potential for retail 
competition, honoring of past utility commitments incurred under 
regulation, protection for low income customers, and continued 
exploration of renewable resources, energy efficiency and environmental 
protections.

     On September 14, 1995, Governor Dean of Vermont announced his 
desire to provide for competition and a restructuring of the electric 
utility industry.  The Governor's announcement included proposed 
legislative adoption of restructuring principles, a VPSB proceeding to 
address the issue, the submission by Vermont electric utilities of 
detailed plans by May 1, 1996, and implementation of restructuring by 
the beginning of 1998.  In response to a Department petition, the VPSB 
opened a proceeding on utility industry restructuring by order dated 
October 17, 1995.  On December 29, 1995, the Company released its 
proposed restructuring plan, calling for corporate separation into a 
regulated company for transmission and distribution functions and an 
unregulated company for generation and sales functions.

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

     The Final Report indicated that Vermont investor-owned utilities 
may be required to divide their competitive retail and regulated 
distribution and transmission functions into separate corporate 
subsidiaries in order to achieve a functional separation of regulated 
and unregulated businesses, and envisioned competition for all customer 
classes to be completed by the end of 1998.  In view of this potential 
change in structure as well as the unknown relative level of competition 
each corporation may face, the Company cannot predict the future cost or 
availability of capital for the new subsidiary corporations, except to 
the extent that it has already created a functionally-separate retail 
marketing affiliate, GMER.  See Management's Discussion and Analysis of 
Financial Condition and Results of Operations - "Unregulated Businesses 
- Green Mountain Resources, Inc."  Furthermore, most of the assets of 
the Company are encumbered by a lien of the Company's First Mortgage 
Indenture.  The Company cannot predict with certainty at this time the 
cost and feasibility of obtaining approval from the existing 
bondholders, to the extent that it is determined that such approvals are 
necessary, in order to achieve functional separation.

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

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

     In early 1997, the Company, Central Vermont Public Service 
Corporation (CVPS), representatives of the Governor of Vermont and the 
Department negotiated a Memorandum of Understanding (MOU) that outlined 
agreed-upon positions among the parties relative to the recovery of 
stranded costs, distribution company rates, corporate unbundling and 
societal benefit programs.  

     In early April 1997, the Vermont Senate passed Senate Bill No. 62 
(S. 62), an electric utility restructuring bill, which requires passage 
by the Vermont House of Representatives and signature by the Governor 
before becoming law. This bill was opposed by the Company and other 
utilities in Vermont in the legislative session that ended in June 1997.  
S. 62 establishes several goals, including the conflicting objectives 
that stranded costs be shared equally between utilities and customers 
and that the continuing financial integrity of the utility be preserved.  

     Under S. 62, full retail competition in Vermont would have started 
in October 1998 and the VPSB was given considerable discretion to weigh 
various potentially conflicting objectives, including the two objectives 
set forth above, in deciding the extent to which and manner under which 
a utility can recover stranded costs.  S. 62 also provides: (1) that 
utilities must either divest unregulated enterprises or "functionally 
separate" them from regulated business activities; (2) an incentive for 
the early closing and decommissioning of the Vermont Yankee nuclear 
power plant; (3) that any retail electricity provider in Vermont shall 
have "ownership" of sufficient tradable renewable energy credits as 
defined in S. 62; (4) that the VPSB may order performance-based 
regulation for distribution functions if it finds that departure from 
cost-of-service regulation is in the public interest; (5) for the 
provision of out placement service and severance pay for utility 
employees adversely affected by restructuring, with such costs shared 
equally by the utility and its customers; and (6) that if a utility has 
received some above-market cost recovery and then the utility is 
acquired, the VPSB is to determine how much, if at all, the value of the 
acquired company was enhanced by the recovery of above-market costs and 
thereafter determine how the enhanced value should be shared equitably 
between the acquired utility's shareholders and customers.

     The Company has strenuously opposed the enactment of S. 62 into law 
principally because its stranded cost sharing provisions would 
jeopardize the Company's financial viability. The ability of the Company 
to apply accounting standards that recognize the economic effect of rate 
regulation and record regulatory assets and liabilities would be 
significantly challenged by the proposed enactment of S. 62.  In the 
event that the criteria for applying Statement of Financial Accounting 
Standards No. 71, Accounting for the Effects of Certain Types of 
Regulation (SFAS 71) are no longer met, the Company would be required to 
write-off a material amount of its regulatory assets.  More 
significantly, the Company would be required to record its best estimate 
of the loss resulting from the equal sharing between the Company and its 
customers of the portion of stranded costs represented by above-market 
purchase power obligations.  These obligations result from contracts for 
power entered into by the Company to meet its obligation to serve its 
retail customers.  Such losses could impact the Company's credit rating, 
dividend policy and financial viability.

     In mid-April 1997, the Vermont House of Representatives indicated 
through its Speaker that there was insufficient time in the legislative 
session (which ended in June 1997) to act upon a utility restructuring 
bill.  S. 62 was not considered by the Vermont House of Representatives 
in the 1997 legislative session. However, along with other proposed 
bills, it is being considered by the House of Representatives during the 
1998 session.

     On July 28, 1997, the Speaker of the House named an eleven member 
non-standing committee to consider reform of the Vermont Electric 
Utility Regulatory System.  In mid-October 1997, the Chair of the 
Committee reported that the Committee did not recommend that the Vermont 
Legislature consider legislation during the 1998 session to allow 
customer choice at this time.  Nevertheless, proposed electric utility-
related legislation, which the House has taken no action on, consists of 
the following:  (1) H. 663, which would create performance-based 
regulation, but not provide for competitive retail sales of electricity; 
(2) H. 701, which would mirror most of the terms of the MOU but would 
not provide reasonable stranded cost recovery for the Company; and (3) 
H. 675, which also would mirror most of the terms of the MOU but would 
confer jurisdiction on the VPSB to provide for stranded cost recovery as 
a ratemaking function.

     There is no assurance that any restructuring legislation will be 
enacted by the Vermont General Assembly in its 1998 session that is 
scheduled to adjourn mid-April 1998 or, if legislation is enacted, that 
it will be consistent with the terms of the Final Report.  The Company 
has stated its position that if legislation is enacted that threatens 
the Company's financial integrity, it will pursue all remedies available 
to it under law. 


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

     The largest category of the Company's stranded costs are future 
costs under long-term power purchase contracts.  The Company intends to 
pursue compliance with the steps outlined in the Final Report and 
aggressively to pursue mitigation efforts in order to maximize its 
recovery of these costs.  The magnitude of stranded costs for the 
Company is largely dependent upon the future market price of power.  The 
Company has discussed various market price scenarios with interested 
parties for the purpose of identifying stranded costs.  Preliminary 
market price assumptions, which are likely to change, have resulted in 
estimates of the Company's stranded costs of between $265 million and 
$1.1 billion.

     If retail competition is implemented in Vermont, there will be an 
impact on the Company's revenues from electricity sales.  However, the 
Company is unable to predict at this time the extent of this impact.  
GMER, the Company's affiliate, is expected to participate in the 
residential and small commercial and industrial customer market in 
Vermont at such time when restructuring occurs.  The Company has agreed 
not to compete against GMER in the retail energy business for a period 
of seven years.  The Company, itself or through another marketing 
affiliate, may elect to endeavor to retain and attract larger commercial 
customers in a competitive retail environment, but neither its relative 
prospects or the margins it will realize on any such sales can be 
estimated at this time.

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

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

     The Company believes that the provisions of the Final Report, if 
implemented, would meet the criteria for continuing application of SFAS 
71 as to those costs for which recovery is permitted.  S. 62, however, 
would not meet the criteria for the continuing application of SFAS 71. 
Under SFAS 5, Accounting for Contingencies, the enactment of S. 62 or 
other restructuring legislation or order containing comparable 
provisions on stranded cost recovery would also require the Company to 
immediately estimate and record losses, on an undiscounted basis, for 
any discretionary above market power purchase contracts and other costs 
which are not probable of recovery from customers, to the extent that 
those costs are estimable. The Company is unable to predict what form 
enacted legislation will take, and it cannot predict if or to what 
extent SFAS 71 will continue to be applicable in the future.  Members of 
the staff of the Securities and Exchange Commission have raised 
questions concerning the continued applicability of SFAS 71 to certain 
other electric utilities facing restructuring. 

     On July 24, 1997, the Emerging Issues Task Force of the Financial 
Accounting Standards Board indicated that utilities should immediately 
discontinue application of SFAS 71 for those business segments which 
will become unregulated, if the utility has a final plan in place for 
transition to competition.  To the extent that the discontinued segment 
has assets secured in arrangements such as a CTC, those assets would 
continue to be accounted for under SFAS 71.  

     SFAS 121, Accounting for the Impairment of Long Lived Assets, which 
was implemented by the Company on January 1, 1996, requires that any 
assets, including regulatory assets, that are no longer probable of 
recovery through future revenues be revalued based upon future cash 
flows.  SFAS 121 requires that a rate-regulated enterprise recognize an 
impairment loss for regulatory assets which are no longer probable of 
recovery.  As of December 31, 1997, based upon the regulatory 
environment within which the Company currently operates, no impairment 
loss was incurred.  Competitive influences or regulatory developments 
may impact this status in the future.

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

     For a discussion of a major risk factor arising from Vermont 
regulatory treatment of the Company's recent rate filing, see Note I of 
the Notes to Consolidated Financial Statements.


     Unregulated Businesses -- The following is a discussion of the 
Company's unregulated enterprises.

     Mountain Energy, Inc., which has invested in energy generation and 
energy and waste water efficiency projects, earned $142,000 in 1997, 
compared to  net income of $1.32 million in 1996.  The 1997 decrease in 
earnings was due primarily to start-up operating losses incurred by 
Micronair, LLC. and a decline in rates paid for power generated by one 
of its wind facilities in California.  The 1997 results contributed 3 
cents of earnings per share to the Company's consolidated results as 
compared to 27 cents in 1996.

     Since its formation in 1989, Mountain Energy has invested more than 
$20 million in ten operating energy projects, including two California 
wind projects, hydroelectric projects in California and New Hampshire, a 
gas cogeneration facility in Illinois and energy efficiency 
installations in Maine, New York, New Jersey, Massachusetts and Hawaii.

     In 1997, Mountain Energy broadened its investment portfolio by 
acquiring an initial 35 percent ownership interest in Micronair, LLC, 
which owns certain patent rights to a wastewater treatment system that 
provides an innovative and efficient solution to the biosolids disposal 
issues facing the United States.  The Micronairr system enhances both 
the processing and energy efficiency at wastewater facilities, virtually 
eliminating biosolids as a byproduct.  Mountain Energy increased its 
ownership interest in Micronair to 71 percent at the end of 1997.

     Green Mountain Propane Gas Company (GMPG), which sells propane gas 
at retail in Vermont and New Hampshire, experienced a $136,000 loss in 
1997 as compared to a $335,000 loss in 1996.  The loss in 1997 was due 
primarily to a decrease in propane sales caused by warmer than normal 
weather in early 1997.  In 1997 and 1996, the losses incurred by GMPG 
reduced the Company's consolidated earnings by 3 cents and 7 cents, 
respectively, per share of common stock.  On February 20, 1998, GMPG and 
the Company entered into a sales agreement with VGS Propane, LLC for the 
sale of all GMPG assets.  The sale was completed on March 16, 1998.  See 
Note I of the Notes to Consolidated Financial Statements.

     The loss in 1996 was due primarily to strong competition, low 
margins due to significant wholesale price fluctuations, increased 
producer pipeline restrictions beginning in November 1996 and warmer 
than normal weather in December 1996.

     The Company's unregulated rental water heater business earned 
$381,000 in 1997, a slight increase from 1996's net income of $379,000.  
The 1997 and 1996 results contributed 7 and 8 cents of earnings, 
respectively, per share to the Company's consolidated results.

     Green Mountain Resources, Inc., which was formed in April 1996 to 
explore opportunities in competitive retail energy markets, experienced 
a loss of $2.0 million in 1997 that was $1.4 million greater than its 
loss of $579,000 in 1996, due primarily to the development costs of its 
investment in GMER.

     On August 6, 1997, the Company and the Sam Wyly family announced 
that their affiliates will jointly own GMER, a Delaware limited 
liability company of which GMRI was the sole owner.  GMER is competing 
in the emerging consumer retail energy market starting in California 
where customers are able to choose their electricity supplier as of 
March 31, 1998.  GMER has created retail brands of electricity and 
natural gas that will be sold to consumers who care about the 
environment in competitive markets across the nation.  An affiliate of 
the Sam Wyly family, Green Funding I, L.L.C. (the Investor), entered 
into an Operating Agreement with GMRI governing the ownership of GMER.  
Pursuant to the terms of the Operating Agreement, the Investor initially 
agreed to invest up to $30 million in GMER in exchange for an equity 
interest of 67 percent while GMRI contributed certain assets and 
business development concepts in exchange for an equity interest of 33 
percent in GMER.  Subsequently, the Investor agreed to invest an 
additional $10 million in GMER, increasing its ownership percentage to 
74.3 percent.  These ownership interests may be reduced further if GMER 
warrants and options issued to GMER management and consultants are 
exercised.  GMRI's ownership percentage of GMER will be further diluted 
if the Investor and/or third parties contribute additional capital to 
GMER and GMRI does not make pro rata additional capital contributions at 
such time.  GMRI received a payment of $4 million from GMER at the 
closing as reimbursement for certain development expenses incurred.  
Pursuant to the terms of the Operating Agreement, funds provided by the 
Investor will be used to pay future GMER development expenses and 
operating costs.  GMRI is not obligated to fund future development 
costs, and the Operating Agreement provides that GMRI will not be 
allocated operating losses from GMER, thus limiting the Company's 
shareholders' future financial risk while preserving their opportunity 
to participate in the success of GMER.  In addition, the Company and the 
Investor have agreed that neither the Company nor the Investor will 
compete against GMER in the retail energy business for a period of seven 
years.

     Douglas G. Hyde, a director, President and Chief Executive Officer 
of the Company, resigned those positions with the Company effective 
August 6, 1997 in order to become the President and Chief Executive 
Officer of GMER.  Thomas C. Boucher, Vice President, Energy Resources 
and Planning; Kevin W. Hartley, Vice President, Marketing; Karen K. 
O'Neill, Vice President, Organizational Development; and Peter H. 
Zamore, General Counsel of the Company, resigned those offices in order 
to join Mr. Hyde as members of the GMER management team.  

     In 1996, GMRI, together with subsidiaries of Hydro-Quebec, 
Consolidated Natural Gas Corporation and Noverco, Inc., participated in 
the retail sales of energy in pilot programs in New Hampshire and 
Massachusetts through Green Mountain Energy Partners L.L.C. (GMEP).  In 
1997, Consolidated Natural Gas and Noverco withdrew from the pilot 
program.  GMRI has concluded its participation in the Massachusetts 
pilot, but will continue participating through May 31, 1998 in the New 
Hampshire pilot program which was designed to test the viability of 
retail electric competition by providing customer choice in the purchase 
of electricity.  In January 1998, Hydro-Quebec withdrew from the pilot 
program.


RESULTS OF OPERATIONS


Operating Revenues and MWh Sales--Operating revenues and megawatthour 
(MWh) sales for the years 1997, 1996 and 1995 consisted of:

                                         1997         1996          1995
                                         ----         ----          ----
 
                                              (Dollars in Thousands)
Operating Revenues:
   Retail . . . . . . . . . . . . .   $ 158,790    $ 154,916     $ 140,676 
   Sales for Resale . . . . . . . .      17,847       20,667        17,541 
   Other  . . . . . . . . . . . . .       2,686        3,426         3,327 
                                      ---------    ---------     ---------
Total Operating Revenues  . . . . .   $ 179,323	   $ 179,009     $ 161,544 
                                      =========    ---------     ---------
 Megawatthour Sales:
   Retail . . . . . . . . . . . . .   1,806,580    1,775,711     1,723,117 
   Sales for Resale . . . . . . . .     588,525      701,835       620,655 
                                      ---------    ---------     ---------
Total Megawatthour sales      . . .   2,395,105    2,477,546     2,343,772 
                                      =========    =========     =========

Average Number of Customers:
   Residential  . . . . . . . . . .      70,671       70,198        69,659 
   Commercial & Industrial  . . . .      12,012       11,853        11,736 
   Other  . . . . . . . . . . . . .          75           75            76 
                                         ------       ------        ------
Total Customers . . . . . . . . . .      82,758       82,126        81,471 
                                         ======       ======        ======

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

                                                    1996          1995
                                                     to            to 
                                                    1997          1996
                                                    ----          ----
                                                       (In Thousands)
Operating Revenues:
   Retail Rates . . . . . . . . . . . . . . .    	$ 1,161        $ 9,654 
   Retail Sales Volume  . . . . . . . . . . .       2,713          4,586 
   Resales and Other Revenues . . . . . . . .      (3,560)         3,225 
                                                   -------       -------
Increase in Operating Revenues  . . . . . . .      $  314        $17,465
                                                   =======       =======

     In 1997, total electricity sales decreased 3.3 percent due 
principally to a decrease in wholesale sales caused by a reduction in 
low-margin, off-system sales.  Sales of electricity to residential 
customers was negatively impacted by winter temperatures in the first 
quarter of 1997 that were substantially warmer than normal.  

     Total operating revenues were virtually unchanged in 1997.  Total 
retail revenues increased 2.5 percent in 1997 primarily due to an 
increase in sales of electricity to the Company's small commercial and 
industrial customers resulting from modest customer growth and an 
increase in sales to IBM.  The increase in retail revenues was nearly 
offset by a 13.6 percent decrease in wholesale revenues caused by a 
reduction in low-margin, off-system sales, which had a minimal impact on 
earnings and a 21.6 percent decrease in other operating revenues caused 
by a one-time adjustment in 1996 to account for higher charges under a 
transmission and interconnection agreement between CVPS and the Company.

     In 1996, total electricity sales increased 5.7 percent due 
principally to an increase in electricity consumption by the Company's 
commercial and industrial customers and regional market conditions that 
allowed the Company to buy electricity and to resell it to other 
utilities at prices slightly higher than the purchase price. Total 
operating revenues increased 10.8 percent in 1996 primarily due to 
retail rate increases of 9.25 percent and 5.25 percent that went into 
effect in June 1995 and June 1996, respectively, and the increase in 
electricity sales mentioned above. Total retail revenues increased 10.1 
percent in 1996 primarily due to the retail rate increases mentioned 
above. Wholesale revenues increased 17.8 percent in 1996 primarily due 
to the regional market conditions mentioned above.

     IBM, the Company's single largest customer, operates manufacturing 
facilities in Essex Junction, Vermont. IBM's electricity requirements 
for its main plant and an adjacent plant accounted for 14.0, 13.2 and 
12.9 percent of the Company's operating revenues in 1997, 1996 and 1995, 
respectively. No other retail customer accounted for more than one 
percent of the Company's revenue.

     In February 1995, the Company and IBM entered into an Economic 
Development Agreement (EDA I) that governed the prices to be paid by IBM 
at its Essex Junction facility for incremental electric usage during 
1995, 1996 and 1997.  The contract, intended to promote growth in IBM's 
operations and create jobs in the Company's service area, applied only 
to that portion of IBM's load that exceeded its 1994 consumption level.  
Most of IBM's electric usage is billed under the Company's tariff rate.  
The EDA I price, although lower than the Company's tariff rate, exceeded 
the Company's marginal costs of providing this incremental electric 
service to IBM.  The VPSB approved the EDA I in June 1995.

     Prior to the expiration of the EDA I on December 31, 1997, the 
Company and IBM negotiated a new, similar EDA (EDA II).  The agreement 
has most of the features of the EDA I, including use of the 1994 base to 
determine incremental load and pricing above the Company's marginal 
costs.  A separate pricing provision applies to load above 1997 levels.  
The Company expects the VPSB to approve EDA II as presented in early 
1998.  The Company believes that the EDA I and EDA II benefit the 
Company because the agreements encourage the incremental purchase of 
electricity by IBM at a price above the Company's marginal cost of 
providing such incremental service.

     Power Supply Expenses -- Power supply expenses constituted 61.3 
percent, 61.5 percent and 60.1 percent of total operating expenses for 
the years 1997, 1996 and 1995, respectively. These expenses increased by 
$120,000 (0.1 percent) in 1997 and by $12.3 million (14.0 percent) in 
1996.

     Total power supply expenses were slightly higher in 1997, although 
the cost of several individual sources were significantly different from 
their costs in 1996.  Power supply expenses from Vermont Yankee 
increased 7.3 percent in 1997 primarily due to the deferral in 1996 and 
the amortization in 1997 of costs associated with a scheduled refueling 
outage.  Company-owned generation expenses increased 60.0 percent in 
1997 primarily due to the increased usage of Company-owned plants 
necessitated by the outage of certain nuclear power plants in the 
region.  These increases were nearly offset by a 6.2 percent decrease in 
power supply expenses from other resources primarily due to the 
recognition of $8 million received from Hydro-Quebec under a Memorandum 
of Understanding entered into in 1996 (as described below) consistent 
with a VPSB accounting order dated December 31, 1996.  (This accounting 
treatment was subsequently changed.  See below.)

     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 $4 million (in 1994 dollars) worth of research and development 
work from Hydro-Quebec over the four-year period, and made a $6.5 
million (in 1994 dollars) cash payment to Hydro-Quebec in 1995.  Hydro-
Quebec retains the right to curtail annual energy deliveries by 10 
percent up to five times, over the 2000 to 2015 period, if documented 
drought conditions exist in Quebec.

     Under an arrangement negotiated in January 1996, the Company 
received cash payments from Hydro-Quebec of $3.0 million in 1996 and 
$1.1 million in 1997.  Consistent with allowed ratemaking treatment, the 
$3.0 million payment reduced purchase power expense by $1.75 million in 
1996; the balance of the payment reduced power costs in 1997.  The $1.1 
million payment reduces purchase power expense ratably over the period 
beginning June 1997 and ending May 1998.  An Order issued by the VPSB in 
March 1998 requires the Company instead to amortize the $1.1 million 
over a four-year period.  (See Note I of the Notes to Consolidated 
Financial Statements.)

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

     Under a separate agreement executed on December 5, 1997, Hydro-
Quebec provided a cash payment of $8.0 million to the Company in 1997.  
In return for this payment, the Company is providing Hydro-Quebec with 
the choice of selecting one of two alternatives by April 1, 1998, 
described below:
Alternative A:  For the period commencing November 1, 1997 and effective 
through the remaining term of the 1987 Contract, which expires in 2015, 
Hydro-Quebec can exercise an option to purchase up to 105,000 MWh on an 
annual basis, at energy prices established in accordance with the 1987 
Contract, for an amount of energy equivalent to the Company's firm 
capacity entitlements in the 1987 Contract.  The cumulative amount of 
energy purchased over the remaining term of the 1987 Contract shall not 
exceed 1,900,000 MWh.  Hydro-Quebec may not exercise its annual rights 
to purchase power in the amounts specified under an arrangement made in 
November 1996 during those years in which Hydro-Quebec exercises its 
rights to curtail energy deliveries in accordance with the July 1994 
Agreement. 
Alternative B:  For the period commencing November 1, 1997 and effective 
through the remaining term of the 1987 Contract, Hydro-Quebec can 
exercise an option to purchase up to 52,500 MWh on an annual basis, at 
energy prices established in accordance with the 1987 Contract, for an 
amount of energy equivalent to the Company's firm capacity entitlements 
in the 1987 Contract.  The cumulative amount of energy purchased over 
the remaining term of the 1987 Contract shall not exceed 950,000 MWh.  
Unlike Alternative A, Hydro-Quebec's option to curtail energy deliveries 
pursuant to the July 1994 Agreement can be exercised in addition to the 
purchase option under Alternative B.  Finally, for the period commencing 
January 1, 1998 and effective though the remaining term of the 1987 
Contract under Alternative B, Hydro-Quebec can exercise an option on an 
annual basis to purchase up to 600,000 MWh at the 1987 Contract energy 
price. Hydro-Quebec can purchase no more than 200,000 MWh in any given 
year.  Under modifications agreed to by Hydro-Quebec and the Company, 
Hydro-Quebec has until April 1, 1998 to elect either Alternative A or B.  
(See Note K of the Notes to Consolidated Financial Statements).

     Notwithstanding the December 31, 1996 accounting order, the VPSB 
ordered a change in accounting treatment in an Order released on March 
2, 1998.  The Company intends to appeal or request reconsideration of 
this decision.  (See Note I of the Notes to Consolidated Financial 
Statements.)

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

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


     Other Operating Expenses -- Other operating expenses decreased 4.7 
percent in 1997 primarily due to an increase in work performed on behalf 
of GMRI, effectively reducing payroll and overhead expenses for the 
Company.  Additionally, the organizational changes attributable to the 
creation of GMER resulted in fewer Company employees, causing a 
reduction in payroll expense.

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

     Transmission Expenses - Transmission expenses increased 2.7 percent 
in 1997 primarily due to higher tariffs under a new operating agreement 
with New England Power Company.

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

     In August 1996, the Company received a bill totaling approximately 
$1.9 million from CVPS for service at certain transmission 
interconnections that are the subject of a 1993 transmission and 
interconnection agreement between the Company and CVPS.  The bill 
covered the period October 1993 through June 1996.  In September 1996, 
the Company charged approximately $700,000 of the CVPS invoice to 
transmission rent expense and deferred the remaining charges.  The 
Company paid the CVPS billing but sought relief under the agreement's 
arbitration clause on the ground, among others, that substantial 
portions of the bill, inclusive of interest, were not properly 
chargeable under the agreement.

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

     On December 31, 1996, the Company received an accounting order from 
the VPSB permitting amounts deferred under the transmission and 
interconnection agreement to be expensed over the remaining eleven years 
of the agreement subject to review in future rate cases.  

     In February 1998, following arbitration, the Company received 
$428,000 from CVPS, in resolution of each of the parties' claims under 
this agreement.  Management sought to recover in rates (by inclusion in 
ratebase) the 13-month average balance of the charges from CVPS net of 
amounts recovered in prior rate orders of the costs of transmission 
under this agreement, revenues that the Company received under the 
agreement for providing service to CVPS, and the approximate amount of 
the arbitration award.  The amount sought in the rate case was 
approximately $747,000.  Management received ratemaking treatment for 
these costs in an Order released by the VPSB on March 2, 1998. 


     Maintenance Expenses - Maintenance expenses increased 7.2 percent 
in 1997 and 6.0 percent in 1996 primarily due to scheduled increases in 
plant maintenance.


     Depreciation and Amortization - Depreciation and amortization 
expenses were virtually unchanged in 1997.

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


     Income Taxes -- The effective federal income tax rates for the 
years 1997, 1996 and 1995 were 32.8 percent, 27.2 percent and 25.3 
percent, respectively.

     The increase in 1997 income taxes is primarily due to an increase 
in taxable income, an increase in the combined federal and state income 
tax rate and an increase in the reserve for unaudited income tax years.

     Other Income - Other income decreased 51.3 percent in 1997 
primarily due to diminished results by two of the Company's wholly-owned 
subsidiaries.  Mountain Energy, Inc., the Company's subsidiary that 
invests in energy generation and energy and waste water efficiency 
projects, earned $1.2 million less in 1997 primarily due to start-up 
operating losses incurred by Micronair LLC, a company in which Mountain 
Energy bought a 71 percent interest in 1997, and a decline in rates paid 
for power generated by one of the California wind facilities in which it 
has invested.  GMRI's loss in 1997 was $1.4 million greater than the 
loss in 1996 due primarily to the development costs of its investment in 
GMER, the retail energy company in which the Company sold a controlling 
interest to an affiliate of the Sam Wyly family during the third quarter 
of 1997.

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


     Dividends on Preferred Stock - Dividends on preferred stock 
increased 41.8 percent in 1997 and 31.0 percent in 1996 primarily due to 
the issuance of 120,000 shares of the Company's 7.32 percent, Class E, 
Series 1 preferred stock in October 1996.


     Interest Charges - Interest charges increased 3.4 percent in 1997 
primarily due to an increase in long-term interest related to the sale 
of $10 million and $4 million of the Company's first mortgage bonds in 
November and December 1996, respectively.  This increase was partially 
offset by a decrease in interest charges related to a lower amount of 
short-term debt outstanding during the year.

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


                            TRANSMISSION ISSUES


     Federal Open Access Tariff Orders -- On April 24, 1996, the Federal 
Energy Regulatory Commission (FERC) issued Orders 888 and 889 which, 
among other things, required the filing of open access transmission 
tariffs by electric utilities, and the functional separation by 
utilities of their transmission operations from power marketing 
operations.  Order 888 also supports the full recovery of legitimate and 
verifiable wholesale power costs previously incurred under federal or 
state regulation.

     On July 9, 1996, the Company filed with the FERC the non-
discriminatory open access tariffs required by Order 888 and subsequent 
modifications to the tariff.  The tariff defined the Company's 
transmission system to include subtransmission facilities owned by the 
Company including Phase I and Phase II facilities and the Company's 
entitlement to facilities owned by VELCO.  The Company's tariffs 
included charges related to the use of the VELCO transmission system by 
customers.  Other Vermont utilities required to make filings with the 
FERC under Order 888 followed the same course of action.  On July 17, 
1997, the FERC approved the Company's Open Access Transmission Tariff, 
and on August 30, 1997 the Company filed its compliance refund report.

     In accordance with Order 889, the Company has also functionally 
separated its transmission operations and filed with the FERC a code of 
conduct for its transmission operations.  The Company is currently 
revising the Code of Conduct in response to a FERC Order respecting it 
issued on November 3, 1997.  The Company does not anticipate any 
material adverse effects or loss of wholesale customers due to the FERC 
orders mentioned above.

     Proposed NEPOOL Transmission Tariff -- Under an allocation 
agreement among VELCO, Northeast Utilities and New England Power 
Corporation (the Three-Party Agreement), VELCO currently has 14 percent 
of the capacity of transmission facilities between New England, New York 
and Canada.  VELCO's capacity for such transmission facilities is 
allocated among Vermont electric utilities, including the Company.  The 
Company's ability to use these delivery paths has been adversely 
impacted by a proposed NEPOOL open access tariff (NEPOOL Fourth 
Supplement to Amendment 33) on file with the FERC.  Under the tariff as 
filed, transmission capability or transfer capacity between New York and 
New England will no longer be allocated in a manner consistent with the 
Three-Party Agreement.  Instead, rights to the transfer capacity will be 
made more generally available to the market subject to certain 
contingencies related to NEPOOL generation availability and accounting 
for the delivery of various grandfathered contracts.  Efforts by the 
Company and other VELCO members to negotiate with NEPOOL participants 
for the preservation of rights to deliver long-term firm contracts 
necessary to serve native load on these delivery routes were 
unsuccessful.  Consequently, on November 18, 1997 VELCO filed with the 
FERC on behalf of the Vermont utilities (including the Company) a motion 
to intervene and seeking summary judgment with respect to the NEPOOL 
filing of the Fourth Supplement filing or the VELCO filing.  The Company 
and other Vermont utilities have argued inter alia that the Fourth 
Supplement was a proposal to terminate the Vermont utilities existing 
and future rights under the Three Party Agreement allocating the New 
York and New England transmission ties and, specifically, the PV20 tie 
with the New York Power Authority (NYPA).  


                           ENVIRONMENTAL MATTERS


     Public concern for the environment has resulted in increased 
government regulation of the licensing and operation of electric 
generation, transmission and distribution facilities.  The electric 
industry typically uses or generates a range of potentially hazardous 
products in its operations.  The Company must meet various land, water, 
air and aesthetic requirements as administered by local, state and 
federal regulatory agencies.  The Company maintains an environmental 
compliance and monitoring program that includes employee training, 
regular inspection of Company facilities, research and development 
projects, waste handling and spill prevention procedures and other 
activities.  Subject to developments concerning the Pine Street Barge 
Canal site described below, the Company believes that it is in 
substantial compliance with such requirements, and no material 
complaints concerning compliance by the Company with present 
environmental protection regulations are outstanding.

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

     Since 1994, the EPA has established a coordinating council, with 
representatives of the PRPs, environmental and community groups, the 
City of Burlington and the State of Vermont presided over by a neutral 
facilitator.  The council has determined, by consensus, what additional 
studies were appropriate for the site, and is addressing the question of 
additional response activities.  The EPA, the State of Vermont and other 
parties have entered into two consent orders for completion of 
appropriate studies.  Work is continuing under the second of those 
orders.  Most recently, on September 23, 1997, the council reached 
tentative agreement on a key component of the proposed remedy for the 
Pine Street site, namely, placement of an underwater sand/silt cap on 
areas of the canal and wetland sediments, combined with long-term 
monitoring to ensure effectiveness of the cap and to ensure that 
groundwater does not reach Lake Champlain, adjacent to the site.  The 
EPA has estimated the costs of this remedy at between $6 to $10 million, 
subject to change.  In addition, the council is exploring supplemental 
projects in and around the site and Burlington as part of a larger plan 
to improve environmental conditions in the vicinity.

     On December 1, 1994, the Company and two other PRPs, New England 
Electric System (NEES) and Vermont Gas Systems (VGS), entered into a 
confidential settlement agreement with the State of Vermont, the City of 
Burlington and nearly all other landowner PRPs under which, subject to 
certain qualifications, the liability of those landowner PRPs for future 
Superfund response costs would be limited and specified.  On December 1, 
1994, the Company entered into a confidential agreement with VGS 
compromising contribution and cost recovery claims of each party and 
contractual indemnity claims of the Company arising from the 1964 sale 
of the manufactured gas plant to VGS.  In March 1996, the Company and 
NEES entered into a confidential agreement compromising past and future 
contribution and cost recovery claims of both parties relating to 
response costs.  In December 1997, the Company and Southern Union Co. 
entered into a confidential settlement agreement compromising past and 
future contribution and cost recovery claims of both parties relating to 
response costs.  The Company has received payment of the full amount 
provided for in the settlement.  In January 1998, the Company and UGI 
Utilities, Inc. entered into a confidential settlement agreement 
compromising past and future contribution and cost recovery claims of 
both parties relating to response costs.  The Company has received 
payment of the initial amount provided for in the settlement.  The EPA 
has advised the Company that it has incurred substantial unrecovered 
response sums at the site which, together with interest the EPA alleges 
may be payable, amount to approximately $11.0 million.  The Company has 
not yet received a formal demand for these sums.  The Company will 
vigorously dispute the EPA's recovery of such costs, which include 
substantial sums for studies and other activities that were not 
reasonably necessary and were not undertaken consistent with legal and 
regulatory requirements.  Further, the Company's agreements with certain 
PRP's will reduce the extent to which it may bear these past response 
costs.  Consequently, the Company is not able at this time to predict 
with certainty whether, or the extent to which, it will be required to 
pay such past response costs.

     In December 1991, the Company brought suit against eight previous 
insurers seeking recovery of unrecovered past costs, cost of defense and 
indemnity against future liabilities associated with environmental 
problems at the site.  Discovery in the case, which was previously 
subject to a stay, is complete. The Company has reached confidential 
settlements with the defendants in this litigation; several such 
settlements are in the final stages of documentation.

     The Company has deferred amounts received from third parties, under 
confidential settlements, pending resolution of the Company's ultimate 
liability with respect to the site and rate recognition of that 
liability.  

     Although the cost of the coordinating council's tentative 
remediation plan, described above, is not expected to approach the EPA's 
earlier estimate of remediation costs for its original clean-up plan, 
the current EPA estimate is subject to change. Since the Company 
believes it may prevail with respect to some of the EPA's unrecovered 
response costs, the Company is unable to predict at this time the 
magnitude of any liability resulting from potential claims for the costs 
to investigate and remediate the site, or the likely disposition or 
magnitude of claims the Company may have against others, including its 
insurers, except to the extent described above.

     Through rate cases filed in 1991, 1993, 1994, and 1995, the Company 
has sought and received recovery for ongoing expenses associated with 
the Pine Street Barge Canal site.  Specifically, the Company proposed 
rate recognition of its unrecovered expenditures incurred between 
January 1, 1991 and June 30, 1995 (in the total of approximately $8.7 
million) for technical consultants and legal assistance in connection 
with the EPA's enforcement action at the site and insurance litigation.  
While reserving the right to argue in the future about the 
appropriateness of rate recovery for the Pine Street Barge Canal site 
related costs, the Company and the Department  reached agreements in 
these cases that the full amount of the Pine Street Barge Canal site 
costs reflected in those rate cases should be recovered in rates.  The 
Company's rates approved by the VPSB in those proceedings reflected the 
Pine Street Barge Canal site related expenditures referred to above.  
The Company proposed in the rate filing made on June 16, 1997 recovery 
of an additional $3.0 million in such expenditures.

     In an Order released March 2, 1998, the VPSB suspended the 
amortization of expenditures associated with the Pine Street Barge Canal 
site pending further proceedings.  Although it did not eliminate the 
rate base deferral of these expenditures, or make any specific order in 
this regard, the VPSB indicated that it was inclined to agree with other 
parties in the case that the ultimate costs associated with the Pine 
Street Barge Canal site, taking into account recoveries from insurance 
carriers and other PRP's, should be "shared" between customers and 
shareholders of the Company.

     As of December 31, 1997, total expenditures for the Pine Street 
Barge Canal site were $13.4 million, inclusive of the $11.7 million 
referred to above.

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

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


                      LIQUIDITY AND CAPITAL RESOURCES


     Construction -- The Company's capital requirements result from the 
need to construct facilities or to invest in programs to meet 
anticipated customer demand for electric service.  If restructuring does 
occur, the Company will reassess its capital expenditures for generation 
and other projects and the terms of financing thereof.

Capital expenditures over the past three years and projected for 
1998 are as follows:

                                                                 Total Net
Actual Generation Transmission Distribution Conservation Other  Expenditures
------ ---------- ------------ ------------ ------------ -----  ------------
(Dollars in thousands and net of AFUDC and Customer Advances For Construction)
1995    $2,696      $1,067        $8,935        $4,152    $2,969   $19,819
1996     6,287*        528         8,422         3,090     3,511    21,838
1997     3,462*        986         9,680         2,094     3,291    19,513
Forecasted 
1998    $1,283        $501        $8,681	       $2,500    $9,221   $22,186

*Includes $4.978 and $2.868 million for wind project in 1996 and 1997, 
respectively.


     Rates -- On June 16, 1997, the Company filed a request with the 
VPSB to increase retail rates by 16.7 percent ($26 million in additional 
annual revenues) and the target return on common equity from 11.25 
percent to 13 percent.  Initial hearings before the VPSB began November 
3, 1997.  The VPSB allowed the intervention of various other parties. 

     In August 1997, several groups, including the Vermont Public 
Interest Research Group (VPIRG), demanded that the VPSB appoint an 
independent counsel to advocate against recovery of Hydro-Quebec power 
costs by the Company.  The VPSB issued an order appointing an 
"independent investigator," described as a person or persons who will 
perform a rigorous and impartial analysis of the Company's actions with 
respect to its power supply options, including the Hydro-Quebec 
contract.  On November 7, 1997, the VPSB selected a firm, MSB Energy 
Associates, Inc. (MSB) to undertake the tasks.

     In testimony filed with the VPSB on October 17, 1997, the 
Department asked the VPSB to find the Company's negotiation, execution 
and decision to "lock in" the contract with Hydro-Quebec to be imprudent 
and uneconomic.  The Department had supported the contract in the period 
1989-1991 after completing its own analysis, based on substantially the 
same information that was available to the Company.  The VPSB in 1990, 
1991, 1992 and 1994 issued orders that determined the contract to be 
needed to supply electricity to Vermont customers, economically 
beneficial to the State and an appropriate part of the Company's 
legally-required least-cost integrated resource plan.

     On October 31, 1997, the Company filed with the VPSB Objections and 
a Motion to Strike relating to the Hydro Quebec contract testimony and 
requested that the VPSB schedule oral argument on the motion prior to 
November 17, 1997.  The grounds for the motion were that the VPSB had 
previously decided the issues sought to be relitigated.  The VPSB heard 
argument on the motion on November 14, 1997 and ruled against the 
Company, but granted the Company leave to renew the motion.  The Company 
did so in its post-hearing briefs.  

     In its testimony, submitted in late 1997, MSB was critical of the 
Company's power supply decision-making in 1991, and recommended a steep 
disallowance of the Hydro-Quebec power costs, in excess of $10 million 
per year.  During the rebuttal phase of the rate case, the Company 
showed that MSB was not independent and did not present "rigorous 
analysis" as the VPSB had ordered.  MSB's presentation adopted the 
testimony of the Department's principal witnesses as well as theories 
espoused by a professional expert retained by IBM and MSB failed to 
present its own analysis showing that, based on any information 
possessed or available to the Company during the critical summer and 
fall of 1991, the long-term Hydro-Quebec contract was uneconomic.

     The Company filed a motion to strike the MSB testimony and to 
impose sanctions upon MSB for submitting testimony without any good 
faith factual or legal basis.  The VPSB struck several portions of MSB's 
testimony forming the core of their arguments on imprudence, based on 
legal or contract interpretation, on the ground that MSB had no 
qualifications to present this testimony.

     Briefs in the case on non-Hydro-Quebec issues were filed January 
30, 1998; the Hydro-Quebec briefs were filed on February 2; all reply 
briefs were filed on February 6.  In its final submissions, the Company 
reduced the requested increase to 14.4 percent ($22 million in 
additional annual revenues) due to changed estimates of costs to be 
incurred in the rate year.  

     On March 2, 1998, the VPSB released a decision in the rate case.  
The Order granted a $5.6 million increase in annual revenue in response 
to the Company's request for a $22 million increase in annual revenue.  
The Company is exploring all legal and regulatory remedies open to it to 
challenge the VPSB's decision.  The VPSB's ruling, if not changed, would 
have a significant adverse impact on the Company's reported financial 
condition and 1998 results of operations and, depending on future 
proceedings to be conducted by the VPSB, could impact the Company's 
credit rating, dividend policy and financial viability.  See Note I of 
the Notes to Consolidated Financial Statements for a complete 
discussion.


     Dividend Policy -- On September 17, 1997, the Company's Board of 
Directors announced a reduction in the quarterly dividend from $0.53 per 
share to $0.275 per share on the Company's common stock.

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

     The Company's common stock dividend payout has ranged from 94 to 
103 percent of earnings over the past five years.  The Company's revised 
dividend policy, which incorporates a target payout ratio of 60 to 70 
percent, reflects the greater risks facing the Company as a result of 
the changing environment of the electric utility industry.  This policy 
contemplates a target payout that is in line with industry trends and is 
comparable to that of other companies in the utility industry. The 
policy assumes fair and appropriate ratemaking.  However, the VPSB's 
recent rate Order, if unchanged, will require the Company to reassess 
the current dividend level. 


     Financing and Capitalization -- For the period 1995 through 1997, 
internally generated funds, after payment of dividends, provided 
approximately 62 percent of total capital requirements for construction, 
sinking funds and other requirements.  The Company anticipates that for 
1998, internally generated funds will provide approximately 48 percent 
of total capital requirements for regulated operations.

     At December 31, 1997, the Company's capitalization consisted of 
50.4 percent common equity, 41.8 percent long-term debt and 7.8 percent 
preferred equity.  The Company has a comprehensive capital plan to 
increase the equity component of its capital structure.

     In May 1997, the rating of the Company's first mortgage bonds by 
Standard & Poor's was upgraded from "BBB+" to "A-," reflecting Standard 
& Poor's revised assessment of the ultimate recovery risk of the senior 
secured debt of utilities.  The Company's corporate credit rating 
remains at "BBB+."  The preferred stock rating remains at "BBB."  In 
March 1998, Standard & Poor's placed the Company's credit ratings on 
Creditwatch with negative implications in reaction to what they 
characterize as an adverse ruling by the VPSB regarding the Company's 
rate increase request.

     The rating of the Company's first mortgage bonds by Duff & Phelps 
remains at "BBB+."  The ratings of the Company's preferred stock remains 
at "BBB."  In March 1998, Duff & Phelps placed the Company's credit 
ratings on Rating Watch - Down in reaction to what they characterize as 
a negative outcome in the Company's rate increase request decided by the 
VPSB.

     The rating of the Company's first mortgage bonds by Moody's 
Investment Services remains at "Baa2."  The rating of the Company's 
preferred stock remains at "baa3."  In March 1998, Moody's changed its 
rating outlook for the Company to negative and indicated the Company's 
credit ratings were pressured in reaction to what they characterize as a 
negative order from the VPSB regarding the Company's rate increase 
request.

     See Note F of the Notes to Consolidated Financial Statements for a 
discussion of the bank credit facilities available to the Company.  See 
Note I of the Notes to Consolidated Financial Statements for a 
discussion of the VPSB rate order.


     Year 2000 Computer Compliance - The Company utilizes software and 
related technologies throughout its businesses that will be affected by 
the date change in the year 2000.  The Company is in the process of 
implementing new customer service and financial systems which are year 
2000 compliant.  An internal study is currently underway to determine 
the full scope and related costs to insure that the Company's systems 
continue to meet its internal needs and those of its customers.  
Maintenance or modification costs will be expensed as incurred, while 
the costs of new software will be capitalized and amortized over the 
software's useful life.  These expenditures may be significant and 
continue through the year 2000.

     The Company expects to have achieved compliance with year 2000 
requirements for its financial and operating systems by June 30, 1999.  
Failure to comply by January 1, 2000 would have a material adverse 
effect on the Company's operations.


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

                             MANAGEMENT CHANGES


     The Company's Board of Directors elected Christopher L. Dutton as 
President and Chief Executive Officer and a director of the Company 
effective August 6, 1997.  Mr. Dutton has served as Chief Financial 
Officer of the Company since 1995.  He joined the Company in 1984 and 
served as Vice President and General Counsel before being named Chief 
Financial Officer of the Company. 

     On October 6,1997, the Company's Board of Directors elected the 
following officers: Richard B. Hieber, Senior Vice President and Chief 
Operating Officer; Michael H. Lipson, General Counsel; Edwin M. Norse, 
Vice President and Chief Financial Officer and Treasurer; and Stephen C. 
Terry, Senior Vice President, Corporate Development.  Jonathan H. Winer 
will continue to serve as President of the Company's subsidiary, 
Mountain Energy, Inc., and will assume new responsibilities as part of 
the Company's senior management.

     On February 9, 1998, the Company's Board of Directors elected the 
following officers:  Mary G. Powell, Vice President Human Resources and 
Organizational Development, and Nancy R. Brock, Chief Corporate 
Strategic Planning Officer.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                      GREEN MOUNTAIN POWER CORPORATION
          INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES

                                                                        Page
Financial Statements

Consolidated Statements of Income
    For the Years Ended December 31, 1997, 1996 and 1995                  43

Consolidated Statements of Cash Flows For the
    Years Ended December 31, 1997, 1996 and 1995                          44

Consolidated Balance Sheets as of
    December 31, 1997 and 1996                                           45-46

Consolidated Capitalization Data as of
    December 31, 1997 and 1996                                            47

Notes to Consolidated Financial Statements                               48-69

Quarterly Financial Information                                          59-60

Report of Independent Public Accountants                                  70

Schedules

For the Years Ended December 31, 1997, 1996 and 1995:

    II  Valuation and Qualifying Accounts and Reserves                    71

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

Consents and Reports of Independent Public Accountants

             Arthur Andersen LLP                                       70 & 82

<TABLE>
<CAPTION>

                            CONSOLIDATED STATEMENTS OF INCOME

        GREEN MOUNTAIN POWER CORPORATION   For the Years Ended December 31




                                                                      1997                1996                1995
                                                                -----------------    ---------------     ---------------
                                                                         (In thousands, except amounts per share)

<S>                                                                     <C>                <C>                 <C>
Operating Revenues..............................................        $179,323           $179,009            $161,544
                                                                -----------------    ---------------     ---------------
Operating Expenses
  Power Supply 
     Vermont Yankee Nuclear Power Corporation...................          32,817             30,596              30,222
     Company-owned generation...................................           5,327              3,330               3,786
     Purchases from others......................................          62,222             66,320              53,915
  Other operating...............................................          16,780             17,615              18,120
  Transmission.................................................           11,122             10,833               9,874
  Maintenance...................................................           4,785              4,463               4,210
  Depreciation and amortization.................................          16,359             16,280              14,116
  Taxes other than income.......................................           7,205              6,982               6,428
  Income taxes..................................................           7,191              6,463               5,578
                                                                -----------------    ---------------     ---------------
     Total operating expenses...................................         163,808            162,882             146,249
                                                                -----------------    ---------------     ---------------
       Operating Income.........................................          15,515             16,127              15,295
                                                                -----------------    ---------------     ---------------

Other Income
  Equity in earnings of affiliates and 
     non-utility operations.....................................             427              2,880               3,513
  Allowance for equity funds used during construction...........             357                175                  27
  Other income and deductions, net..............................             789                175                  94
                                                                -----------------    ---------------     ---------------
    Total other income..........................................           1,573              3,230               3,634
                                                                -----------------    ---------------     ---------------
      Income before interest charges............................          17,088             19,357              18,929
                                                                -----------------    ---------------     ---------------

Interest Charges
  Long-term debt................................................           7,274              6,872               6,546
  Other.........................................................             691                994               1,427
  Allowance for borrowed funds used during 
     construction............................................               (315)              (468)               (547)
                                                                -----------------    ---------------     ---------------
    Total interest charges......................................           7,650              7,398               7,426
                                                                -----------------    ---------------     ---------------
Net Income......................................................           9,438             11,959              11,503

Dividends on preferred stock....................................           1,433              1,010                 771
                                                                -----------------    ---------------     ---------------
Net Income Applicable to Common Stock...........................          $8,005            $10,949             $10,732
                                                                =================    ===============     ===============

Common Stock Data
  Earnings per share............................................           $1.57              $2.22               $2.26

  Cash dividends declared per share.............................           $1.61              $2.12               $2.12

  Weighted average shares outstanding...........................           5,112              4,933               4,747


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

</TABLE>


<TABLE>
<CAPTION>

                          CONSOLIDATED BALANCE SHEETS

                   GREEN MOUNTAIN POWER CORPORATION    December 31


                                                         1997               1996
                                                       ---------          ---------
                                                              (In thousands)
ASSETS

<S>                                                    <C>                <C>
Utility Plant 
    Utility plant, at original cost....................$265,441           $248,135
    Less accumulated depreciation......................  87,689             81,286
                                                       ---------          ---------
      Net utility plant................................ 177,752            166,849
    Property under capital lease.......................   8,342              9,006
    Construction work in progress......................  10,626             13,998
                                                       ---------          ---------
      Total utility plant, net......................... 196,720            189,853
                                                       ---------          ---------
Other Investments
    Associated companies, at equity ...................  15,860             15,769
    Other investments .................................   6,137              4,865
                                                       ---------          ---------
      Total other investments..........................  21,997             20,634
                                                       ---------          ---------
Current Assets
    Cash...............................................     118                238
    Accounts receivable, customers and others,
      less allowance for doubtful accounts.............  17,365             17,733
    Accrued utility revenues...........................   6,505              6,662
    Fuel, materials and supplies, at average cost......   3,261              3,621
    Prepayments........................................   1,563              2,206
    Other..............................................     313                441
                                                       ---------          ---------
      Total current assets.............................  29,125             30,901
                                                       ---------          ---------
Deferred Charges
    Demand side management programs....................  13,692             16,409
    Environmental proceedings costs....................   8,441              7,991
    Purchased power costs..............................   4,283              9,163
    Other..............................................   9,415              9,661
                                                       ---------          ---------
      Total deferred charges...........................  35,831             43,224
                                                       ---------          ---------
Non-Utility
    Cash and cash equivalents..........................     153                511
    Other current assets...............................  11,501              3,979
    Property and equipment.............................  10,784             11,226
    Intangible assets..................................   2,116              2,555
    Equity investment in energy-related businesses.....  12,824             12,494
    Other assets.......................................   4,682              9,162
                                                       ---------          ---------
      Total non-utility assets.........................  42,060             39,927
                                                       ---------          ---------
Total Assets...........................................$325,733           $324,539
                                                       =========          =========

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



                   GREEN MOUNTAIN POWER CORPORATION    December 31

                                                         1997               1996
                                                       ---------          ---------
                                                              (In thousands)

CAPITALIZATION AND LIABILITIES

Capitalization (See Capitalization Data)
    Common Stock Equity 
      Common stock..................................... $17,318            $16,790
      Additional paid-in capital.......................  70,720             68,226
      Retained earnings................................  26,717             26,916
      Treasury stock, at cost..........................    (378)              (378)
                                                       ---------          ---------
        Total common stock equity...................... 114,377            111,554
    Redeemable cumulative preferred stock..............  17,735             19,310
    Long-term debt, less current maturities ...........  93,200             94,900
                                                       ---------          ---------
        Total capitalization........................... 225,312            225,764
                                                       ---------          ---------

Capital Lease Obligation ..............................   8,342              9,006
                                                       ---------          ---------

Current Liabilities
    Current maturuties of long-term debt...............   1,700              3,034
    Short-term debt....................................   2,616              1,016
    Accounts payable, trade, and accrued liabilities...   6,828              6,140
    Accounts payable to associated companies...........   7,661              6,621
    Dividends declared.................................     350                381
    Customer deposits..................................     721                689
    Taxes accrued......................................   2,843                986
    Interest accrued...................................   1,311              1,382
    Other..............................................   1,256                788
                                                       ---------          ---------
        Total current liabilities......................  25,286             21,037
                                                       ---------          ---------
Deferred Credits
    Accumulated deferred income taxes..................  23,501             26,726
    Unamortized investment tax credits.................   4,542              4,825
    Other..............................................  25,680             23,417
                                                       ---------          ---------
        Total deferred credits.........................  53,723             54,968
                                                       ---------          ---------

Non-Utility
    Current liabilities................................   1,119              1,752
    Other liabilities..................................  11,951             12,012
                                                       ---------          ---------
        Total non-utility liabilities..................  13,070             13,764
                                                       ---------          ---------
Total Capitalization and Liabilities...................$325,733           $324,539
                                                       =========          =========

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

</TABLE>


<TABLE>
<CAPTION>

                                    CONSOLIDATED STATEMENTS OF CASH FLOWS

                     GREEN MOUNTAIN POWER CORPORATION  For the Years Ended December 31


                                                                         1997          1996          1995
                                                                       ---------     ---------     ---------
                                                                                  (In thousands)
<S>                                                                      <C>          <C>           <C>
Operating Activities:
  Net Income...........................................................  $9,438       $11,959       $11,503
  Adjustments to reconcile net income to net cash
    provided by operating activities:
      Depreciation and amortization....................................  16,359        16,280        14,116
      Dividends from associated companies less equity income...........     (90)          254           660
      Allowance for funds used during construction.....................    (672)         (643)         (574)
      Deferred purchased power costs...................................    (331)       (5,917)      (12,935)
      Amortization of purchased power costs............................   5,212         5,187         6,036
      Deferred income taxes............................................  (2,715)        1,937         3,715
      Amortization of investment tax credits...........................    (282)         (282)         (283)
      Environmental proceedings costs, net.............................  (2,123)       (1,720)       (1,351)
      Conservation expenditures........................................  (2,411)       (3,207)       (3,960)
      Changes in:
        Accounts receivable............................................     368           347        (2,841)
        Accrued utility revenues.......................................     156          (139)         (510)
        Fuel, materials and supplies...................................     359          (309)            2
        Prepayments and other current assets...........................  (6,749)         (354)        1,562
        Accounts payable...............................................   1,728           221         2,191
        Taxes accrued..................................................   1,856           415          (871)
        Interest accrued...............................................     (71)         (465)         (106)
        Other current liabilities......................................    (164)        1,065           (22)
      Other............................................................   6,635         1,738           (95)
                                                                       ---------     ---------     ---------
    Net cash provided by operating activities..........................  26,503        26,367        16,237
                                                                       ---------     ---------     ---------

Investing Activities:
    Construction expenditures.......................................... (16,409)      (17,541)      (15,314)
    Investment in non-utility property.................................     218        (2,203)       (6,121)
                                                                       ---------     ---------     ---------
      Net cash used in investing activities............................ (16,191)      (19,744)      (21,435)
                                                                       ---------     ---------     ---------
Financing Activities:
    Issuance of preferred stock........................................    --          12,000          --
    Reduction in preferred stock.......................................  (1,575)       (1,620)         (205)
    Issuance of common stock...........................................   3,023         4,642         4,404
    Short-term debt, net...............................................   1,600        (7,400)      (11,799)
    Issuance of long-term debt.........................................    --          14,000        25,917
    Reduction in long-term debt........................................  (4,201)      (16,201)       (4,833)
    Cash dividends.....................................................  (9,637)      (11,455)      (10,818)
                                                                       ---------     ---------     ---------
      Net cash provided by (used in) financing activities.............. (10,790)       (6,034)        2,666
                                                                       ---------     ---------     ---------

    Net increase (decrease) in cash and cash equivalents...............    (478)          589        (2,532)
    Cash and cash equivalents at beginning of year.....................     749           160         2,692
                                                                       ---------     ---------     ---------
Cash and Cash Equivalents at End of Year...............................    $271          $749          $160
                                                                       =========     =========     =========

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

</TABLE>


<TABLE>
<CAPTION>

                                            CONSOLIDATED CAPITALIZATION DATA

                                            GREEN MOUNTAIN POWER CORPORATION  December 31


                                                                                    Issued and Outstanding
CAPITAL STOCK                                                      Authorized        1997         1996         1997         1996
                                                                   -----------    ----------   ----------    ---------    ---------
                                                                                                                 (In thousands)

<S>                                                                <C>            <C>          <C>            <C>          <C>   
Common Stock,$3.33 1/3 par value (Note C).......................   10,000,000     5,195,432    5,037,143      $17,318      $16,790
                                                                                                             =========    =========
     -----------------------------------------------------------------------------------------------------------------

                                                                                         Outstanding
                                                        Authorized   Issued          1997         1996         1997         1996
                                                        ---------- -----------    ----------   ----------    ---------    ---------
                                                                                                                 (In thousands)
<S>                                                         <C>        <C>            <C>          <C>           <C>          <C>
Redeemable Cumulative Preferred Stock,
 $100 par value (Note D)
   4.75%,Class B, redeemable at
     $101 per share.....................................    15,000     15,000         2,700        2,850         $270         $285
   7%,Class C, redeemable at
     $101 per share.....................................    15,000     15,000         4,650        4,650          465          465
   9.375%,Class D,Series 1,
     redeemable at $101 per share.......................    40,000     40,000         8,000        9,600          800          960
   8.625%,Class D,Series 3,
     redeemable at $101.919 per share...................    70,000     70,000        42,000       56,000        4,200        5,600
   7.32%,Class E,Series 1,..............................   200,000    120,000       120,000      120,000       12,000       12,000
                                                                                                             ---------    ---------
Total Preferred Stock...................................                                                      $17,735      $19,310
                                                                                                             =========    =========


LONG-TERM DEBT (Note E)                                                                                        1997         1996
                                                                                                             ---------    ---------
                                                                                                                 (In thousands)

First Mortgage Bonds
  6.84% Series due 1997......................................................................................$   --         $1,334
  7% Series due 1998.........................................................................................   3,000        3,000
  5.71% Series due 2000......................................................................................   5,000        5,000
  6.21% Series due 2001......................................................................................   8,000        8,000
  6.29% Series due 2002......................................................................................   8,000        8,000
  6.41% Series due 2003......................................................................................   8,000        8,000
  10.0% Series due 2004 - Cash sinking fund,$1,700,000
      annually...............................................................................................  11,900       13,600
  7.05% Series due 2006......................................................................................   4,000        4,000
  7.18% Series due 2006......................................................................................  10,000       10,000
  6.7% Series due 2018.......................................................................................  15,000       15,000
  9.64% Series due 2020......................................................................................   9,000        9,000
  8.65% Series due 2022 - Cash sinking fund,commences 2012...................................................  13,000       13,000
                                                                                                             ---------    ---------
Total Long-term Debt Outstanding.............................................................................  94,900       97,934
  Less Current Maturities (due within one year)..............................................................   1,700        3,034
                                                                                                             ---------    ---------
Total Long-term Debt, Net.................................................................................... $93,200      $94,900
                                                                                                             =========    =========

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

</TABLE>

Notes to Consolidated Financial Statements


                       A. SIGNIFICANT ACCOUNTING POLICIES

     1.  The Company.  Green Mountain Power Corporation (the Company) is 
an investor-owned energy services company located in Vermont that serves 
one-quarter of its population.  The most significant portion of the 
Company's net income is derived from its regulated electric utility 
operation, which purchases and generates electric power and distributes 
it to 83,200 retail and wholesale customers.  Two of the Company's 
wholly-owned subsidiaries (which are not regulated by the Vermont Public 
Service Board (VPSB)) are Green Mountain Propane Gas Company (GMPG), 
which supplies propane to 10,000 customers in Vermont and New Hampshire, 
and Mountain Energy, Inc., which has invested in energy generation and 
energy and waste water efficiency projects across the United States.  In 
1996, the Company's wholly-owned, unregulated subsidiary, Green Mountain 
Resources, Inc. (GMRI), was created to participate in the emerging 
retail energy market.  The results of these subsidiaries, the Company's 
unregulated rental water heater program and its other unregulated 
wholly-owned subsidiaries (GMP Real Estate Corporation and Lease-Elec, 
Inc.) are included in earnings of affiliates and non-utility operations 
in the Other Income section of the Consolidated Statements of Income.  
Summarized financial information is as follows:

                                           For the years ended December 31,
                                                   1997         1996
                                                   ----         ----
                                                     (In thousands)
   Revenues  . . . . . . . . . . . . . . .       $11,842      $11,997
   Expenses. . . . . . . . . . . . . . . .        13,439       11,207
                                                 --------     -------
   Net Income  . . . . . . . . . . . . . .       $(1,597)     $   790
                                                 ========     =======

     In 1997, the Company and an affiliate of the Sam Wyly family 
announced that they will jointly own Green Mountain Energy Resources 
L.L.C. (GMER), a Delaware limited liability company in which GMRI was 
the sole owner.  GMER is competing in the emerging retail energy market 
starting in California where customers are able to choose their 
electricity supplier as of March 31, 1998.  See Management's Discussion 
and Analysis of Financial Condition and Results of Operations - Future 
Outlook - Unregulated Businesses for a complete discussion.

     The Company carries its investments in various associated companies 
-- Vermont Yankee Nuclear Power Corporation (Vermont Yankee), Vermont 
Electric Power Company, Inc. (VELCO), New England Hydro-Transmission 
Corporation, and New England Hydro-Transmission Electric Company -- at 
equity.


     2. Basis of Presentation  The Company's utility operations, 
including accounting records, rates, operations and certain other 
practices of its electric utility business, are subject to the 
regulatory authority of the Federal Energy Regulatory Commission (FERC) 
and the VPSB.

     The accompanying consolidated financial statements conform to 
generally accepted accounting principles applicable to rate-regulated 
enterprises in accordance with Statement of Financial Accounting 
Standards (SFAS) 71, Accounting for Certain Types of Regulation.  Under 
SFAS 71, the Company is permitted to account for certain transactions in 
accordance with permitted regulatory treatment.  As such, regulators may 
permit incurred costs, typically treated as expenses, to be deferred and 
recovered in future revenues.  Conditions that give rise to the 
discontinuance of SFAS 71 include (1) increasing competition that 
restricts the Company's ability to establish prices to recover specific 
costs, and (2) a change in the manner in which rates are set by 
regulators from cost-based regulation to another form of regulation.  In 
the event that the Company no longer meets the criteria under SFAS 71, 
the Company would be required to write off related regulatory assets and 
liabilities.

     SFAS 121, Accounting for the Impairment of Long Lived Assets, which 
became effective for the Company January 1, 1996, requires that any 
assets, including regulatory assets, which are no longer probable of 
recovery through future revenues, be revalued based upon future cash 
flows.  SFAS 121 requires that a rate-regulated enterprise recognize an 
impairment loss for regulatory assets which are no longer probable of 
recovery.  As of December 31, 1997, based upon the regulatory 
environment within which the Company currently operates, no impairment 
loss need be recorded under SFAS 121.  Competitive influences or 
regulatory developments may impact this status in the future.  See 
Management's Discussion and Analysis of Financial Condition and Results 
of Operations for a discussion of electric utility restructuring which 
may impact the Company's application of SFAS 71 and 121, and Note I of 
the Notes to Consolidated Financial Statements.


     3. Statements of Cash Flows.  The following amounts of interest 
(net of amounts capitalized) and income taxes were paid for the years 
ending December 31:
                                                1997        1996       1995 
                                                ----        ----       ----
                                                       (In thousands)
   Interest . . . . . . . . . . . . . . . .     $7,800      $8,104     $7,940 
   Income Taxes (Net of refunds)  . . . . .      5,853       3,727      2,949 


     4. Utility Plant.  The cost of plant additions includes all 
construction-related direct labor and materials, as well as indirect 
construction costs, including the cost of money (Allowance for Funds 
Used During Construction or AFUDC).  The costs of renewals and 
betterments of property units are capitalized.  The costs of 
maintenance, repairs and replacements of minor property items are 
charged to maintenance expense.  The costs of units of property removed 
from service, net of removal costs and salvage, are charged to 
accumulated depreciation.


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

     The annual depreciation provision was approximately 3.6 percent of 
total depreciable property at the beginning of each year 1997, 1996 and 
1995.


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


     7. Deferred Charges.  In a manner consistent with authorized or 
expected ratemaking treatment, the Company defers and amortizes certain 
replacement power, maintenance and other costs associated with the 
Vermont Yankee nuclear plant.  In addition, the Company accrues and 
amortizes other replacement power expenses to reflect more accurately 
its cost of service to better match revenues and expenses consistent 
with regulatory treatment.  

     The Company defers and amortizes costs associated with its 
investment in the demand side management program.

     At December 31, 1997, other deferred charges totaled $9.4 million, 
consisting of repair costs for the Essex and Vergennes hydroelectric 
facilities, regulatory deferrals of storm damages, rights-of-way 
maintenance, regulatory proceedings expenses, unamortized debt expense, 
preliminary survey and investigation charges, transmission 
interconnection charges and various other projects and deferrals.


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

     In March 1997, the Financial Accounting Standards Board issued a 
new accounting standard, Statement of Financial Accounting Standards  
No. 128, Earnings per Share (SFAS 128).  SFAS 128, effective for 
financial statements issued for annual periods ending after December 15, 
1997, replaces the definition of primary earnings per share, calculated 
in accordance with the provisions of APB 15, with a new calculation, 
basic earnings per share.  Fully diluted earnings per share, now called 
diluted earnings per share, is still required.  Since the Company has 
not issued any potentially dilutive securities, both calculations are 
the same.


     9. Major Customers.  The Company had one major retail customer, 
IBM, metered at two locations, that accounted for 14.0, 13.2 and 
12.9 percent of operating revenues in 1997, 1996 and 1995, respectively.


     10. Pension and Retirement Plans.  The Company has a defined 
benefit pension plan covering substantially all of its employees.  The 
retirement benefits are based on the employees' level of compensation 
and length of service.  The Company's policy is to fund all accrued 
pension costs.  The Company records annual expense based on amounts 
funded in accordance with methods approved in the rate-setting process.

Net pension costs reflect the following components and assumptions:
                                                      1997     	1996     1995
                                                      ----      ----     ----
                                                       (Dollars in thousands)
Service cost-benefits earned during the period  .    $  720   $  689   $  687
Interest cost on projected benefit obligations  .     2,069    1,912    1,671
Actual return on plan assets  . . . . . . . . . .    (6,339)  (4,383)  (6,447)
Net amortization and deferral . . . . . . . . . .     3,432    1,756    4,232
Effect of voluntary retirement program  . . . . .       ---      416      765
Adjustment due to actions of regulator  . . . . .       126     (366)    (878)
                                                     ------   ------   -------
Net periodic pension cost funded and recognized .    $    8   $   24   $   30 
                                                     ======   ======   =======

Assumptions used to determine pension costs and the related benefit 
obligation in 1997, 1996 and 1995 were:
   Discount rate . . . . . . . . . . . . . . . .     	 7.25%    8.0%     8.0%
   Rate of increase in future compensation levels    	 4.5%     5.0%     5.0% 
   Expected long-term rate of return on assets .     	 9.0%     9.0%     9.0% 


The following table sets forth the plan's funded status as of December 
31:
                                                 1997       1996       1995
                                                 ----       ----       ---- 
                                                        (In thousands)
Actuarial present value of benefit obligations:
   Accumulated benefit obligations,
     including vested benefits of $24,231,
     $21,146 and $19,107, respectively . . . . 	($25,717)  ($21,376) ($19,431)
                                                =========  ========= =========
   Projected benefit obligations for
     service rendered to date  . .  . . . . . .	($28,630)  ($25,615) ($21,974)
Plan assets at fair value  . . . . . . . . . .    35,773     31,286    28,685 
                                                ---------  --------- ---------
Assets in excess of projected
   benefit obligations . . . . . . . . . . . .    	7,143      5,671     6,711 
Unrecognized net gain from past
   experience different from that assumed  . .    (5,962)    (4,734)   (5,188)
Prior service cost not yet recognized in net
   periodic pension cost . . . . . . . . . . .     1,247      1,474     1,506 
Unrecognized net asset at transition
   being recognized over 16.47 years . . . . .    (1,249)    (1,477)   (1,706)
Adjustment due to actions of regulator . . . .    (1,179)      (934)   (1,323)
                                                 --------   --------   -------
Prepaid pension cost included in other assets    $   ---   	$   ---    $  --- 
                                                 ========   ========   =======

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

     The Company also has a supplemental pension plan for certain 
employees.  Pension costs for the years ended December 31, 1997, 1996 
and 1995 were $456,000, $494,000 and $397,000, respectively, under this 
plan.  This plan is funded in part through insurance contracts.


     11. Postretirement Health Care Benefits.  The Company provides 
certain health care benefits for retired employees and their dependents.  
Employees become eligible for these benefits if they reach normal 
retirement age while working for the Company.  The Company accrues the 
cost of these benefits during the service life of covered employees.

     Accrued postretirement health care expenses are recovered in rates 
if those expenses are funded.  In order to maximize the tax deductible 
contributions that are allowed under IRS regulations, the Company 
amended its pension plan to establish a 401-h sub-account and separate 
VEBA trusts for its union and non-union employees.  The plan assets 
consist primarily of cash equivalent funds, fixed income securities and 
equity securities.

     Net postretirement benefits costs reflect the following components 
and assumptions:
                                                  1997      1996       1995   
                                                  ----      ----       ----
                                                        (In thousands)
Accumulated postretirement benefit obligation:
   Current retirees . . . . . . . . . . . .   ($ 6,412)  ($ 4,563)  ($ 4,594)
   Participants currently eligible  . . . .       (483)	     (772)      (681)
   All others . . . . . . . . . . . . . . .     (4,151)    (3,837)    (3,384)
                                              ---------  ---------  ---------
Total accumulated postretirement benefit
   obligation . . . . . . . . . . . . . . .    (11,046)    (9,172)    (8,659)
Plan assets at fair value . . . . . . . . .      7,893      6,327      5,465 
                                              ---------  ---------   --------
Accumulated postretirement benefit
   obligation in excess of plan assets  . .     (3,153)	   (2,845)    (3,194)
Unrecognized prior service cost . . . . . .       (805)      (867)      (929)
Unrecognized transition obligation  . . . .      5,278      5,630      5,982 
Unrecognized net gain . . . . . . . . . . .     (1,400)    (1,879)    (1,687)
                                               --------   --------   --------
Prepaid (accrued) postretirement benefit
   cost . . . . . . . . . . . . . . . . . .    $   (80)   $    39    $   172
                                               ========   ========   ========


     Net periodic postretirement benefit cost includes the following 
components:

                                                   1997       1996      1995
                                                   ----       ----      ----
                                                        	(In thousands)
Service cost . . . . . . . . . . . . . . . .     $   228   $   247     $ 224 
Interest cost  . . . . . . . . . . . . . . .         763       698       697 
Actual return on plan assets . . . . . . . .      (1,566)     (870)     (586)
Deferred asset gain. . . . . . . . . . . . .       1,028       407       264 
Recognition of transition obligation,
   net of amortization . . . . . . . . . . .         261       245       234 
                                                 -------   -------   -------
Total net periodic postretirement
   benefit cost  . . . . . . . . . . . . .       $   714   $   727   $   833 
                                                 =======   =======   =======

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

                                               	   1997      1996      1995
                                                   ----      ----      ----
Discount rate to determine postretirement
  benefit costs .  . . . . . . . . . . . . .       8.0%      8.0%       8.5%
Discount rate to determine postretirement
  benefit obligation . . . . . . . . . . . .       7.25%     8.0%       8.5%
Expected long-term rate of return on assets.        8.5%     8.5%       7.5%

     For measurement purposes, a 5.8 percent annual rate of increase in 
the per capita cost of covered benefits was assumed for 1997; the rate 
was assumed to decrease gradually to 5.0 percent by the year 2001 and 
remain at that level thereafter.  The health care cost trend rate 
assumption has a significant effect on the amounts reported.  For 
example, increasing the assumed health care cost trend rate by one 
percentage point would increase the accumulated postretirement benefit 
obligation as of December 31, 1997 by $1.7 million and the aggregate of 
the service and interest components of net periodic postretirement 
benefit cost for the year ended December 31, 1997 by $156,000.


     12. Fair Value of Financial Instruments.  If the first mortgage 
bonds and preferred stock outstanding at December 31, 1997 were 
refinanced using new issue debt rates of interest, which, on average, 
are lower than the Company's outstanding rates, the present value of 
those obligations would differ from the amounts outstanding on the 
December 31, 1997 balance sheet by 4 percent.  In the event of such a 
refinancing, there would be no gain or loss, inasmuch as under 
established regulatory precedent, any such difference would be reflected 
in rates and have no effect upon income.


     13. Deferred Credits.  At December 31, 1997, the Company had other 
deferred credits and long-term liabilities of $25.7 million, consisting 
of operating lease equalization, reserves for damage claims and 
environmental liabilities and accruals for employee benefits.


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


B. 	INVESTMENTS IN ASSOCIATED COMPANIES


     The Company accounts for investments in the following companies by 
the equity method:
                                  Percent Ownership       Investment in Equity
                                at December 31, 1997          December 31,    
                                --------------------      --------------------
                                                            1997         1996
                                                            ----         ----
                                                               (In thousands)
VELCO - Common . . . . . . . . .          29.5%          $  1,833      $ 1,834
      - Preferred  . . . . . . .          30.0%               961        1,118
                                                         --------      -------
Total VELCO  . . . . . . . . . .                            2,794        2,952
Vermont Yankee - Common  . . . .          17.9%             9,701        9,768
New England Hydro-Transmission -
     Common  . . . . . . . . . .          3.18%             1,063        1,205
New England Hydro-Transmission
     Electric - Common . . . . .          3.18%             1,811        1,891
                                                          -------      -------
                                                          $15,369      $15,816
                                                          =======      =======

     Undistributed earnings in associated companies totaled $632,000 at 
December 31, 1997.


     VELCO.  VELCO is a corporation engaged in the transmission of 
electric power within the State of Vermont.  VELCO has entered into 
transmission agreements with the State of Vermont and other electric 
utilities, and under these agreements bills all costs, including 
interest on debt and a fixed return on equity, to the State and others 
using the system.  The Company's purchases of transmission services from 
VELCO were $7.6 million, $7.7 million and $7.6 million for the years 
1997, 1996 and 1995, respectively.  Pursuant to VELCO's Amended Articles 
of Association, the Company is entitled to approximately 30 percent of 
the dividends distributed by VELCO.  The Company has recorded its equity 
in earnings on this basis and also is obligated to provide its 
proportionate share of the equity capital requirements of VELCO through 
continuing purchases of its common stock, if necessary.

     Summarized financial information for VELCO is as follows:
                                                         December 31,    
                                                 ------------------------   
                                                 1997      1996      1995 
                                                 ----      ----      ----
                                           	          (In thousands)
Company's equity in net income . . . . . . .   	$   354  $   383   $   377
                                                =======  =======   =======
Total assets . . . . . . . . . . . . . . . .   	$70,566  $74,065   $71,668
Less:
   Liabilities and long-term debt  . . . . .   	61,162	   64,159    61,238
                                                ------   -------   -------
Net assets . . . . . . . . . . . . . . . . .   	$9,404   $ 9,906   $10,430
                                                ======   =======   =======
Company's equity in net assets . . . . . . .   	$2,794   $ 2,952   $ 3,089
                                                ======   =======   =======


     Vermont Yankee.  The Company is responsible for 17.7 percent of 
Vermont Yankee's expenses of operations, including costs of equity 
capital and estimated costs of decommissioning, and is entitled to a 
similar share of the power output of the nuclear plant, which has a net 
capacity of 531 megawatts.  Vermont Yankee's current estimate of 
decommissioning costs is approximately $386 million, of which $193 
million has been funded.  At December 31, 1997, the Company's portion of 
the net unfunded liability was $34 million, which it expects will be 
recovered through rates over Vermont Yankee's remaining operating life.  
As a sponsor of Vermont Yankee, the Company also is obligated to provide 
20 percent of capital requirements not obtained by outside sources.  
During 1997, the Company incurred $28.5 million in Vermont Yankee annual 
capacity charges, which included $1.9 million for interest charges.  The 
Company's share of Vermont Yankee's long-term debt at December 31, 1997 
was $16.2 million.

     The Price-Anderson Act currently limits public liability from a 
single incident at a nuclear power plant to $8.9 billion.  Any liability 
beyond $8.9 billion is indemnified under an agreement with the Nuclear 
Regulatory Commission, but subject to congressional approval.  The first 
$200 million of liability coverage is the maximum provided by private 
insurance.  The Secondary Financial Protection Program is a 
retrospective insurance plan providing additional coverage up to 
$8.7 billion per incident by assessing premiums of $79.3 million against 
each of the 110 reactor units in the United States that are currently 
subject to the Program, limited to a maximum assessment of $10 million 
per incident per nuclear unit in any one year.  The maximum assessment 
is expected to be adjusted at least every five years to reflect 
inflationary changes.

     The above insurance now covers all workers employed at nuclear 
facilities for bodily injury claims.  Vermont Yankee had previously 
purchased a Master Worker insurance policy with limits of $200 million 
with one automatic reinstatement of policy limits to cover workers 
employed on or after January 1, 1988.  Vermont Yankee no longer 
participates in this retrospectively based worker policy and has 
replaced this policy with the guaranteed cost coverage mentioned above.  
Vermont Yankee does, however, retain a potential obligation for 
retrospective adjustments due to past operations of several smaller 
facilities that did not join the new program.  These exposures will 
cease to exist no later than December 31, 2007.  Vermont Yankee's 
maximum retrospective obligation remains at $3.1 million.  The Secondary 
Financial Protection layer, as referenced above, would be in excess of 
the Master Worker policy.

     Insurance has been purchased from Nuclear Electric Insurance 
Limited (NEIL) to cover the costs of property damage, decontamination or 
premature decommissioning resulting from a nuclear incident.  All 
companies insured with NEIL are subject to retroactive assessments if 
losses exceed the accumulated funds available.  The maximum potential 
assessment against Vermont Yankee with respect to NEIL losses arising 
during the current policy year is $11.0 million.  Vermont Yankee's 
liability for the retrospective premium adjustment for any policy year 
ceases six years after the end of that policy year unless prior demand 
has been made.

     Summarized financial information for Vermont Yankee is as follows:
                                                         December 31,        
                                                 --------------------------
                                                 1997       1996       1995
                                                 ----       ----       ----  
                                                      	(In thousands)
Earnings:
   Operating revenues . . . . . . . . . . .    $173,106  $181,715   $180,437
   Net income applicable to common stock  .       6,834     6,985      6,790
   Company's equity in net income . . . . .       1,244     1,232      1,171
Total assets  . . . . . . . . . . . . . . .    $610,024  $565,000   $531,293
Less:
   Liabilities and long-term debt . . . . .    	555,735  	510,202    477,350
                                               --------  --------   --------
Net assets  . . . . . . . . . . . . . . . .    $ 54,289  $ 54,798   $ 53,943
                                               ========  ========   ========
Company's equity in net assets  . . . . . .    $  9,701  $  9,768   $  9,631
                                               ========  ========   ========


                               C. COMMON STOCK EQUITY


     The Company maintains a Dividend Reinvestment and Stock Purchase 
Plan (DRIP) under which 388,508 shares were reserved and unissued at 
December 31, 1997.  The Company also funds an Employee Savings and 
Investment Plan (ESIP).  At December 31, 1997, there were 123,198 shares 
reserved and unissued under the ESIP.

     During 1995, the Company's Board of Directors, with subsequent 
approval of the Company's common shareholders, adopted the Compensation 
Program for Officers and Certain Key Management Personnel.  The program 
links a portion of the officers and key management personnels' 
compensation to corporate performance results.  Participants are 
entitled to receive cash and restricted and unrestricted stock grants in 
predetermined proportions.  Participants who receive restricted stock 
are entitled to receive dividends and have voting rights but assumption 
of full beneficial ownership is contingent upon two restrictions of a 
five year duration, including no transferability and forfeiture of the 
stock upon termination of employment with the Company.  Participants who 
receive unrestricted stock assume full beneficial ownership upon grant 
and may retain or sell such shares.  During 1997, 10,956 shares of 
common stock were awarded under this program.  At December 31, 1997, 
there were 20,083 shares reserved and unissued under the Compensation 
Program.

     Changes in common stock equity for the years ended December 31, 
1995, 1996 and 1997 are as follows:


<TABLE>
<CAPTION>
                                              Common Stock                                   Treasury Stock
                                         ------------------------  Paid-in     Retained  ------------------------   Stock
                                            Shares      Amount     Capital     Earnings     Shares      Amount      Equity
                                            ------      ------     -------     --------     ------      ------      ------
                                                                             (Dollars in thousands)
<S>                                        <C>           <C>         <C>         <C>          <C>          <C>      <C>
BALANCE, December 31, 1994...............  4,677,512     $15,592     $60,378     $25,727      15,856       ($378)   $101,319

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

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

Common Stock Issuance:
  DRIP...................................    120,631         402       2,182                                           2,584
  ESIP...................................     26,702          89         507                                             596
  Compensation Program:
    Restricted Shares....................      6,190          21         119                                             140
    Stock Grant..........................      4,766          16          92                                             108
Net Income...............................                                          9,438                               9,438
Cash Dividends on Capital Stock:
  Common Stock      -$2.12 per share.....                                         (8,204)                             (8,204)
  Preferred Stock   -$4.75 per share.....                                            (13)                                (13)
                    -$7.00 per share.....                                            (33)                                (33)
                    -$9.375 per share....                                            (86)                                (86)
                    -$8.625 per share....                                           (423)                               (423)
                    -$7.32 per share.....                                           (878)                               (878)
Other-Preferred Stock Issuance Expense...                               (406)                                           (406)
                                         ------------------------------------------------------------------------------------
BALANCE, December 31, 1997...............  5,195,432     $17,318     $70,720     $26,717      15,856       ($378)   $114,377
                                         ====================================================================================
</TABLE>

     Dividend Restrictions.  Certain restrictions on the payment of cash 
dividends on common stock are contained in the Company's indenture 
relating to long-term debt and in the Restated Articles of Association.  
Under the most restrictive of such provisions, $17.5 million of retained 
earnings were free of restrictions at December 31, 1997.

     The properties of the Company include several hydroelectric 
projects licensed under the Federal Power Act, with license expiration 
dates ranging from 1999 to 2025.  At December 31, 1997, $350,000 of 
retained earnings had been appropriated as excess earnings on 
hydroelectric projects as required by Section 10(d) of the Federal Power 
Act.


                             D. 	PREFERRED STOCK


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

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

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

     Under the Restated Articles of Association relating to Redeemable 
Cumulative Preferred Stock, the annual aggregate amount of purchase and 
sinking fund requirements for the next five years are $1,650,000 for 
each of the years 1998-1999, $1,640,000 for 2000 and $235,000 for 2001-
2002.

     Certain classes of preferred stock are redeemable at the option of 
the Company or, in the case of voluntary liquidation, at various prices 
on various dates.  The prices include the par value of the issue plus 
any accrued dividends and a redemption premium.  The redemption premium 
for Class B, C and D, Series 1, is $1.00 per share.  The redemption 
premium for the Class D, Series 3, is $1.919 per share until September 
1, 1998; and $0.916 per share from September 1, 1998 to September 1, 
1999, after which there is no redemption premium.


                               E. LONG-TERM DEBT


     Utility.  Substantially all of the property and franchises of the 
Company are subject to the lien of the indenture under which first 
mortgage bonds have been issued.  The annual sinking fund requirements 
(excluding amounts that may be satisfied by property additions) and 
long-term debt maturities for the next five years are:

                                 Sinking
                                  Funds   Maturities      Total
                                 -------  ----------      -----
                                          (In thousands)
1998 . . . . . . . . . . . . . .$1,700      	$3,000      	$4,700
1999 . . . . . . . . . . . . . .	1,700       	---	         1,700
2000 . . . . . . . . . . . . . .	1,700       	5,000       	6,700
2001 . . . . . . . . . . . . . .	1,700	       8,000       	9,700
2002 . . . . . . . . . . . . . .	1,700       	8,000       	9,700


     Non-Utility.  At December 31, 1997, Green Mountain Propane Gas 
Company, the Company's propane subsidiary, had long-term debt of 
$1,900,000, which was secured by substantially all of the subsidiary's 
assets, and Mountain Energy, Inc., the Company's subsidiary that invests 
in energy generation and energy and wastewater efficiency projects, had 
unsecured long-term debt of $1,583,330.  The annual sinking fund 
requirements and maturities for the next three years are:
                                   Sinking
                                    Funds     Maturities    Total
                                   -------    ----------    -----
                                            (In thousands)
1998 . . . . . . . . . . . . .     $1,167       $ ---      $1,167
1999 . . . . . . . . . . . . .        167         900       1,067
2000 . . . . . . . . . . . . .         83       1,166       1,249


                             F. SHORT-TERM DEBT


     Utility.  On August 12, 1997, the Company entered into a revolving 
credit agreement in the amount of $45 million with three banks, which 
replaces a portion of its lines of credit.  At December 31, 1997, there 
were no borrowings outstanding under this revolving credit agreement.  

     At December 31, 1997, the Company had lines of credit with two 
banks totaling $8.0 million, with borrowings outstanding of $2.6 
million.  Borrowings under these lines of credit are at interest rates 
based on various market rates and are generally less than the prime 
rate.  The Company has fee arrangements on its lines of credit ranging 
from 0 to 1/8 percent and no compensating balance requirements.  These 
lines of credit are subject to periodic review and renewal during the 
year by the various banks.

     The weighted average interest rate on borrowings outstanding at 
December 31, 1997 and December 31, 1996 was 7.0 percent and 5.7 percent, 
respectively.


     Non-Utility.  At December 31, 1997, Green Mountain Propane Gas 
Company, the Company's propane subsidiary, had a line of credit with a 
bank for $750,000, with $400,000 outstanding.


                            G. INCOME TAXES


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

     The regulatory assets and liabilities represent taxes that will be 
collected from or returned to customers through rates in future periods.  
As of December 31, 1997 and 1996, the net regulatory assets were 
$1,704,000 and $1,194,000, respectively.

     The temporary differences which gave rise to the net deferred tax 
liability at December 31, 1997 and December 31, 1996, were as follows:

                                       		At December 31,	    	At December 31,
                                                1997               1996      
                                         ---------------      ---------------
                                    		              (In thousands)
Deferred Tax Assets
 Contributions in aid of construction         	$ 7,946           $ 7,094  
 Deferred compensation and
   post-retirement benefits . . . . . .          3,199             2,944  
 Alternative minimum tax credit  . . .              15              (552) 
 Other . . . . . . . . . . . . . . . .           3,212             2,719  
                                               -------           -------
                                                14,372            12,205
                                               -------           -------
Deferred Tax Liabilities
 Property-related and other  . . . . .          31,864            29,359
 Demand side management costs  . . . .           4,775             5,856  
 Deferred purchased power costs  . . .           1,234             3,716  
                                              --------          --------
                                                37,873            38,931
                                              --------          --------
Net accumulated deferred income tax
   liability . . . . . . . . . . . . .        ($23,501)         ($26,726)
                                              =========         =========
 

The following table reconciles the change in the net accumulated 
deferred income tax liability to the deferred income tax expense 
included in the income statement for the period:
                                                  Year Ended December 31,
                                                 --------------------------
                                                 1997       1996       1995
                                                 ----       ----       ----
                                                       (In thousands)
Net change in deferred income tax
  liability per above table . . . . . . . . .  ($3,225)    $1,434    $3,210
Change in income tax related regulatory
  assets and liabilities. . . . . . . . . . .      509        504       503
Change in alternative minimum tax credit  . .      567        109       168
IRS audit adjustment, 1989 - 1990 . . . . . .       --         --       255
                                               --------    ------    ------
Deferred income tax expense for the period  .  ($2,149)    $2,047    $4,136
                                               ========    ======    ======

The components of the provision for income taxes are as follows:
                                            		   Year Ended December 31,
                                               ----------------------------
                                              	1997         1996       1995
                                               ----         ----       ----
                                                        (In thousands)
Current federal income taxes . . . . . .      $7,355       $3,708    $	1,359
Current state income taxes . . . . . . .       2,267          990        365
                                              ------       ------    -------
Total current income taxes. . . . . .          9,622        4,698      1,724
                                              ------       ------    -------

Deferred federal income taxes  . . . . .      (1,623)       1,588      3,239
Deferred state income taxes  . . . . . .        (526)         459        897
                                              -------       -----      -----
Total deferred income taxes. . . . . .        (2,149)       2,047      4,136
                                              -------       -----      -----

Investment tax credits -- net  . . . . .        (282)        (282)      (282)
                                              ------       -------    -------
Income taxes charged to operations . . .      $7,191       $6,463     $5,578
                                              ======       =======    =======

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

                                                  Year Ended December 31,
                                                 -------------------------
                                                 1997       1996      1995
                                                 ----       ----      ----
                                                  (Dollars in thousands)
Income before income tax . . . . . . .          $16,630    $18,422   $17,081
Federal statutory rate . . . . . . . .            34.5%        34%       34%
Computed "expected" federal
  income taxes . . . . . . . . . . . .          $ 5,737    $ 6,263   $ 5,808
Increase (decrease) in taxes
  resulting from:
  Tax versus book depreciation . . . .       	      349        327       327
  Dividends received and paid credit .             (575)      (524)     (616)
  AFUDC - equity funds . . . . . . . .             (123)       (59)       (9)
  Amortization of ITC  . . . . . . . .             (282)      (282)     (282)
  State tax benefit  . . . . . . . . .             (601)      (493)     (429)
  Excess deferred taxes  . . . . . . .              (60)       (60)      (60)
  Taxes attributable to subsidiaries .              682       (140)     (401)
  Tax reserve  . . . . . . . . . . . .              270       (101)       (3)
  Other  . . . . . . . . . . . . . . .               53         83       (19)
                                                 ------     ------    -------
Total federal income taxes . . . . . .           $5,450     $5,014    $4,316
                                                 ======     ======    =======
Effective federal income tax rate  . .           32.8%      27.2%     25.3%

     Non-Utility.  The Company's non-utility subsidiaries had 
accumulated deferred income taxes of $7.1 million on their balance 
sheets at December 31, 1997, largely attributable to property-related 
transactions.

     The components of the provision for the income tax/(benefit) for 
the non-utility operations are:
                                             Year Ended December 31,
                                            -----------------------------
                                           	1997         1996        1995
                                            ----         ----        ----
                                                  (In thousands)
State income taxes . . . . . . . . . .      $ 78        $154        $165
Federal income taxes . . . . . . . . .    (1,071)        207         613
Investment tax credits . . . . . . . .       (45)        (45)        (45)
                                         --------      ------      ------
Income tax (benefit)/provision charged
 to operations. . . . . . . . . . . . .  $(1,038)      $ 316       $ 733
                                         ========      ======      ======


     The effective federal income tax rates for the non-utility 
operations were 37.0 percent, 22.4 percent, and 29.7 percent for the 
years ended December 31, 1997, 1996 and 1995, respectively.  
     The increase in 1997 income taxes is primarily due to an increase 
in taxable income, an increase in the combined federal and state income 
tax rate and an increase in the reserve for unaudited income tax years.


                H. 	QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


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

                                            1997 Quarter Ended
                                            ------------------
                                 	March    June    Sept.     Dec.	    Total
                                  -----    ----    -----     ----     -----
                                 (Amounts in thousands, except per share)
Operating Revenues . . . . . . $	47,204 	$42,682 	$43,574 	$45,863 	$179,323
Operating Income . . . . . . .    4,251	  	2,991   	4,542   	3,731	   15,515
Net Income . . . . . . . . . .    3,315   	1,230   	3,371   	1,522     9,438
Net Income Applicable to
  Common Stock . . . . . . . .    2,941	    	856   	3,022   	1,186 	   8,005
Earnings per Average Share of
  Common Stock . . . . . . .  .   $0.58   		$0.17  	$0.59   	$0.23     $1.57
Weighted Average Number of
  Common Shares Outstanding  .   	5,044	    5,096  	5,138   	5,168	    5,112

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


                     I. 	COMMITMENTS AND CONTINGENCIES


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

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


     2. Environmental Matters.  Public concern for the environment has 
resulted in increased government regulation of the licensing and 
operation of electric generation, transmission and distribution 
facilities.   The electric industry typically uses or generates a range 
of potentially hazardous products in its operations.  The Company must 
meet various land, water, air and aesthetic requirements as administered 
by local, state and federal regulatory agencies.    The Company 
maintains an environmental compliance and monitoring program that 
includes employee training, regular inspection of Company facilities, 
research and development projects, waste handling and spill prevention 
procedures and other activities.  Subject to developments concerning the 
Pine Street Barge Canal site described below, the Company believes that 
it is in substantial compliance with such requirements, and no material 
complaints concerning compliance by the Company with present 
environmental protection regulations are outstanding.

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

     Since 1994, the EPA has established a coordinating council, with 
representatives of the PRPs, environmental and community groups, the 
City of Burlington and the State of Vermont presided over by a neutral 
facilitator.  The council has determined, by consensus, what additional 
studies were appropriate for the site, and is addressing the question of 
additional response activities.  The EPA, the State of Vermont and other 
parties have entered into two consent orders for completion of 
appropriate studies.  Work is continuing under the second of those 
orders.  Most recently, on September 23, 1997, the council reached 
tentative agreement on a key component of the proposed remedy for the 
Pine Street site, namely, placement of an underwater sand/silt cap on 
areas of the canal and wetland sediments, combined with long-term 
monitoring to ensure effectiveness of the cap and to ensure that 
groundwater does not reach Lake Champlain, adjacent to the site.  The 
EPA has estimated the costs of this remedy at between $6 to $10 million, 
subject to change.  In addition, the council is exploring supplemental 
projects in and around the site and Burlington as part of a larger plan 
to improve environmental conditions in the vicinity. 

     On December 1, 1994, the Company, and two other PRPs, New England 
Electric System (NEES) and  Vermont Gas Systems (VGS), entered into a 
confidential settlement agreement with the State of Vermont, the City of 
Burlington and nearly all other landowner PRPs under which, subject to 
certain qualifications, the liability of those landowner PRPs for future 
Superfund response costs would be limited and specified.  On December 1, 
1994, the Company entered into a confidential agreement with VGS 
compromising contribution and cost recovery claims of each party and 
contractual indemnity claims of the Company arising from the 1964 sale 
of the manufactured gas plant to VGS.  In March 1996, the Company and 
NEES entered into a confidential agreement compromising past and future 
contribution and cost recovery claims of both parties relating to 
response costs.  In December 1997, the Company and Southern Union Co. 
entered into a confidential settlement agreement compromising past and 
future contribution and cost recovery claims of both parties relating to 
response costs.  The Company has received payment of the full amount 
provided for in the settlement.  In January 1998, the Company and UGI 
Utilities, Inc. entered into a confidential settlement agreement 
compromising past and future contribution and cost recovery claims of 
both parties relating to response costs.  The Company has received 
payment of the initial amount provided for in the settlement.  The EPA 
has advised the Company that it has incurred substantial unrecovered 
response sums at the site which, together with interest the EPA alleges 
may be payable, amounts to approximately $11.0 million.  The Company has 
not yet received a formal demand for these sums.  The Company will 
vigorously dispute the EPA's recovery of such costs, which include 
substantial sums for studies and other activities that were not 
reasonably necessary and were not undertaken consistent with legal and 
regulatory requirements.  Further, the Company's settlement agreements 
with certain PRP's will reduce the extent to which it may bear these 
past response costs.  Consequently, the Company is not able at this time 
to predict with certainty whether, or the extent to which it will be 
required to pay such past response costs.

     In December 1991, the Company brought suit against eight previous 
insurers seeking recovery of unrecovered past costs, cost of defense and 
indemnity against future liabilities associated with environmental 
problems at the site.  Discovery in the case, which was previously 
subject to a stay, is complete.  The Company has reached confidential 
settlements with the defendants in this litigation; several such 
settlements are in the final stages of documentation.

     The Company has deferred amounts received from third parties, under 
confidential settlements, pending resolution of the Company's ultimate 
liability with respect to the site and rate recognition of that 
liability.  

     Although the cost of the coordinating council's tentative 
remediation plan, described above, is not expected to approach EPA's 
earlier estimate of remediation costs for its original clean-up plan, 
because the current EPA estimate is subject to change, and because the 
Company believes it may prevail with respect to some of the EPA's 
unrecovered response costs, the Company is unable to predict at this 
time the magnitude of any liability resulting from potential claims for 
the costs to investigate and remediate the site, or the likely 
disposition or magnitude of claims the Company may have against others, 
including its insurers, except to the extent described above.

     Through rate cases filed in 1991, 1993, 1994 and 1995, the Company 
has sought and received recovery for ongoing expenses associated with 
the Pine Street Barge Canal site.  Specifically, the Company proposed 
rate recognition of its unrecovered expenditures incurred between 
January 1, 1991 and June 30, 1995 (in the total of approximately $8.7 
million) for technical consultants and legal assistance in connection 
with the EPA's enforcement action at the site and insurance litigation.  
While reserving the right to argue in the future about the 
appropriateness of rate recovery for the Pine Street Barge Canal site 
related costs, the Company and the Vermont Department of Public Service 
(the Department) reached agreements in these cases that the full amount 
of the Pine Street Barge Canal site costs reflected in those rate cases 
should be recovered in rates.  The Company's rates approved by the VPSB 
in those proceedings reflected the Pine Street Barge Canal site related 
expenditures referred to above.  The Company proposed, in a rate filing 
made on June 16, 1997 recovery of an additional $3.0 million in such 
expenditures.

     In an Order released March 2, 1998, the VPSB suspended the 
amortization of expenditures associated with the Pine Street Barge Canal 
site pending further proceedings.  Although it did not eliminate the 
rate base deferral of these expenditures, or make any specific order in 
this regard, the VPSB indicated that it was inclined to agree with other 
parties in the case that the ultimate costs of the Pine Street Barge 
Canal, taking into account recoveries from insurance carriers and other 
PRP's, should be shared between customers and shareholders of the 
Company.

     As of December 31, 1997, total expenditures for the Pine Street 
Barge Canal site were $13.4 million, inclusive of the $11.7 million 
referred to above.

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


     3. Operating Leases.  The Company has an operating lease for its 
corporate headquarters building and two of its service center buildings, 
including related real estate.  This lease has a base term of 25 years, 
ending June 30, 2009, with renewal options aggregating another 25 years.  
The annual lease charges will total $983,000 for each of the years 1998 
through 2008 and $574,000 for 2009.  The Company has options to purchase 
the buildings at fair market value at the end of the base term and at 
the end of each renewal period.


     4. Jointly-Owned Facilities.  The Company had joint-ownership 
interests in electric generating and transmission facilities at December 
31, 1997, as follows:

                            Ownership   Share of      Utility   Accumulated
                             Interest   Capacity       Plant    Depreciation
                            ---------   --------      -------   ------------
                              (In %)     (In MW)         (In thousands)
Highgate  . . . . . . . . . .   33.8       67.6       $10,592      $3,309
McNeil  . . . . . . . . . . .   11.0        5.9       $ 8,633      $3,613
Stony Brook (No. 1) . . . . .    8.8       31.0       $10,039      $6,348
Wyman (No. 4) . . . . . . . .    1.1        6.8       $ 2,384      $1,384
Metallic Neutral Return (1) .   59.4        ---       $ 1,563      $  431
(1)	Neutral conductor for NEPOOL/Hydro-Quebec Interconnection

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


     5. Rate Matters.  On June 16, 1997, the Company filed a request 
with the VPSB to increase retail rates by 16.7 percent ($26 million in 
additional annual revenues) and the target return on common equity from 
11.25 percent to 13 percent.  Initial hearings before the VPSB began 
November 3, 1997.  The VPSB allowed the intervention of various other 
parties. 

      In August 1997, several groups, including the Vermont Public 
Interest Research Group (VPIRG), demanded that the VPSB appoint an 
independent counsel to advocate against recovery of Hydro-Quebec power 
costs by the Company.  The VPSB issued an order appointing an 
"independent investigator," described as a person or persons who will 
perform a rigorous and impartial analysis of the Company's actions with 
respect to its power supply options, including the Hydro-Quebec 
contract.  On November 7, 1997, the VPSB selected a firm, MSB Energy 
Associates, Inc. (MSB) to undertake the tasks.

     In testimony filed with the VPSB on October 17, 1997, the 
Department asked the VPSB to find the Company's negotiation, execution 
and decision to "lock in" the contract with Hydro-Quebec to be imprudent 
and uneconomic.  The Department had supported the contract in the period 
1989-1991 after completing its own analysis, based on substantially the 
same information that was available to the Company.  The VPSB in 1990, 
1991, 1992 and 1994 issued orders that determined the contract to be 
needed to supply electricity to Vermont customers, economically 
beneficial to the State and an appropriate part of the Company's 
legally-required least-cost integrated resource plan.

     On October 31, 1997, the Company filed with the VPSB Objections and 
a Motion to Strike relating to the Hydro Quebec contract testimony and 
requested that the VPSB schedule oral argument on the motion prior to 
November 17, 1997.  The grounds for the motion were that the VPSB had 
previously decided the issues sought to be relitigated.  The VPSB heard 
argument on the motion on November 14, 1997 and ruled against the 
Company, but granted the Company leave to renew the motion.  The Company 
did so in its post-trial briefs.  

     In its testimony, submitted in late 1997, MSB was critical of the 
Company's power supply decision-making in 1991, and recommended a steep 
disallowance of the Hydro-Quebec power costs, in excess of $10 million 
per year.  During the rebuttal phase of the rate case, the Company 
showed that, MSB was not independent and did not present "rigorous 
analysis" as the VPSB had ordered.  MSB's presentation adopted the 
testimony of the Department's principal witnesses as well as theories 
espoused by a professional expert retained by IBM and MSB failed to 
present its own analysis showing that, based on any information 
possessed or available to the Company during the critical summer and 
fall of 1991, the long-term Hydro-Quebec contract was uneconomic.

     The Company filed a motion to strike the MSB testimony and to 
impose sanctions upon MSB for submitting testimony without any good 
faith factual or legal basis.  The VPSB struck several portions of MSB's 
testimony forming the core of their arguments on imprudence, based on 
legal or contract interpretation, on the ground that MSB had no 
qualifications to present this testimony.

     Briefs in the case on non-Hydro-Quebec issues were filed January 
30, 1998; the Hydro-Quebec briefs were filed on February 2; all reply 
briefs were filed on February 6.  In its final submissions, the Company 
reduced the requested increase to 14.4 percent due to changed estimates 
of costs to be incurred in the rate year.  

     6. Subsequent Events.  On March 2, 1998, the VPSB released its 
Order in the Company's pending rate case.  The VPSB ordered the 
Company's rates increased by 3.61 percent, increasing annual revenues by 
$5.6 million.  The Company had sought in its final submissions to the 
VPSB an increase of $22 million in revenue to cover increased cost of 
service.

     Approximately $11 million of the reduction of the Company's revenue 
request resulted primarily from the VPSB's modification of the Company's 
calculation of rate base, the exclusion of future capital projects from 
rate base, various cost of service reductions in areas of payroll and 
operations and maintenance, and a reduction in the requested allowed 
return on equity from 13 percent to 11.25 percent.  More significantly, 
the VPSB denied the recovery by the Company of $5.48 million in costs 
related to its long-term Hydro-Quebec power contract.  The decision 
stated that the Company had been imprudent in locking-into the power 
contract in August 1991 and that the contract power would not be used 
and useful to utility customers to the extent that power costs, after 
accounting for the imprudence disallowance, were in excess of current 
estimates of market prices for power.  Unless the Order is modified, the 
Company must accrue its estimate of the loss related to these imprudence 
and used and useful disallowances.

The Order discussed the VPSB's policies of disallowing the recovery 
of imprudent expenditures and power contract purchases that it 
determines not to be used and useful.  However, the Order also stated 
that the methodologies and measures used in this rate case were 
provisional and applicable in the current proceeding only.  The VPSB 
went on to state that it will schedule subsequent proceedings to examine 
the appropriate methodologies for measuring the effects of imprudence 
and calculating the portion of the contract that is not used and useful.  
If the VPSB were to apply the methodologies and measures used in the 
Order (or similar methodologies and measures) to future power contract 
costs, notwithstanding its statement that it will reexamine such 
matters, the Company would be required under Statement of Financial 
Accounting Standards No. 5 to record an expense of approximately $180 
million based on the estimated future market price of power used by the 
VPSB in its Order.  However, the Company will not be able to estimate 
the loss to be recorded, if any, until the reconsideration and appeal 
processes and such subsequent proceedings are completed.

Furthermore, if the VPSB's ruling, that above-market Hydro-Quebec 
power contract costs are not used and useful and should be shared 
equally between ratepayers and shareholders, is not modified, then the 
Company's rates may be set, effectively, on a basis other than its costs 
to provide service.  This would require the Company to discontinue the 
application of Statement of Financial Accounting Standards No. 71, 
resulting in the write-off of regulatory assets and liabilities with a 
charge to earnings, as an extraordinary item.  As of December 31, 1997, 
the Company had approximately $15 million of net regulatory assets on 
its balance sheet.

In addition to the Hydro-Quebec power contract disallowances 
described above, the Order also requires the Company to create a 
deferred credit for $9.1 million of payments received by the Company in 
1997 pursuant to two arrangements with Hydro-Quebec that were designed 
to decrease the costs of the contract power.  The Order, contrary to the 
VPSB's prior Accounting Order dated December 31, 1996, now requires the 
Company to amortize this deferred credit over the remaining lives of the 
related power contracts.  Unless the current Order is modified, the 
Company would be required to expense approximately $8.6 million 
previously recognized in earnings related to the $9.1 million.

In response to the Order, the rating agencies that rate the 
Company's fixed income securities have placed the Company's credit 
ratings on their rating watch or rating outlook with negative or down 
implications.

     The Company is exploring all legal and regulatory remedies open to 
it to challenge the VPSB decision, including requesting reconsideration 
from the VPSB and a direct appeal to the Vermont Supreme Court.  The 
Company believes that the decisions set forth in the Order are inaccurate 
factually and incorrect legally.  The VPSB's ruling, if not changed, 
would have a significant impact on the Company's reported financial 
condition and 1998 results of operations and, depending on the outcome of 
future proceedings to be conducted by the VPSB, could impact the 
Company's credit ratings, dividend policy and financial viability.

     On February 20, 1998, the Company and GMPG entered into a sales 
agreement with VGS Propane, LLC, for the sale of all GMPG assets which 
had a net book value of $8.1 million at December 31, 1997.  This sale is 
not expected to have a material impact on the Company's results of 
operations.


     7. Deferred Charges Not Included in Rate Base.  The Company has 
incurred and deferred approximately $3.1 million in costs for tree 
trimming, storm damage and regulatory commission work.  Currently, the 
Company amortizes such costs based on historical averages and does not 
receive a return on amounts deferred.  Management expects to seek and 
receive ratemaking treatment for these costs in future filings.

     In early January 1998, Vermont and much of the Northeast 
experienced a severe ice storm which resulted in approximately $2.5 
million of storm damage costs which will also be deferred.  Management 
will seek and expects to receive a return on these costs as discussed 
above.

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


    J. 	OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT


     Agreements executed in 1985 among the Company, VELCO and other 
NEPOOL members and Hydro-Quebec provided for the construction of the 
second phase (Phase II) of the interconnection between the New England 
electric systems and that of Hydro-Quebec.  Phase II expands the Phase I 
facilities from 690 megawatts to 2,000 megawatts and provides for 
transmission of Hydro-Quebec power from the Phase I terminal in northern 
New Hampshire to Sandy Pond, Massachusetts.  Construction of Phase II 
commenced in 1988 and was completed in late 1990.  The Company is 
entitled to 3.2 percent of the Phase II power-supply benefits.  Total 
construction costs for Phase II were approximately $487 million.  The 
New England participants, including the Company, have contracted to pay 
monthly their proportionate share of the total cost of constructing, 
owning and operating the Phase II facilities, including capital costs.  
As a supporting participant, the Company must make support payments 
under thirty-year agreements.  These support agreements meet the capital 
lease accounting requirements under SFAS 13.  At December 31, 1997, the 
present value of the Company's obligation is $8.3 million.

Projected future minimum payments under the Phase II support agreements 
are as follows:
               Year ending December 31,
               1998 . . . . . . . . . . .  $  463,450
               1999 . . . . . . . . . . .     463,450
               2000 . . . . . . . . . . .     463,450
               2001 . . . . . . . . . . .     463,450
               2002 . . . . . . . . . . .     463,450
               Total for 2003-2020  . . .   6,024,845
                                           ----------
                                           $8,342,095
                                           ==========

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


                      K. 	LONG-TERM POWER PURCHASES


     1. Unit Purchases.  Under long-term contracts with various electric 
utilities in the region, the Company is purchasing certain percentages 
of the electrical output of production plants constructed and financed 
by those utilities.  Such contracts obligate the Company to pay certain 
minimum annual amounts representing the Company's proportionate share of 
fixed costs, including debt service requirements (amounts necessary to 
retire the principal of and to pay the interest on the portion of the 
related long-term debt ascribed to the Company) whether or not the 
production plants are operating.  The cost of power obtained under such 
long-term contracts, including payments required to be made when a 
production plant is not operating, is reflected as "Power Supply 
Expenses" in the accompanying Consolidated Statements of Income.

     Information (including estimates for the Company's portion of 
certain minimum costs and ascribed long-term debt) with regard to 
significant purchased power contracts of this type in effect during 1997 
follows:

                                                    Stony      Vermont
                                     Merrimack      Brook      Yankee
                                     ---------      -----      -------
                                           (Dollars in thousands)
Plant capacity . . . . . . . . . . .  320.0 MW    352.0 MW    531.0 MW
Company's share of output  . . . . .      8.9%        4.4%       17.7%
Contract period  . . . . . . . . . . 1968-1998         (1)         (2)
Company's annual share of:
  Interest . . . . . . . . . . . . .    $  645      $  221     $ 1,850
  Other debt service . . . . . . . .       371         319         ---
  Other capacity . . . . . . . . . .     1,939         387      25,328
                                        ------      ------     -------
Total annual capacity  . . . . . . .    $2,955      $  927     $27,178
                                        ======      ======     =======
Company's share of long-term debt  .    $  894      $4,241     $16,220
                                        ======      ======     =======

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


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

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

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

     As part of the July 1994 Agreement, the Company is obligated to 
purchase $4 million (in 1994 dollars) worth of research and development 
work from Hydro-Quebec over the four-year period, and made a $6.5 
million (in 1994 dollars) cash payment to Hydro-Quebec in 1995.  Hydro-
Quebec retains the right to curtail annual energy deliveries by 10 
percent up to five times, over the 2000 to 2015 period, if documented 
drought conditions exist in Quebec.

     During the first year of the July 1994 Agreement (the period from 
November 1995 through October 1996), the average cost per kilowatt-hour 
of Schedules B and C3 combined was cut from 6.4 to 4.2 cents per 
kilowatt-hour, a 34 percent (or $16 million) cost reduction.  Over the 
period from November 1996 through December 2000 and accounting for the 
cash payments to Hydro-Quebec, the combined unit costs will be lowered 
from 6.6 to 5.9 cents per kilowatthour, reducing unit costs by 10 
percent and saving $20.7 million in nominal terms.

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

     A summary of the Hydro-Quebec contracts, including the July 1994 
Agreement, but excluding the January and November 1996 arrangements 
(described below) including historic and projected charges for the years 
indicated, follows:

                       	                    The 1987 Contract
                    	                 Schedule B      Schedule C3
                                      ----------      -----------
                                        (Dollars in thousands)
Capacity Acquired . . . .   	            68 MW            46 MW
Contract Period . . . . .             1995-2015        1995-2015
Minimum Energy Purchase
 (annual load factor) . .               75%               75%

Annual Energy Charge  . .              $10,555          $7,188
                                        (1997)           (1997)

                                       $14,999         $10,347
                                      (1998-2015)*    (1998-2015)*

Annual Capacity Charge . .             $14,018          $1,913
                                        (1997)           (1997)

                                        $17,135        $11,320
                                      (1998-2015)*    (1998-2015)*

Average Cost per KWH . .                 6.1 cents       3.3 cents
                                        (1997) **       (1997)**

                                         7.0 cents       6.7 cents
                                      (1998-2015)***  (1998-2015)***
*  Estimated average.
** Excludes amortization of payments to Hydro-Quebec for the July 1994 
   Agreement.
***Estimated average in nominal dollars, levelized over the period 
   indicated.  Includes amortization of payments to Hydro-Quebec for the
   July 1994 Agreement.

     Under an arrangement negotiated in January 1996 (the January 1996 
Agreement), Hydro-Quebec provided a cash payment to the Company of $3.0 
million in 1996 and provided an additional cash payment of $1.1 million 
in 1997.  In return, the Company has agreed, under certain 
circumstances, to shift up to 40 megawatts of the Schedule C3 deliveries 
from the NEPOOL/Hydro-Quebec interconnection facilities to alternate 
transmission paths, using the freed-up transmission path for an 
incremental purchase.  The Company will purchase an annual minimum 
quantity of energy for the Company's use or resale for the period of 
September 1996 through June 2001.  The purchase price will vary based 
upon conditions in effect when the purchases are made, or on the resale 
conditions at the time.  Should the Company not satisfy its obligation 
to purchase the quantity of energy in any calendar year, it must pay a 
cancellation fee or rollover its residual purchase obligation into the 
succeeding calendar year period.  Although the level of benefits to the 
Company will depend on various factors, the Company estimates that the 
January 1996 Agreement will provide a minimum benefit of $1.8 million on 
a net present value basis.  During 1997, the Company purchased or sold 
to others, 51.4 percent of the minimum purchase obligation for that 
year.  The Company will not rollover the balance of purchase obligations 
into 1998, but instead will pay a cancellation fee.

     Under an agreement executed on December 5, 1997, Hydro-Quebec 
provided a cash payment of $8.0 million to the Company in 1997.  In 
return for this payment, the Company is providing Hydro-Quebec with the 
choice of selecting one of two alternatives by April 1, 1998, described 
below:
Alternative A:  For the period commencing November 1, 1997 and effective 
through the remaining term of the 1987 Contract, which expires in 2015, 
Hydro-Quebec can exercise an option to purchase up to 105,000 MWh on an 
annual basis, at energy prices established in accordance with the 1987 
Contract, for an amount of energy equivalent to the Company's firm 
capacity entitlements in the 1987 Contract.  The cumulative amount of 
energy purchased over the remaining term of the 1987 Contract may not 
exceed 1,900,000 MWh.  Hydro-Quebec may not exercise its annual rights 
to purchase power in the amounts specified under an arrangement made in 
November 1996 during those years in which Hydro-Quebec exercises its 
rights to curtail energy deliveries in accordance with the July 1994 
Agreement. 
Alternative B:  For the period commencing November 1, 1997 and effective 
through the remaining term of the 1987 Contract, Hydro-Quebec can 
exercise an option to purchase up to 52,500 MWh on an annual basis, at 
energy prices established in accordance with the 1987 Contract, for an 
amount of energy equivalent to the Company's firm capacity entitlements 
in the 1987 Contract.  The cumulative amount of energy purchased over 
the remaining term of the 1987 Contract shall not exceed 950,000 MWh.  
Unlike Alternative A, Hydro-Quebec's option to curtail energy deliveries 
pursuant to the July 1994 Agreement can be exercised in addition to the 
purchase option under Alternative B.  Finally, for the period commencing 
January 1, 1998 and effective though the remaining term of the 1987 
Contract under Alternative B, Hydro-Quebec can exercise an option on an 
annual basis to purchase up to 600,000 MWh at the 1987 Contract energy 
price. Hydro-Quebec can purchase no more than 200,000 MWh in any given 
year. Under modifications agreed to by Hydro-Quebec and the Company, 
Hydro-Quebec has until April 1, 1998 to elect either Alternative A or B.

     Consistent with an accounting order from the VPSB issued on 
December 31, 1996, the $8.0 million payment was recognized in income in 
1997.  However, it was necessary to change the accounting treatment 
subsequently based on an order issued by the VPSB in March 1998, 
resulting in the amortization of the $8 million over the life of the 
contract.  The Company intends to appeal or request reconsideration of 
this decision.  (See Note I of the Notes to Consolidated Financial 
Statements.)


 
               REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS



To the Board of Directors of
Green Mountain Power Corporation:

We have audited the accompanying consolidated balance sheets and 
capitalization data of Green Mountain Power Corporation (a Vermont 
corporation) as of December 31, 1997 and 1996, and the related 
consolidated statements of income and cash flows for each of the three 
years in the period ended December 31, 1997.  These financial statements 
are the responsibility of the Company's management.  Our responsibility 
is to express an opinion on these financial statements based on our 
audits.

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

As discussed in Note I.6, on March 2, 1998, the Company received a rate 
order from the Vermont Public Service Board (the VPSB) allowing for a 
$5.6 million increase in annual revenue in response to the Company's 
request for a $22 million increase in annual revenue.  The Company is 
exploring all legal and regulatory remedies open to it to challenge the 
correctness of the VPSB's decision.  The VPSB's ruling, if not changed, 
would have a significant adverse impact on the company's reported 
financial condition and 1998 results of operations and, depending on 
future proceedings to be conducted by the VPSB, could impact the 
Company's financial viability.

In our opinion, the consolidated financial statements referred to above 
present fairly, in all material respects, the financial position of 
Green Mountain Power Corporation as of December 31, 1997 and 1996, and 
the consolidated results of its operations and its cash flows for each 
of the three years in the period ended December 31, 1997, in conformity 
with generally accepted accounting principles.


/s/ ARTHUR ANDERSEN LLP



Boston, Massachusetts
February 2, 1998 (except with respect to the matter discussed in Note 
I.6, as to which the date is March 2, 1998)


Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1997, 1996 and 1995

<TABLE>
<CAPTION>

                                                                  Additions
                                        Balance at      -------------------------------                    Balance at
                                       Beginning of       Charged to       Charged to                        End of
Description                               Period        Cost & Expenses  Other Accounts    Deductions        Period
-----------------------------------    -------------    --------------   --------------   -------------   -------------
<S>                                        <C>               <C>           <C>                <C>             <C>
Injuries and Damages
  1997.................................    $237,892          $427,546      $   --               $1,653        $663,785
  1996.................................    $103,301          $572,000      $   --             $437,409        $237,892
  1995.................................    $513,720           $38,000      $   --             $448,419        $103,301


Bad Debt Reserve (2)
  1997.................................    $498,024          $637,010         $173,899 (1)    $815,528        $493,405
  1996.................................    $417,684          $677,272          $72,344 (1)    $669,276        $498,024
  1995.................................    $402,923          $371,564          $48,696 (1)    $405,499        $417,684

(1) Represents collection of accounts previously written off.
(2) Includes non-utility bad debt reserve.


</TABLE>


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

     None


                                 PART III

ITEMS 10, 11, 12 & 13

     Certain information regarding executive officers called for by Item 
10, "Directors and Executive Officers of the Registrant," is furnished 
under the caption, "Executive Officers" in Item 1 of Part I of this 
Report.  The other information called for by Item 10, as well as that 
called for by Items 11, 12, and 13, "Executive Compensation," "Security 
Ownership of Certain Beneficial Owners and Management" and "Certain 
Relationships and Related Transactions," will be set forth under the 
captions "Election of Directors," "Board Compensation, Other 
Relationship, Meetings and Committees," "Section 16(a) Beneficial 
Ownership Reporting Compliance," "Executive Compensation," "Compensation 
Committee Report on Executive Compensation," "Performance Graphs," 
"Pension Plan Information" and "Securities Ownership of Certain 
Beneficial Owners and Management" in the Company's definitive proxy 
statement relating to its annual meeting of stockholders to be held on 
May 15, 1997.  Such information is incorporated herein by reference.  
Such proxy statement pertains to the election of directors and other 
matters.  Definitive proxy materials will be filed with the Securities 
and Exchange Commission pursuant to Regulation 14A in April 1997.


                                  PART IV

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

     A report on Form 8-K was filed on March 12, 1998 setting forth the 
financial and accounting implications for the Company resulting from the 
Vermont Public Service Board's Order in the Company's rate case.

                                                                   Filed
                                                                 Herewith
                                                                 On Page 

     Item 14(a)(1).  The financial statements and financial           42
statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.

<TABLE>
<CAPTION>

ITEM 14 (a) (3).                 EXHIBITS

<S>                                                                  <C>         <C>
                                                                 Incorporated by Reference from
Exhibit                                                                           SEC Docket or
Number                                                            Exhibit     Page Filed Herewith
-------    -----------------------------------------------        -------     -------------------
3-a        Restated Articles of Association, as certified            3-a         Form 10-K 1993
             June 6, 1991.                                                       (1-8291)

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

3-a-2      Amendment to 3-a above, dated as of October 11, 1996.     3-a-2       Form 10-Q Sept. 1996
                                                                                 (1-8291)

3-b        By-laws of the Company, as amended                        3-b         Form 10-K 1996
             February 10, 1997.                                                  (1-8291)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

4-b-16     Sixteenth Supplemental Indenture dated as of              4-b-16     Form 10-K 1995
              December 1, 1995.                                                 (1-8291)

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

*4-b-18    Credit Agreement by and among Green Mountain Power        4-b-18
              The Bank of Nova Scotia, State Street Bank and 
              Trust Company, Fleet National Bank, and Fleet
              National Bank, as Agent

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



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

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

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

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

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

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

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

10-b-6     Guarantee Agreement, dated November 5, 1981,              10-b-6         2-75293
             of the Company for its proportionate share 
             of the obligations of Vermont Yankee Nuclear 
             Power Corporation under a $40 million loan
             arrangement.

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

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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

10-b-64    Sales Agreement dated as of June 20, 1986,                10-b-64        33-8164
             between the Company and Fitchburg Gas and 
             Electric Light Company for sale of 10 MW 
             capacity and energy from the Vermont Yankee 
             plant.

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

10-d-5a    Severance Agreements with D. G. Hyde, E. M. Norse,        10-d-5a     Form 10-K 1990
             C. L. Dutton, S. C. Terry and T.C. Boucher.                         (1-8291)

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

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

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

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

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

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

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

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

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

*10-d-15b  Green Mountain Power Corporation Compensation Program     10-d-15b
            for Officers and Key Management Personnel as amended
            August 4, 1997

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

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

10-d-18    Severance Agreement with R. B. Hieber                     10-d-18     Form 10-K 1996
                                                                                 (1-8291)

10-d-19    Severance Agreement with R. J. Griffin                    10-d-19     Form 10-K 1996
                                                                                 (1-8291)

10-d-20    Severance Agreement with K. W. Hartley                    10-d-20     Form 10-K 1996
                                                                                 (1-8291)

21         Subsidiaries of the Registrant                            21          Form 10-K 1996
                                                                                 (1-8291)

*23-a-1    Consent of Arthur Andersen LLP

*24        Power of Attorney

*27        Financial Data Schedule

____________________
* Filed herewith

</TABLE>

ITEM 14(b)	

	A report on Form 8-K was filed on March 12, 1998 setting forth the 
financial and accounting implications for the Company resulting from the 
Vermont Public Service Board's Order in the Company's rate case.


                                SIGNATURES

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

                                           GREEN MOUNTAIN POWER CORPORATION


                                       By:   /s/ Christopher L. Dutton      
                                             _________________________
                                             Christopher L. Dutton, President
                                             and Chief Executive Officer

Date:  March 26, 1998

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

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


 /s/ Christopher L. Dutton    President and Director              March 26, 1998
     Christopher L. Dutton    (Principal Executive Officer)

 /s/ Edwin M. Norse           Vice President, Treasurer and       March 26, 1998
     Edwin M. Norse           Chief Financial Officer (Principal 
                              Financial Officer)

 /s/ Robert J. Griffin        Controller                          March 26, 1998
     Robert J. Griffin        (Principal Accounting Officer)

     *Thomas P. Salmon        Chairman of the Board 

     *Nordahl L. Brue         )

    *William H. Bruett        )

     *Merrill O. Burns        )

  *Lorraine E. Chickering     )

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

     *Euclid A. Irving        )

    *Martin L. Johnson        )

      *Ruth W. Page           )

*By: /s/ Christopher L. Dutton_                                  March 26, 1998
     Christopher L. Dutton
     (Attorney - in - Fact)


                       REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS



To the Board of Directors of
Green Mountain Power Corporation:

We have audited, in accordance with generally accepted auditing 
standards, the consolidated financial statements of Green Mountain Power 
Corporation included in this Form 10-K and have issued our report 
thereon dated February 2, 1998.  Our audit was made for the purpose of 
forming an opinion on the basic financial statements taken as a whole.  
The schedule listed in the index on page 42 of this Form 10-K is the 
responsibility of the Company's management and is presented for purposes 
of complying with the Securities and Exchange Commission's rules and is 
not part of the basic consolidated financial statements.  This schedule 
has been subjected to the auditing procedures applied in the audit of 
the basic consolidated financial statements, and in our opinion, fairly 
states, in all material respects, the financial data required to be set 
forth therein in relation to the basic consolidated financial statements 
taken as a whole.



Boston, Massachusetts
February 2, 1998               /s/  Arthur Andersen LLP