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, 1998

                      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 12, 1999, was $55,551,767.19 
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 12, 1999, 
was 5,322,325.


                   DOCUMENTS INCORPORATED BY REFERENCE

	The Company's Definitive Proxy Statement relating to its Annual 
Meeting of Stockholders to be held on May 20, 1999, 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.  We serve approximately 83,500 customers.  The Company was 
incorporated under the laws of the State of Vermont on April 7, 1893.

     Our sources of revenue for the year ended December 31, 1998 were as 
follows:
     33.5% from residential customers,
     33.5% from small commercial and industrial customers,
     21.8% from large commercial and industrial customers,
      9.0% from sales to other utilities, and
      2.2% from other sources.  

     During 1998, our energy resources for retail and wholesale sales of 
electricity were obtained as follows: 
     44.0% from hydroelectric sources (7.8% Company-owned, 0.1% New York    
              Power Authority (NYPA), 32.8% Hydro-Quebec and 3.3% small 
              power producers),
     27.5% from a nuclear generating source (the Vermont Yankee nuclear 
              plant described below), 
      2.0% from coal sources,
      3.5% from wood,
      2.4% from natural gas,
      1.5% from oil, and
      0.6% from wind.  
The remaining 18.5% was purchased on a short-term basis from other 
utilities through the New England Power Pool (NEPOOL).

     In 1998, we purchased 91.4% of the energy required to satisfy our 
retail and wholesale sales of electricity (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 our 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).  We have a 17.9% equity interest in 
Vermont Yankee.  For information concerning Vermont Yankee, see "Power 
Resources - Vermont Yankee."

     We participate in NEPOOL, a regional bulk power transmission 
organization established to assure reliable and economical power supply 
in the Northeast.  Our representative to NEPOOL is Vermont Electric 
Power Company, Inc. (VELCO), a transmission consortium owned by the 
Company and other Vermont utilities, in which we have a 30% equity 
interest.  As a member of NEPOOL, we benefit from increased efficiencies 
of centralized economic dispatch, availability of replacement power for 
scheduled and unscheduled outages of our own power sources, sharing of 
bulk transmission facilities and reduced generation reserve 
requirements.

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

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

     Our largest customer is International Business Machines (IBM).  
Electric energy sales to IBM for the years ended December 31, 1998, 1997 
and 1996, accounted for 14.7%, 14.0% and 13.2%, respectively, of our 
operating revenues in those years.  No other retail customer accounted 
for more than 1.0% of our revenue.  Under the present regulatory system, 
the loss of IBM as a customer would require the Company to seek rate 
relief to recover the revenues previously paid by IBM from other 
customers in an amount sufficient to offset the fixed costs that IBM had 
been covering through its payments.


                               EMPLOYEES

     As of December 31, 1998, the Company had 288 employees, exclusive 
of temporary employees, and our subsidiary, Mountain Energy Inc., had 
six employees.


                      SEASONAL NATURE OF BUSINESS

      Winter recreational activities, longer hours of darkness and 
heating loads from cold weather usually cause our peak electric sales to 
occur in December, January or February.  Our heaviest load in 1998 - 
312.5 MW - occurred on January 14, 1998.  

      We charge our customers higher rates for billing cycles in 
December through March and lower rates for the remaining months.  These 
are called "seasonally differentiated rates".  In order to eliminate the 
impact of the seasonally differentiated rates on earnings, we defer some 
of the revenues from those four months and account for them in later 
periods in which we have lower revenues or higher costs.  By deferring 
certain revenues we are able to match our revenues to our costs more 
accurately.

      Under this structure, retail electric rates produce average 
revenues per kilowatthour during four peak season months (December 
through March) that are approximately 30% higher than during the eight 
off-season months (April through November).  See "Energy Efficiency" and 
"Rate Design."

<TABLE>
<CAPTION>

OPERATING STATISTICS
For the Years Ended December 31
                                                          1998          1997          1996          1995          1994
                                                       ----------    ----------    ----------    ----------    ----------


<S>                                                        <C>           <C>           <C>           <C>           <C>
Net System Capability During Peak Month (MW)
  Hydro (1)............................................    174.8         180.0         193.8         152.1         179.0
  Lease transmissions..................................      0.6           0.6           0.6           0.3           2.1
  Nuclear (1)..........................................     95.7          95.7          95.7          81.9         107.2
  Conventional steam...................................     53.0          53.0          52.9          77.8          67.1
  Internal combustion..................................     49.0          64.0          60.7          62.0          60.2
  Combined cycle.......................................     22.1          22.1          22.1          22.0          22.6
  Wind.................................................      1.7           1.5         --            --            --
                                                       ----------    ----------    ----------    ----------    ----------
    Total capability (MW)..............................    396.9         416.9         425.8         396.1         438.2
  Net system peak......................................    312.5         311.5         313.0         297.1         308.3
                                                       ----------    ----------    ----------    ----------    ----------
  Reserve (MW).........................................     84.4         105.4         112.8          99.0         129.9
                                                       ==========    ==========    ==========    ==========    ==========
  Reserve % of peak....................................     27.0%         33.8%         36.0%         33.3%         42.1%

Net Production (MWH)
  Hydro (1)............................................  972,723     1,073,246     1,192,881     1,043,617       742,088
  Lease transmissions..................................    --            --            --            --            --
  Nuclear (1)..........................................  607,708       772,030       680,613       682,814       763,690
  Conventional steam...................................  750,602       560,504       705,331       673,982       651,105
  Internal combustion..................................   40,148         4,827         2,674         6,646         3,532
  Combined cycle.......................................  118,322       104,836        51,162        92,723        37,808
                                                       ----------    ----------    ----------    ----------    ----------
    Total production...................................2,489,503     2,515,443     2,632,661     2,499,782     2,198,223
  Less non-requirements sales to other utilities.......  499,409       524,192       663,175       582,942       328,794
                                                       ----------    ----------    ----------    ----------    ----------
  Production for requirements sales....................1,990,094     1,991,251     1,969,486     1,916,840     1,869,429
  Less requirements sales & lease transmissions (MWH)..1,883,959     1,870,913     1,814,371     1,760,830     1,730,497
                                                       ----------    ----------    ----------    ----------    ----------
  Losses and company use (MWH).........................  106,135       120,338       155,115       156,010       138,932
                                                       ==========    ==========    ==========    ==========    ==========
Losses as a percentage of total production.............     4.26%         4.78%         5.89%         6.24%         6.32%
System load factor (2).................................     71.8%         71.6%         69.7%         71.2%         67.7%

Sales and Lease Transmissions (MWH)
  Residential - GMP....................................  533,904       549,259       557,726       549,296       564,635
  Lease transmissons...................................    --            --            --            --            --
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................  533,904       549,259       557,726       549,296       564,635
  Commercial & industrial - small......................  665,707       645,331       630,839       608,688       604,686
  Commercial & industrial - large......................  636,436       608,051       584,249       556,278       521,400
  Other................................................    3,476         3,939         2,898         8,855         1,146
                                                       ----------    ----------    ----------    ----------    ----------
    Total retail sales and lease transmissions.........1,839,522     1,806,580     1,775,712     1,723,117     1,691,867
  Sales to municipals and cooperatives                    44,437        64,333        38,659        37,713        38,630
                                                       ----------    ----------    ----------    ----------    ----------
    Total requirements sales...........................1,883,959     1,870,913     1,814,371     1,760,830     1,730,497
  Other sales for resale...............................  499,409       524,192       663,175       582,942       328,794
                                                       ----------    ----------    ----------    ----------    ----------
    Total sales and lease transmissions................2,383,368     2,395,105     2,477,546     2,343,772     2,059,291
                                                       ==========    ==========    ==========    ==========    ==========

Average Number of Electric Customers
  Residential..........................................   71,301        70,671        70,198        69,659        68,811
  Commercial and industrial - small....................   12,170        11,989        11,828        11,712        11,611
  Commercial and industrial - large....................       23            23            25            24            24
  Other................................................       70            75            75            76            76
                                                       ----------    ----------    ----------    ----------    ----------
    Total..............................................   83,564        82,758        82,126        81,471        80,522
                                                       ==========    ==========    ==========    ==========    ==========


Average Revenue per KWH (Cents)
  Residential including lease revenues.................    11.56         11.18         10.87         10.09          9.03
  Lease charges........................................      --            --            --            --            --
                                                       ----------    ----------    ----------    ----------    ----------
    Total Residential..................................    11.56         11.18         10.87         10.09          9.03
  Commercial and industrial - small....................     9.29          9.10          8.96          8.42          8.00
  Commercial and industrial - large....................     6.32          6.22          6.28          5.86          6.02
  Total retail including lease revenues................     8.96          8.94          8.92          8.36          7.96


Average Use and Revenue Per Residential Customer
  Kilowatt hours including lease transmissions.........    7,488         7,772         7,945         7,885         8,206
  Revenues including lease revenues....................     $865          $869          $863          $796          $741


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

     Our rate tariffs are uniform throughout our service area.  We have 
entered into a number of jobs incentive agreements, providing for 
reduced capacity charges to large customers applicable only to new load.  
We have an economic development agreement with IBM that provides for 
contractually established charges, rather than tariff rates, for 
incremental loads.  See Item 7. Management's Discussion and Analysis of 
Financial Condition and Results of Operations - "Results of Operations - 
Operating Revenues and MWh Sales."

     Our wholesale rate on sales to two wholesale customers is regulated 
by the Federal Energy Regulatory Commission (FERC).  Revenues from sales 
to these customers were approximately 0.9% of operating revenues for 
1998.

     Late in 1989, we began serving a municipal utility, Northfield 
Electric Department, under our wholesale tariff.  This customer 
increased our electricity sales in 1998 by approximately 24,064.6 MWh 
and peak requirements by approximately 5.5 MW.  Revenues in 1998 from 
Northfield were $1,462,549.

     We provide transmission service to twelve customers within the 
State under rates regulated by the FERC; revenues for such services 
amounted to less than 1.0% of the Company's operating revenues for 1998.

     On April 24, 1996, the FERC issued Orders 888 and 889 that among 
other things required the filing of open access transmission tariffs by 
electric utilities.  See Item 7. Management's Discussion and Analysis Of 
Financial Condition And Results Of Operations - "Transmission Issues - 
Federal Open Access Tariff Orders."  NEPOOL's Open Access tariff for 
certain transmission facilities, including certain facilities between 
New York and New England, incorporates a load-based method of capacity 
allocation for NEPOOL transmission facilities.  The Open Access tariff 
could reduce the amount of capacity available to the Company from such 
facilities in the future.  See Item 7.  Management's Discussion and 
Analysis Of Financial Condition and Results Of Operations - 
"Transmission Issues - NEPOOL Transmission Tariff."

     The Company has equity interests in Vermont Yankee, VELCO and 
Vermont Electric Transmission Company, Inc. (VETCO), a wholly owned 
subsidiary of VELCO.  We have filed an exemption statement under Section 
3(a)(2) of the Public Utility Holding Company Act of 1935, thereby 
securing exemption from the provisions of such Act, except for Section 
9(a)(2), which prohibits the acquisition of securities of certain other 
utility companies without approval of the Securities and Exchange 
Commission (SEC).  The SEC has the power to institute proceedings to 
terminate such exemption for cause.



     Licensing.  Pursuant to the Federal Power Act, the FERC has granted 
licenses for the following hydro-electric projects owned by the Company:

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

     The relicensing application for Vergennes is on file with the FERC 
and the relicensing application for Waterbury is being prepared for 
filing.  We expect both projects to be relicensed for a 30 year term in 
the near future and does not have any competition for the licenses.

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

     In June 1996, we filed with the VPSB and the Department an 
integrated resource plan pursuant to Vermont Statute 30 V.S.A. Section 218c.  
That filing is still pending before the VPSB.


                        RECENT RATE DEVELOPMENTS

     On May 8, 1998, we filed a request with the VPSB to increase retail 
rates by 12.9 percent.  The retail rate increase is needed to cover 
higher power supply costs, the cost of the January 1998 ice storm, 
higher taxes and investments in new plant and equipment.  

     On November 18, 1998, by Memorandum of Understanding (MOU), the 
Company, the Department and IBM agreed to:
 -	implementation of a temporary rate increase of 5.7 percent, 
effective December 15, 1998, with the potential for an additional 
surcharge in order to produce additional revenues necessary to 
provide the Company with the capacity to finance estimated 1999 
Pine Street Barge Canal site expenditures of $5.8 million, and
 -	to stay, effective November 16, 1998, further rate proceedings in 
this rate case until or after September 1, 1999, or such earlier 
date to which the parties may later agree or the VPSB may order.  
For further information regarding recent rate developments, see 
Item 7. Management's Discussion and Analysis Of Financial 
Condition and Results Of Operations - "Liquidity and Capital 
Resources" and Note I 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 utility industry to facilitate competition 
for electricity sales at wholesale and retail levels.  For further 
information regarding Competition and Restructuring, See Item 7. 
Management's Discussion and Analysis of Financial Condition and Results 
of Operations - "Future Outlook."

                               POWER RESOURCES

     The Company has agreed to enter into a contract with Morgan Stanley 
Capital Group, Inc. as the result of our all power requirements 
solicitation in 1998.  See Note L of Notes to Consolidated Financial 
Statements "Power Purchase and Supply Agreement".

     The Company generated, purchased or transmitted 1,977,647.5 MWh of 
energy for retail and requirements wholesale customers for the twelve 
months ended December 31, 1998.  The corresponding maximum one-hour 
integrated demand during that period was 312.5 MW on January 14, 1998.  
This compares to the all-time peak of 322.6 MW on December 27, 1989.  
The following table shows the net generated and purchased energy, the 
source of such energy for the twelve-month period and the capacity in 
the month of the period system peak.  See Note K of Notes to 
Consolidated Financial Statements.

                         


                                   Net Generated and      Net Generated and
                                   Purchased in Year      Purchased at Time
                                   Ended 12/31/98 (a)       of Annual Peak
                                  ___________________    ___________________
                                     MWh         %           KW          %
WHOLLY OWNED PLANTS
  Hydro . . . . . . . . . . . . .  162,358.0    7.8        35,310       8.9
  Diesel and Gas Turbine  . . . .    4,647.8    0.2        46,030      11.6
  Searsburg . . . . . . . . . . .   12,886.3    0.6         1,690       0.4

JOINTLY OWNED PLANTS
  Wyman #4  . . . . . . . . . . .   14,144.5    0.7         7,030       1.8
  Stony Brook I . . . . . . . . .   21,471.3    1.0         7,990       2.0
  McNeil  . . . . . . . . . . . .   14,192.3    0.7         6,450       1.6

OWNED IN ASSOCIATION W/OTHERS
  Vermont Yankee Nuclear  . . . .  571,407.1   27.5        95,680      24.1

NYPA LEASE TRANSMISSIONS
  State of Vermont (NYPA) . . . .    1,650.3    0.1           620       0.2

LONG-TERM PURCHASES
  Hydro-Quebec  . . . . . . . . .  682,197.0   32.8       121,690      30.7
  Merrimack #2  . . . . . . . . .   40,721.1    2.0        31,820       8.0
  Stony Brook I   . . . . . . . .   41,679.7    2.0        14,150       3.6
  Small Power Producers . . . . .  126,507.7    6.1        24,650       6.2

SHORT-TERM PURCHASES  . . . . . .  386,926.4   18.5         3,860        .9
                                 ___________   ____       _______     _____
                                 
  Less System Sales Energy  . . . (103,142.0)                   

  NET OWN LOAD  . . . . . . . .  1,977,647.5  100.0       396,970     100.0
                                 ===========  ======      =======    ======
(a) Excludes losses on off-system purchases, totaling 24,189 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 our power contract, we 
are required to pay 20% of Vermont Yankee's operating expenses 
(including depreciation and taxes), fuel costs (including charges in 
respect of estimated costs of disposal of spent nuclear fuel), 
decommissioning expenses, interest expense and return on common equity, 
whether or not the Vermont Yankee plant is operating.  In 1969, we sold 
to other Vermont utilities a share of our entitlement to the output of 
Vermont Yankee.  Accordingly, those utilities have an aggregate 
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 us.  
Accordingly, those utilities have an obligation to pay us 2.338% of 
Vermont Yankee's operating expenses, fuel costs, decommissioning 
expenses, interest expense and return on common equity, whether or not 
the Vermont Yankee plant is operating.

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

     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.

The NRC's most recently issued Systematic Assessment of Licensee
Performance scores for Vermont Yankee are for the period January 19, 1997
to July 18, 1998.  Operations, engineering, maintenance and plant
support were rated good.  These scores were identical to Vermont Yankee's
scores for the prior 18 month-period except for plant support, which
declined from superior.  

     During periods when Vermont Yankee is unavailable, we incur 
replacement power costs in excess of those costs that we would have 
incurred for power purchased from Vermont Yankee.  Replacement power is 
available to us from NEPOOL and through contractual arrangements with 
other utilities.  Replacement power costs adversely affect cash flow 
and, absent deferral, amortization and recovery through rates, would 
adversely affect reported earnings.  Routinely, in the case of scheduled 
outages for refueling, the VPSB has permitted the Company to defer, 
amortize and recover these excess replacement power costs for financial 
reporting and rate making purposes over the period until the next 
scheduled outage.  Vermont Yankee has adopted an 18-month refueling 
schedule.  On March 21, 1998, Vermont Yankee began a scheduled refueling 
outage, which concluded June 3, 1998.  The 1999 refueling outage is 
scheduled to begin October 29, 1999.  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 $407 million, of which $260 million has been 
funded. Vermont Yankee is in the process of preparing an updated site 
decommissioning cost study.  Preliminary results indicate that the 
revised estimate could exceed $500 million in 1998 dollars.  Vermont 
Yankee is required to file the results of the new study with the FERC by 
March 31, 1999, and expects that any resulting change in rates will be 
effective January 1, 2000. At December 31, 1998, our portion of the net 
non-funded liability was $26 million, which we expect will be recovered 
through rates over Vermont Yankee's remaining operating life.

     During 1998, we incurred $27.2 million in Vermont Yankee annual 
capacity charges, which included $2 million for interest charges.  Our 
share of Vermont Yankee's long-term debt at December 31, 1998 was $16.7 
million.

     During the year ended December 31, 1998, we utilized 571,407.1 MWh 
of Vermont Yankee energy to meet 27.5% of our retail and requirements 
wholesale (Rate W) sales.  The average cost of Vermont Yankee 
electricity in 1998 was 5.7 cents per KWh.  Vermont Yankee's annual capacity 
factor for 1998 was 73.6%, compared to 93.5% in 1997 and 83.0% in 1996.  
The decrease in capacity was due to plant outages. 

     The Price-Anderson Act currently sets the statutory limit of 
liability from a single incident at a nuclear power plant at $9.8 
billion.  Any damages beyond $9.8 billion are indemnified under the 
Price-Anderson Act, but subject to Congressional approval.  The first 
$200 million of liability coverage is the maximum provided by private 
insurance.  The Secondary Financial Protection Program is a 
retrospective insurance plan providing additional coverage up to $9.6 
billion per incident by assessing each of the 109 reactor units that are 
currently subject to the Program in the United States a total of $88.1 
million, limited to a maximum assessment of $10 million per incident per 
nuclear unit in any one year.  The maximum assessment is adjusted at 
least every five years to reflect inflationary changes.

     The above insurance 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.  
However, Vermont Yankee does 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.  

See Note L-3 of Notes to Consolidated Financial Statements. 

HYDRO-QUEBEC

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

     NEPOOL/Hydro-Quebec Interconnection.  VELCO and certain other 
NEPOOL members have entered into agreements with Hydro-Quebec 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 
competitive prices; 
- 	energy banking, under which participating New England utilities 
will transmit relatively inexpensive energy to Hydro-Quebec 
during off-peak periods and will receive equal amounts of energy, 
after adjustment for transmission losses, from Hydro-Quebec 
during peak periods when replacement costs are higher; and 
- 	provision for emergency transfers and mutual backup to improve 
reliability for both the Hydro-Quebec system and the New England 
systems.

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

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

     Phase II.  Agreements executed in 1985 among the Company, VELCO and 
other NEPOOL members and Hydro-Quebec provided for the construction of 
the second phase (Phase II) of the interconnection between the New 
England Electric System and that of Hydro-Quebec.  Phase II 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, 1998, the 
present value of the Company's obligation was $7,696,336.  The Company's 
projected future minimum payments under the Phase II support agreements 
are $452,726 for each of the years 1999-2003 and an aggregate of 
$5,432,706 for the years 2004-2020.  

     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, 1998, the capital structure 
of such corporations was 41% common equity and 59% long-term debt.  See 
Note J of Notes to Consolidated Financial Statements.

     At times, we request that portions of our power deliveries from 
Hydro-Quebec and other sources be routed through New York.  Our ability 
to do so could be adversely affected by the proposed tariff that NEPOOL 
has filed with the FERC, which would reduce our allocation of capacity 
on transmission interfaces with New York.  As a result, our ability to 
import power to Vermont from outside New England could be adversely 
affected, thereby impacting our power costs in the future.  See Item 7. 
Management's Discussion and Analysis Of Financial Condition and Results 
Of Operations - "Transmission Issues" and Note J of Notes to 
Consolidated Financial Statements. 

     Hydro-Quebec Power Supply Contracts.  We have several purchase 
power contracts with Hydro-Quebec.  The bulk of our purchases are 
comprised of two schedules, B and C3, pursuant to a Firm Contract dated 
December 1987.  Under these two schedules, we purchase 114.2 MW.  Under 
an arrangement negotiated in January 1996, the HQ 9601 and the HQ 9602 
contracts, we received cash payments from Hydro-Quebec of $3,000,000 in 
1996 and  $1,100,000 in 1997.  In accordance with such arrangement, we 
agreed to shift certain transmission requirements, purchase certain 
quantities of power and make certain minimum payments for periods in 
which power is not purchased.  In addition, in November 1996, we entered 
into a Memorandum of Understanding with Hydro-Quebec under which Hydro-
Quebec paid $8,000,000 to the Company in exchange for certain power 
purchase elections.  See Item 7. Management's Discussion And Analysis Of 
Financial Condition and Results Of Operations - "Power Supply Expenses" 
and Notes J and K-2 of Notes to Consolidated Financial Statements.

     In 1998, we utilized 351,012.6 MWh under Schedule B, 260,329.3 MWh 
under Schedule C3, and 70,855.1 MWh under HQ 9601 and HQ 9602 to meet 
32.8% of our retail and requirements wholesale sales.  The average cost 
of Hydro-Quebec electricity in 1998 was 6.8 cents per KWh.

     New York Power Authority (NYPA).  The Department allocates NYPA 
power to us, which, in turn, we deliver to our residential and farm 
customers.  We purchased at wholesale 1,650.3 MWh to meet 0.1% of our 
retail and requirements wholesale sales of NYPA power at an average cost 
of 5.0 cents per KWh in 1998.

     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.  We were entitled to 31.05 MW of capacity and 
related energy from the unit under a 30-year contract that expired May 
1, 1998.  

     In 1998, we utilized 40,721.1 MWh from the unit to meet 2.0% of our 
total retail and requirements wholesale sales.  The average cost of 
electricity from this unit was 5.7 cents per KWh in 1998.  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.  
We entered into a Joint Ownership Agreement with MMWEC dated as of 
October 1, 1977, whereby we acquired an 8.8% ownership share of the 
plant, entitling us to 31.0 MW of capacity.  In addition to this 
entitlement, we have contracted for 14.2 MW of capacity for the life of 
the Stony Brook I plant, for which we will pay a proportionate share of 
MMWEC's share of the plant's fixed costs and variable operating 
expenses.  The three units that comprise Stony Brook I are all capable 
of burning oil.  Two of the units are also capable of burning natural 
gas.  The natural gas system at the plant was modified in 1985 to allow 
two units to operate simultaneously on natural gas.

     During 1998, we utilized 63,151.0 MWh from this plant to meet 3.0% 
of our retail and requirements wholesale sales at an average cost of 
4.2 cents.  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.  
Central Maine Power Company sponsored the construction of this plant.  
We have a joint-ownership share of 1.1% (7.1 MW) in the Wyman #4 unit, 
which began commercial operation in December 1978.

     During 1998, we utilized 14,144.5 MWh from this unit to meet 0.7% 
of our retail and requirements wholesale sales at an average cost of 
2.4 cents per kWh, based only on operation, maintenance, and fuel costs 
incurred during 1998.  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.  We have an 11.0% or 5.8 MW interest in the J. C. 
McNeil plant, which began operation in June 1984.  In 1989, the plant 
added the capability to burn natural gas on an as-
available/interruptible service basis.

     During 1998, we utilized 14,192.3 MWh from this unit to meet 0.7% 
of our retail and requirements wholesale sales at an average cost of 
4.7 cents per kWh, based only on operation, maintenance, and fuel costs 
incurred during 1998.  See Note I-4 of Notes to Consolidated Financial 
Statements.

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

     Currently, the State purchasing agent, Vermont Electric Power 
Producers, Inc. (VEPPI), is authorized to seek 150 MW of power from 
qualifying facilities under PURPA, of which our average pro rata share 
in 1998 was approximately 32.9% or 49.3 MW.

     The rated capacity of the qualifying facilities currently selling 
power to VEPPI is approximately 74.5 MW.  These facilities were all 
online by the spring of 1993, and no other projects are under 
development.  We do not expect any new projects to come online in the 
foreseeable future because the excess capacity in the region has 
eliminated the need for and value of additional qualifying facilities.

     In 1998, through both our direct contracts and VEPPI, we purchased 
126,507.7 MWh of qualifying facilities production to meet 6.1% of our 
retail and requirements wholesale sales at an average cost of 10.9 cents per 
KWh.

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

     During 1998, we purchased 386,926.4 MWh, meeting 18.5% of our 
retail and requirements wholesale sales, at an average cost of 2.7 cents per 
kWh.

     NEPOOL.  As a participant of NEPOOL, through VELCO, we take 
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 us to maintain a generating 
capacity reserve as set by NEPOOL, but which is lower than the reserve 
which would be required if we 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 
7.8 MW.  

     In 1998, these plants provided 162.358 MWh of low-cost energy, 
meeting 7.8% of our retail and requirements wholesale sales at an 
average cost of 3.3 cents per kWh, based on total embedded costs.  See "State 
and Federal Regulation" - "Licensing."

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

     Long-Term Power Sales.  In 1986, we entered into an agreement for 
the sale to United Illuminating of 23 MW of capacity produced by the 
Stony Brook I combined-cycle plant and provided for our recovery of all 
costs associated with the capacity and energy sold.  The agreement 
commenced October 1, 1986 and expired October 31, 1998.

     Fuel.  During 1998, our retail and requirements wholesale sales 
were provided by the following fuel sources:  
     44.0% from hydro (7.8% Company-owned, 0.1% NYPA, 32.8% Hydro-Quebec and
           3.3% from small power producers), 
     27.5% from nuclear, 
      2.0% from coal, 
      3.5% from wood, 
      2.4% from natural gas, 
      1.5% from oil, 
      0.6% from wind, and
     18.5% purchased on a short-term basis from other utilities through
           NEPOOL.

     Vermont Yankee has several "requirement based" contracts for the 
four components (uranium, conversion, enrichment and fabrication) used to 
produce nuclear fuel.  These contracts are executed only if the need or 
requirement for fuel arises.  Under these contracts, any disruption of 
operating activity would allow Vermont Yankee to cancel or postpone 
deliveries until actually required.  The contracts extend through 
various time periods and contain clauses to allow Vermont Yankee the 
option to extend the agreements.  Negotiation of new contracts and 
renegotiations of existing contracts routinely occurs, the latter often 
focuses on one of the four components.  The price of the 1998 reload was 
approximately $22 million.  The 1999 reload will also cost approximately 
$22 million.  Future reload costs will depend on market and contract 
prices

     On January 20, 1997, Vermont Yankee entered into an agreement with 
a former uranium supplier whereby the supplier could opt to terminate a 
production purchase agreement dated August 4, 1978.  Although there had 
been no transactions under the production purchase agreement for several 
years, Vermont Yankee maintained certain financial rights.  In 
consideration for the option to terminate the production purchase 
agreement and the subsequent exercise of the option, Vermont Yankee 
received $600,000 in 1997, which was recorded as an offset to nuclear 
fuel expense.  The potential future payments over a ten-year period 
range from zero to $2.4 million.  No payments were received in 1998 
under this agreement.  Due to the uncertainty of this transaction, any 
benefits received will be recorded on a cash basis.

     Vermont Yankee has a contract with the United States Department of 
Energy (DOE) for the permanent disposal of spent nuclear fuel.  Under 
the terms of this contract, in exchange for the one-time fee discussed 
below and a quarterly fee of 1 mil per kWh of electricity generated and 
sold, the DOE agrees to provide disposal services when a facility for 
spent nuclear fuel and other high-level radioactive waste is available, 
which is required by contract to be prior to January 31, 1998.  The 
actual date for these disposal services is expected to be delayed many 
years.  DOE currently estimates that a permanent disposal facility will 
not begin operation before 2010.  A DOE temporary disposal site may be 
provided in a few years, but no decision has been made to proceed on 
providing a temporary disposal site at this time. 

     The DOE contract obligates Vermont Yankee to pay a one-time fee of 
approximately $39.3 million for disposal costs for all spent fuel 
discharged through April 7, 1983.  Although such amount has been 
collected in rates from the Vermont Yankee participants, Vermont Yankee 
has elected to defer payment of the fee to the DOE as permitted by the 
DOE contract.  The fee must be paid no later than the first delivery of 
spent nuclear fuel to the DOE.  Interest accrues on the unpaid 
obligation based on the thirteen-week Treasury Bill rate and is 
compounded quarterly.  Through 1998, Vermont Yankee accumulated 
approximately $98 million 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.

     We do not maintain long-term contracts for the supply of oil for 
our wholly-owned oil-fired peaking unit generating stations (80 MW).  We 
did not experience difficulty in obtaining oil for our own units during 
1998, and, while no assurance can be given, we do not anticipate any 
such difficulty during 1999.  None of the utilities from which we expect 
to purchase oil- or gas-fired capacity in 1999 has advised us of grounds 
for doubt about maintenance of secure sources of oil and gas during the 
year.

     Merrimack #2 purchased coal 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 in 1998.  Our 
contract with Merrimack #2 expired May 1,1998.

      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 
233,312 tons of wood chips and mill residue and 181.9 million cubic feet 
of natural gas in 1998.  The McNeil plant is forecasting consumption of 
wood chips for 1999 to be 200,000 tons and natural gas consumption of 
136 million cubic feet.

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

      Wind Project.  Our 20 years of research and development work in 
wind generation was recognized in 1993 when we were selected by the 
DOE and the Electric Power Research Institute (EPRI) to build a commercial
scale wind-powered facility.  The DOE and EPRI provided partial funding
for the wind project of approximately $3.9 million.  The net cost to the
Company of the project, located in the southern Vermont town of Searsburg,
was $7.8 million.  The eleven wind turbines have a rating of 6 MW and were
commissioned July 1, 1997.

     In 1998, the plant provided 12,886.3 MWh, meeting 0.6% of our 
retail and requirements wholesale sales at an average cost of 7.0 cents cents 
per kWh. 

                            ENERGY EFFICIENCY

     In 1998, we continued to focus our energy efficiency services on 
programs that encouraged customers to install energy efficient equipment 
when they are planning to replace or buy new equipment rather than 
attempting to convince them to replace equipment that is still in good 
working order.  This strategy, along with careful management, has helped 
us to keep our cost-per-kilowatthour saved below 2 cents which is a 56% 
reduction in costs since 1992.  In 1998, our energy efficiency programs 
saved 8,320 megawatthours, 4% above targeted savings for the year.  
During the past eight years our efficiency programs have achieved a 
cumulative annual savings of 79,049 megawatthours, saving approximately 
$7 million per year for our customers.

     We continued to work with other Vermont utilities and the Vermont 
Department of Public Service to improve and expand a set of statewide 
demand side management programs.  This effort should reduce cost of 
delivering these programs and provide a more standardized service to 
customers throughout the State. 

     In 1998, we spent approximately $1.8 million on energy efficiency 
programs, approximately 1.0% of our 1998 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, we have 
offered optional time-of-use rates for residential and commercial 
customers.  Currently, approximately 2,500 of our residential customers 
continue to be billed on the original 1976 time-of-use rate basis.   In 
1987, we received regulatory approval for a rate design that permitted 
us to charge prices for electric service that reflected as accurately as 
possible the cost burden imposed by each customer class.  Our 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 our largest customers 
be charged time-of-use rates on a phased-in basis by 1994.  At year end 
December 31, 1998, approximately 1,350 of our largest customers, 
comprising 48% of our retail revenues, continue to receive service on 
mandatory time-of-use rates.  

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

     No modifications to base rate design have taken place since the 
VPSB Order issued on December 2, 1994.


             DISPATCHABLE AND INTERRUPTIBLE SERVICE CONTRACTS

     In 1998, we 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 allows the 
Company to control power supply capacity charges by reducing our 
capacity requirements.  During 1998, we 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.  We shift load 
from our high cost peak periods and the customer uses inexpensive power 
at a time when its use provides maximum value.  These programs are 
available by tariff for qualifying customers.


                   CONSTRUCTION AND CAPITAL REQUIREMENTS

     Our capital expenditures for 1996 through 1998 and projection for 
1999 are set forth in Item 7. Management's Discussion And Analysis Of 
Financial Condition and Results Of Operations - "Liquidity and Capital 
Resources" -"Construction."  Construction projections are subject to 
continuing review and may be revised from time-to-time in accordance 
with changes in the Company's financial condition, load forecasts, the 
availability and cost of labor and materials, licensing and other 
regulatory requirements, changing environmental standards and other 
relevant factors.

     For the period 1996-1998, internally generated funds, after payment 
of dividends, provided approximately 60 percent of total capital 
requirements for construction, sinking fund obligations and other 
requirements.  Internally generated funds provided 25 percent of such 
requirements for 1998.  We anticipate that for 1999, internally 
generated funds will provide approximately 90 percent of total capital 
requirements for regulated operations, the remainder to be derived from 
bank loans.


                            ENVIRONMENTAL MATTERS

     We have been notified by the Environmental Protection Agency (EPA) 
that we are one of several potentially responsible parties for clean up 
at the Pine Street Barge Canal site in Burlington, Vermont.  For 
information regarding the Pine Street Canal site and other environmental 
matters see Item 7. Management's Discussion and Analysis Of Financial 
Condition and Results of Operations - "Environmental Matters" and Note 
I-2 of Notes to Consolidated Financial Statements.


                           UNREGULATED BUSINESSES

     In 1998, we sold the assets of our wholly owned subsidiary, Green 
Mountain Propane Gas Company.  Through our subsidiary, Green Mountain 
Resources, Inc., we agreed to sell our remaining interest in Green 
Mountain Energy Resources to Green Funding I in early 1999.  For 
information regarding our unregulated businesses, see Item 7. 
Management's Discussion and Analysis of Financial Condition and Results 
of Operations- "Unregulated Businesses."



EXECUTIVE OFFICERS

Executive Officers of the Company as of March 15, 1999:

      Name                Age

Nancy Rowden Brock        43   Vice President, Chief Financial Officer and 
                               Treasurer since December 1998.  Chief 
                               Corporate Strategic Planning Officer from 
                               March 1998 to December 1998.  Prior to 
                               joining the Company, she was Chief Financial 
                               Officer of SAL, Inc., 1997; and Senior Vice 
                               President, Chief Financial Officer and 
                               Treasurer for the Chittenden Corporation from 
                               1988 to 1996.

Christopher L. Dutton     50   President, Chief Executive Officer of 
                               the Company 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         42   Controller since October 1996.  Manager 
                               of General Accounting from 1990 to 1996.


Donna S. Laffan           49   Corporate Secretary since December 
                               1993.  Assistant Secretary from 1986 to 1993.

John J. Lampron           54   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         54   General Counsel since August 1997.  
                               Assistant General Counsel from 1994 to 1997.  
                               Senior Attorney from 1993 to 1994.  Corporate 
                               Attorney from 1990 to 1993.  Prior to joining 
                               the Company, he was a partner with Miller, 
                               Eggleston and Rosenberg Ltd.

Craig T. Myotte           44   Assistant Vice President-Engineering 
                               and Operations since 1994.  Assistant Vice 
                               President-Operations and Maintenance from 
                               1991 to 1994.

Walter S. Oakes           52   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            38   Vice President, Administration since 
                               February 1999.  Vice President, Human 
                               Resources and Organizational Development from 
                               March 1998 to February 1999.  Prior to 
                               joining the Company, she was Senior Vice 
                               President, Human Resources and Senior Vice 
                               President Community Banking, Senior Vice 
                               President Administration, and Vice President 
                               of Human Resources for KEYCORP from October 
                               1992 to March 1998.

Stephen C. Terry          56   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         47   President of Mountain Energy, Inc. 
                               since March 1997.  Vice President and Chief 
                               Operating Officer of Mountain Energy, Inc. 
                               from 1989 to March 1997.


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


ITEM 2.  PROPERTY
                           GENERATING FACILITIES

     Our Vermont properties are located in five areas and are 
interconnected by transmission lines of VELCO and New England Power 
Company.  We wholly own and operate eight hydroelectric generating 
stations with a total nameplate rating of 36.1 MW and an estimated 
claimed capability of 35.7 MW.  We also own two gas-turbine generating 
stations with an aggregate nameplate rating of 59.9 MW and an estimated 
aggregate claimed capability of 73.2 MW.  We have two diesel generating 
stations with an aggregate nameplate rating of 8.0 MW and an estimated 
aggregate claimed capability of 8.6 MW.  We also have a wind generating 
facility with a nameplate rating of 6.1 MW.

     We also own:
- 	17.9% of the outstanding common stock of Vermont Yankee, and are 
entitled to 17.662% (93.8 MW of a total 531 MW) of the capacity 
of the plant; 
- 	1.1% (7.1 MW of a total 620 MW) joint-ownership share of the 
Wyman #4 plant located in Maine; 
- 	8.8% (31.0 MW of a total 352 MW) joint-ownership share of the 
Stony Brook I intermediate units located in Massachusetts; and
- 	11.0% (5.8 MW of a total 53 MW) joint-ownership share of the J.C. 
McNeil wood-fired steam plant located in Burlington, Vermont.
See Item 1. Business - "Power Resources" for plant details and the table 
hereinafter set forth for generating facilities presently available.


                        TRANSMISSION AND DISTRIBUTION

     The Company had, at December 31, 1998, approximately 1.5 miles of 
115 kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4 
miles of 44 kV and 284.6 miles of 34.5 kV transmission lines.  Our 
distribution system includes about 2,409 miles of overhead lines of 
2.4 kV to 34.5 kV, and about 459 miles of underground cable of 2.4 kV to 
34.5 kV.  At such date, we owned approximately 158,820 kVa of substation 
transformer capacity in transmission substations, 567,750 kVa of 
substation transformer capacity in distribution substations and 
1,079,987 kVa of transformers for step-down from distribution to 
customer use.

     The Company owns 34.8% of the Highgate transmission inter-tie, a 
225-MW converter and transmission line utilized to transmit power from 
Hydro-Quebec.

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


                              PROPERTY OWNERSHIP

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

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


                          INDENTURE OF FIRST MORTGAGE


     The Company's interests in substantially all of its properties and 
franchises are subject to the lien of the mortgage securing its First 
Mortgage Bonds and a second mortgage and security interest in the 
property securing the 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, we 
receive up to 6.6 MW as a result of other owners' losses on this 
system.

                          CORPORATE HEADQUARTERS

     The Company has an operating lease for its Corporate Headquarters, 
building, which it expects to vacate mid-year 1999.  For a discussion 
regarding this lease, see Note I-6 of Notes to Consolidated Financial 
Statements.


ITEM 3.  LEGAL PROCEEDINGS

     See the discussion Item 7. Management's Discussion And Analysis Of 
Financial Condition And Results Of Operations - "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 1998:

                                            HIGH         LOW
        
        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

        1998           First Quarter        20 1/16      18
                       Second Quarter       19 1/16      14 1/8
                       Third Quarter        14 9/16      11 1/8
                       Fourth Quarter       15 1/16      10 1/16

     The number of common stockholders of record as of March 12, 1999 
was 7,032.

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

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

      1997 . . . .   53.0 cents  53.0 cents   27.5 cents   27.5 cents
      1998 . . . .   27.5 cents  27.5 cents   27.5 cents  13.75 cents

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

     Our current dividend policy reflects changes affecting the electric 
utility industry, which is moving away from the traditional cost-of-
service regulatory model to a competition based market for power supply, 
and the rate case developments discussed in Item 7. Management's 
Discussion And Analysis Of Financial Condition And Results Of Operations 
- "1998 Retail Rate Case".

     The current environment prompted us to reassess the appropriateness 
of our dividend. The Company's Board of Directors will continue to 
assess and adjust the dividend when appropriate, as the Vermont electric 
industry evolves towards competition.  In addition, if other events 
beyond our control cause our financial situation to deteriorate further, 
the Board of Directors will also consider whether the current dividend 
level is appropriate or if the dividend should be reduced or eliminated.  
See Item 7. Management's Discussion And Analysis Of Financial Condition 
and Results Of Operations "Future Outlook - Competition and 
Restructuring" and Note C of Notes to Consolidated Financial Statements 
- "Dividend Restrictions."

<TABLE>
<CAPTION>

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

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

                                               1998         1997         1996         1995         1994
                                             ---------    ---------    ---------    ---------    ---------
<S>                                          <C>          <C>          <C>          <C>          <C>
Operating Revenues...........................$184,304     $179,323     $179,009     $161,544     $148,197
Operating Expenses........................... 178,832      163,808      162,882      146,249      133,680
                                             ---------    ---------    ---------    ---------    ---------
  Operating Income...........................   5,472       15,515       16,127       15,295       14,517
                                             ---------    ---------    ---------    ---------    ---------
Other Income
  AFUDC - equity.............................     104          357          175           27          263
  Other......................................    (577)       1,216        3,055        3,607        3,418
                                             ---------    ---------    ---------    ---------    ---------
    Total other income (deductions)..........    (473)       1,573        3,230        3,634        3,681
                                             ---------    ---------    ---------    ---------    ---------
Interest Charges
  AFUDC - borrowed funds.....................    (131)        (315)        (468)        (547)        (539)
  Other......................................   8,007        7,965        7,866        7,973        7,735
                                             ---------    ---------    ---------    ---------    ---------
    Total interest charges...................   7,876        7,650        7,398        7,426        7,196
                                             ---------    ---------    ---------    ---------    ---------

Net Income (Loss)............................  (2,877)       9,438       11,959       11,503       11,002

Dividends on Preferred Stock.................   1,296        1,433        1,010          771          794
                                             ---------    ---------    ---------    ---------    ---------
Net Income (Loss)Applicable to Common Stock.. ($4,173)      $8,005      $10,949      $10,732      $10,208
                                             =========    =========    =========    =========    =========
Common Stock Data
  Earnings (loss)per share...................  ($0.80)       $1.57        $2.22        $2.26        $2.23
  Cash dividends declared per share.......... $0.9625        $1.61        $2.12        $2.12        $2.12
  Weighted average shares outstanding........   5,243        5,112        4,933        4,747        4,588



Financial Condition as of December 31
-------------------------------------
                                               1998         1997         1996         1995         1994
                                             ---------    ---------    ---------    ---------    ---------

Assets

 Utility Plant, Net..........................$195,556     $196,720     $189,853     $181,999     $175,987
 Other Investments...........................  20,678       21,997       20,634       20,248       20,751
 Current Assets..............................  35,700       29,125       30,901       30,216       28,798
 Deferred Charges............................  30,576       27,390       43,224       42,951       35,659
 Non-Utility Assets..........................  27,314       42,060       39,927       37,868       33,416
                                             ---------    ---------    ---------    ---------    ---------
  Total Assets...............................$309,824     $317,292     $324,539     $313,282     $294,611
                                             =========    =========    =========    =========    =========

Capitalization and Liabilities

 Common Stock Equity.........................$106,755     $114,377     $111,554     $106,408     $101,319
 Redeemable Cumulative Preferred Stock.......  16,085       17,735       19,310        8,930        9,135
 Long-Term Debt, Less Current Maturities.....  88,500       93,200       94,900       91,134       74,967
 Capital Lease Obligation....................   7,696        8,342        9,006        9,778       10,278
 Curent Liabilities..........................  28,825       25,286       21,037       32,629       40,441
 Deferred Credits and Other..................  54,889       45,282       54,968       52,041       49,434
 Non-Utility Liabilities.....................   7,074       13,070       13,764       12,362        9,037
                                             ---------    ---------    ---------    ---------    ---------
  Total Capitalization and Liabilities.......$309,824     $317,292     $324,539     $313,282     $294,611
                                             =========    =========    =========    =========    =========

</TABLE>

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

	In this section, we explain the general financial condition and the 
results of operations for Green Mountain Power Corporation (the Company) 
and its subsidiaries, including:
- 	Factors that affect our business; 
- 	Our earnings and costs in the periods presented and why they 
   changed between periods; 
- 	The source of our earnings; 
- 	Our expenditures for capital projects and what we expect they will 
   be in the future;  
- 	Where we expect to get cash for future capital expenditures; and  
- 	How all of the above affects our overall financial condition.   

	There are statements in this section that contain projections or 
estimates and are considered to be "forward-looking" as defined by the 
Securities and Exchange Commission.  In these statements, you may find 
words such as "believes," "expects," "plans," or similar words.  These 
statements are not guarantees of our future performance.  There are 
risks, uncertainties and other factors that could cause actual results 
to be different from those projected.  Some of the reasons the results 
may be different are listed below and discussed under "Future Outlook", 
"Environmental Matters", "Liquidity and Capital Resources" and "Year 
2000 Computer Compliance" in this section:

- 	Regulatory decisions or legislation;
- 	Weather;
- 	Energy supply and demand and pricing;
- 	Availability, terms, and use of capital; 
- 	General economic and business environment;
- 	Nuclear and environmental issues; and
- 	Industry restructuring and cost recovery (including stranded 
   costs).

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


                               EARNINGS SUMMARY


     The Company lost $0.80 per average share of common stock in 1998 as 
compared with earnings per share of common stock of $1.57 in 1997 and 
$2.22 in 1996.  The 1998 loss represents a negative return on average 
common equity of 3.8 percent.  The earned return on average common 
equity was 7.1 percent in 1997 and 10.0 percent in 1996.

     The decrease in earnings in 1998 resulted primarily from the 
following:
- 	A rate decision by the Vermont Public Service Board ("VPSB") in 
   February 1998 that disallowed recovery of $6 million for Hydro-
   Quebec power supply expenses and other costs;
- 	A $5.25 million loss accrued in 1998 resulting from the continued 
   disallowance of Hydro-Quebec power costs during 1999; 
- 	Higher 1998 power supply expenses resulting from a one time $8 
   million payment received from Hydro-Quebec in 1997 that reduced 
   1997 power supply expenses accordingly;
- 	A $3.2 million charge associated with terminating the Company's 
   corporate headquarters lease and  with workforce reductions in 
   1998; and
- 	A $2.1 million (after-tax) loss experienced by Mountain Energy, 
   Inc.  in 1998, as compared to earnings of $142,0000 in 1997, 
   resulting from a $1.2 million net write-off of a wind power 
   investment and continued start-up operating losses incurred by 
   Micronair LLC, a wholly-owned wastewater treatment investment.  
   This loss was substantially off-set by a $1.8 million reduction in 
   losses experienced by Green Mountain Resources, Inc. (GMRI) due to 
   the absence of start-up expenses in 1998, as compared to 1997.

     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 invests in 
   energy generation, energy efficiency and wastewater treatment  
   projects, earned $1.2 million less in 1997 than in 1996.  The 
   decrease in earnings was 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.
- 	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 Green 
   Mountain Energy Resources L.L.C. (GMER), the retail energy company 
   in which the Company sold a 67 percent interest during the third 
   quarter of 1997.

                               FUTURE OUTLOOK


     Competition and Restructuring -- The electric utility business is 
experiencing rapid and substantial changes.  These changes are the 
result of the following trends: 
- 	Surplus generating capacity; 
- 	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, 
   also known as "restructuring". 

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

     In states across the country, including the New England states, 
there has been legislation enacted to allow retail customers to choose 
their electricity suppliers, with incumbent utilities required to 
deliver that electricity over their transmission and distribution 
systems (also known as "retail wheeling").  Increased 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 in 
states, including Vermont where legislation has not been enacted, are 
considering how to facilitate competition for electricity sales at the 
wholesale and retail levels. 
     The 1998 session of the Vermont General Assembly adjourned on April 
16, 1998 without enacting legislation that would allow Vermont customers 
to choose their electric supplier.  There is currently no indication 
that restructuring legislation will be enacted in the 1999 session. 

     In the future, the Vermont General Assembly through legislation, or 
the VPSB through a subsequent report, action or proceeding, may allow 
customers to choose their electric supplier.  If this happens without 
providing for recovery of a significant portion of the costs associated 
with our power supply contracts, the Company's business, including our 
operating results, cash flows and ability to pay dividends at the 
current level, would be adversely affected.  If actions by the Vermont 
General Assembly or the VPSB threaten the Company's financial integrity, 
we will evaluate all potential alternatives available to us at that 
time, including, but not limited to, the filing of a petition for 
reorganization under the United States Bankruptcy Code. 

     In August 1998, the VPSB hosted an open workshop to examine the 
extent to which realistic opportunities exist to increase the value or 
lower the costs of Vermont's existing power supply arrangements, and, if 
such opportunities exist, to consider the best processes for attracting 
the highest value proposals. Topics included:
- 	Vermont's current power supply situation;
- 	Case studies in reforming power supply; and 
- 	Opportunities in Vermont to reform the power supply.

     In September 1998, the VPSB issued an Order (Docket No. 6140) 
opening an investigation into the reform of Vermont's electric power 
supply and ordered all Vermont electric utilities to participate.  That 
Order also requested participants to file with the VPSB position papers 
to address the scope of the investigation and present substantive 
proposals for reform.  The Company, together with Central Vermont Public 
Service Corporation (CVPS), Citizens Utilities Company and Associated 
Industries of Vermont (AIV), an industrial trade association, filed a 
position paper responding to the Order.  We participated in the VPSB's 
technical conference in October at which the scope of the investigation 
was discussed.  We filed our response to that conference indicating the 
priorities and action steps we believe should be taken in order to 
provide the greatest assistance in the effort to mitigate Vermont's 
power supply costs.

	 On July 22, 1998, Governor Howard B. Dean announced the 
appointment of the Working Group on Vermont's Electricity Future 
(Working Group) to examine the structure of the utility industry in 
Vermont.  The Working Group was comprised of five citizens who were 
charged with evaluating and devising sound public policy relating to the 
future of the Vermont electric industry.  The Working Group issued its 
report on December 18, 1998.  The fundamental conclusions of the report 
are:
- 	Bankruptcy is not a solution to Vermont restructuring efforts and 
   is not an appropriate means to resolve the above-market costs 
   associated with Vermont's power supply portfolio.
- 	Financing mechanisms, including asset securitization, that have 
   been implemented in other states that have restructured their 
   electric industries should be made available in Vermont.  Such 
   mechanisms would enable the utilities to provide an up-front lump-
   sum payment to suppliers of power to Vermont utilities in exchange 
   for terminating or substantially reducing the pricing in their 
   contracts.  The legislature or regulators could authorize such 
   financing mechanisms. 
- 	The utilities in Vermont should exit the power generation and 
   supply business as part of the restructuring of the electric 
   industry in Vermont.  The Working Group believes that Vermont 
   should move rapidly into a restructured competitive environment in 
   which the incumbent utilities would serve as distribution 
   providers.
- 	As a component of a restructuring plan, serious consideration 
   should be given to consolidation of the 22 utilities in Vermont, 
   beginning with the amalgamation of Citizens Utilities' Vermont 
   operations with Green Mountain Power Corporation and Central 
   Vermont Public Service Corporation.

     On January 8, 1999, the Company, CVPS, AIV and Citizen Utilities 
filed Consolidated Comments and Procedural Recommendations with the VPSB 
regarding the Working Group's report.  We have recommended to the VPSB 
that it give priority to considering the Working Group's principal 
recommendations, as discussed above, and approve the procedures 
necessary for their implementation. 

     The idea of consolidation of Vermont's utilities needs further 
exploration and the Company, CVPS and Citizens Utilities have signed 
confidentiality agreements so that such exploration may proceed.  
Consistent with the Company's charter, we will consider the benefits of 
any merger or consolidation for our shareholders as well as the social, 
legal and economic effects upon our customers, employees, suppliers and 
others in similar relationships with us, and upon the communities in 
which we do business.

     Risk Factors -- The major risk factors for the Company arising from 
electric industry restructuring, including risks pertaining to the 
recovery of stranded costs, are: 
- 	Regulatory and legal decisions;
- 	The market price of power; and
- 	The amount of market share retained by the Company.  

     There can be no assurance that any final restructuring plan ordered 
by the VPSB, the courts, or through legislation will include a mechanism 
that would allow for full recovery of our stranded costs and include a 
fair return on those costs as they are being recovered.  If laws are 
enacted or regulatory decisions are made that do not offer an adequate 
opportunity to recover stranded costs, we believe we have compelling 
legal arguments to challenge such laws or decisions.

     The largest category of our potential stranded costs is future 
costs under long-term power purchase contracts, which, based on current 
forecasts, are above-market.  We intend to pursue aggressively 
mitigation efforts in order to maximize the recovery of these costs.  
The magnitude of our stranded costs is largely dependent upon the future 
market price of power.  We have discussed various market price scenarios 
with interested parties for the purpose of identifying stranded costs.  
Preliminary market price assumptions, which are likely to change, have 
resulted in estimates of the Company's stranded costs of between $245 
million and $620 million.

     If retail competition is implemented in Vermont, there will be an 
impact on the Company's revenues from electricity sales.  However, we 
are unable to predict at this time the extent of this impact.  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 nor 
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. Statement of Financial Accounting Standards No. 
71 (SFAS 71) allows regulated entities, in appropriate circumstances, to 
establish regulatory assets and liabilities, and thereby defer the 
income statement impact of certain costs and revenues that are expected 
to be realized in future rates. The Company has established regulatory 
assets and liabilities under SFAS 71. 

     As described 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: 
- 	Deregulation;
- 	A change in the regulators' approach to setting rates from cost-
   based regulation to another form of regulation;
- 	Increasing competition that limits our ability to sell utility 
   services or product at rates that will recover costs; and
- 	Regulatory actions that result from resistance to rate increases 
   that limit our ability to sell utility services or products at 
   rates that will recover costs if we are unable to obtain relief 
   from prior regulatory actions through appeals to the VPSB or the 
   courts.  See Note I of the Notes to Consolidated Financial 
   Statements and "Liquidity and Capital Resources".

     Under SFAS 5, Accounting for Contingencies, the enactment of 
restructuring legislation or issuance of a regulatory order containing 
provisions that do not allow for stranded cost recovery, consisting 
principally of above market power costs, would require the Company to 
estimate and record losses immediately, on an undiscounted basis, for 
any above market power purchase contracts and other costs which are 
probable of not being recoverable from customers, to the extent that 
those costs are estimable.  We are unable to predict what form enacted 
legislation or such an order will take, and we 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 stranded costs that are recoverable through rates, those costs would 
continue to be accounted for under SFAS 71.  

     SFAS 121, Accounting for the Impairment of Long Lived Assets, 
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 that are 
no longer probable of recovery.  As of December 31, 1998, based upon the 
regulatory environment within which we currently operate, no impairment 
loss was recorded.  Competitive influences or regulatory developments 
may impact this status in the future.

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

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

                          UNREGULATED BUSINESSES

    The following is a discussion of the Company's unregulated enterprises.
Our unregulated businesses lost 39 cents per share of common stock in 
1998 as compared to a loss of 31 cents per share of common stock in 
1997.

     Mountain Energy, Inc. (MEI), which invests in energy generation, 
energy efficiency and waste water treatment projects, lost $2.1 million 
in 1998, compared to earnings of $0.1 million in 1997.  The 1998 
decrease in earnings was due primarily to continued start-up operating 
losses incurred by Micronair, LLC and a write-off related to a wind 
facility in California. 

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

     In 1997, MEI 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 bio-solids disposal issues 
facing the United States.  The Micronairr system enhances both the 
processing and energy efficiency at wastewater facilities, virtually 
eliminating bio-solids as a byproduct.  In 1998, MEI acquired the 
remaining interest in Micronair.

     In 1998, MEI acquired a 33.9 percent equity interest in CASTion 
Corporation, an industrial wastewater treatment company.  CASTion's 
Controlled Atmospheric Separation Technology (CAST ) separates clean 
water from industrial process waste streams, in some cases recapturing 
valuable minerals and chemicals for reuse.  The potential market 
continues to grow as public and regulatory tolerance for wastewater 
discharges wanes.  CASTion has fourteen systems in commercial operation.

     Green Mountain Propane Gas, Limited (GMPG), which sold propane gas 
at retail in Vermont and New Hampshire, experienced a $139,000 loss in 
1998 as compared to a $136,000 loss in 1997.   

     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.

     The Company's unregulated rental water heater business earned 
$416,000 in 1998, a slight increase from 1997's net income of $381,000.  
The 1998 and 1997 results contributed 8 cents and 7 cents of earnings, 
respectively, per share to the Company's consolidated results.

     Green Mountain Resources, Inc. (GMRI) was formed in April 1996 to 
explore opportunities in the emerging competitive retail energy market.  
In 1998, GMRI lost $0.2 million compared to a loss of $2.0 million in 
1997.  GMRI's loss in 1997 was primarily due to development costs 
associated with its investment in Green Mountain Energy Resources L.L.C. 
(GMER).

     On August 6, 1997, GMRI entered into an agreement with Green 
Funding I, L.L.C. (GFI), whereby GMRI and GFI would jointly own GMER, a 
Delaware limited liability company of which GMRI was previously the sole 
owner.  GMER is a company that has created retail brands of electricity 
that are sold to consumers in competitive markets.  GMRI received a 
payment of $4 million from GMER at the closing in 1997 as reimbursement 
for certain development expenses GMRI had incurred.  

     Under the terms of the original agreement through which GFI 
acquired its interest in GMER, GMRI's ownership percentage of GMER would 
be diluted if GFI and/or third parties proposed to contribute additional 
capital to GMER, and GMRI did not make pro rata additional capital 
contributions at such time.  During 1998, GFI made additional, 
substantial investments in GMER and it was anticipated that GFI or other 
parties would make additional, substantial investments in 1999.  GMRI 
elected not to provide  additional capital contributions, which reduced 
its ownership percentage in GMER.  In view of the likely need for future 
investment in GMER's business, we considered it to be in the best 
interest of our shareholders to sell GMRI's remaining interest in GMER.

     In December 1998, GMRI and GFI replaced the 1997 agreement with a 
new agreement, which among other things, provided for the sale of GMRI's 
remaining interest in GMER in return for $1 million to be paid and 
recorded as income in the first quarter of 1999.  The funds were 
received and will be used for the Company's general operating expenses.

     The new agreement provides us substantial relief from a "non-
compete clause" in the 1997 agreement that would have restricted our 
activities in the retail energy business for seven years. 

                            RESULTS OF OPERATIONS

     Operating Revenues and MWh Sales - Operating revenues and 
megawatthour (MWh) sales for the years 1998, 1997 and 1996 consisted of:

                                    1998         1997         1996
                                    ----         ----         ----
                                          (Dollars in thousands)
Operating Revenues:
   Retail . . . . . . . . . . .   $164,855   $ 158,790     $ 154,916
   Sales for Resale . . . . . .     16,529      17,847        20,667
   Other  . . . . . . . . . . .      2,920       2,686         3,426
                                  --------   ---------     ---------
Total Operating Revenues  . . .   $184,304   $ 179,323     $ 179,009
                                  ========   =========     =========

 Megawatthour Sales:
   Retail . . . . . . . . . . .  1,839,522   1,806,580     1,775,711
   Sales for Resale . . . . . .    543,846     588,525       701,835
                                 ---------   ---------     ---------
Total Megawatthour sales  . . .  2,383,368   2,395,105     2,477,546
                                 =========   =========     =========

Average Number of Customers:
   Residential  . . . . . . . .     71,301      70,671        70,198
   Commercial & Industrial  . .     12,193      12,012        11,853
   Other  . . . . . . . . . . .         70          75            75
                                    ------      ------        ------
Total Customers   . . . . . . .     83,564      82,758        82,126
                                    ======      ======        ======


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

                                                    1997         1996
                                                     to           to 
                                                    1998         1997
                                                    ----         ----
                                                     (In Thousands)
Operating Revenues:
   Retail Rates . . . . . . . . . . . . . . .   $   3,113     $  1,161
   Retail Sales Volume  . . . . . . . . . . .       2,952        2,713
   Resales and Other Revenues . . . . . . . .      (1,084)      (3,560)
                                                 ---------     --------
Increase in Operating Revenues  . . . . . . .    $  4,981      $   314
                                                 =========     ========

     In 1998, total electricity sales decreased 0.5 percent due 
principally to a decrease in wholesale sales caused by a reduction in 
low-margin, off-system sales.

     Total operating revenues increased 2.8 percent in 1998.  Total 
retail revenues increased 3.8 percent in 1998 primarily due to:
- 	A 3.9 percent increase in sales of electricity to our commercial 
   and industrial customers resulting from increased use of air 
   conditioning during the spring and summer months; and
- 	A 3.79 percent retail rate increase for service rendered March 1, 
   1998. 
The increase was partially offset by a 2.8 percent reduction in sales to 
residential customers caused by warmer than normal winter months.  
Wholesale revenues decreased 7.4 percent in 1998 primarily due to a 
reduction in low-margin, off-system sales.

     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 our 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.

     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 14.7, 14.0, and 
13.2 percent of  our operating revenues in 1998, 1997 and 1996, 
respectively.  No other retail customer accounted for more than one 
percent of our revenue in any such year.

     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 our 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 our tariff rate.  The EDA I price, 
although lower than our tariff rate, exceeded our 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 our marginal costs.  A 
separate pricing provision applies to load above 1997 levels.  The 
agreement is for one year, subject to extension for another year at 
IBM's option.  The VPSB approved the EDA II on May 21 1998.  We believe 
that the EDA I and EDA II benefit us because the agreements encourage 
the incremental purchase of electricity by IBM at a price above our 
marginal cost of providing such incremental service.

     Power Supply Expenses -- Power supply expenses constituted 67.7 
percent, 61.3 percent and 61.5 percent of total operating expenses for 
the years 1998, 1997 and 1996, respectively. These expenses increased by 
$20.7 million (20.6  percent) in 1998 and $120,000 (0.1 percent) in 
1997.

     Total power supply expenses increased 20.6 percent in 1998 
primarily due to:
- 	The absence in 1998 of the $8 million reduction of Hydro-Quebec 
   power costs  resulting from the rate treatment of a payment 
   received from Hydro-Quebec in 1997;
- 	A $5.25 million loss accrued in 1998 resulting from the continued 
   disallowance of Hydro-Quebec power costs during 1999; and
- 	A $4.8 million increase in  scheduled Hydro-Quebec contract 
   capacity costs in 1998.
Company-owned generation increased 20.4 percent in 1998 due to an 
increase in the use of high-cost generating facilities that replaced 
power that was unavailable from Hydro-Quebec during a severe ice storm 
that affected much of Vermont, the Northeast United States and Quebec in 
January 1998.

     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.  

     During 1994, we 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, we 
will, in essence, take delivery of the amounts of energy as specified in 
the 1987 Contract, but the associated fixed costs will be significantly 
reduced from those specified in the 1987 Contract.

     As part of the July 1994 Agreement, we are 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, we 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 reduced purchase power expense ratably over the period beginning 
June 1997 and ending May 1998.  We received VPSB approval of this 
accounting treatment in an Accounting Order dated December 31, 1996.

     Under the 1996 arrangement we are required to shift up to 40 
megawatts of our 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 
our level of benefits  will depend on various factors, we estimate that 
the 1996 arrangement will provide a minimum benefit of $1.8 million on a 
net present value basis.  During 1998, we purchased or sold to others 
44.2 percent of the minimum purchase obligation for that year.    We 
recorded a liability of $0.3 million for our remaining 1998 minimum 
purchase obligation.

     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, we provided Hydro-Quebec an option for the 
purchase of power.  Commencing April 1, 1998 and effective through the 
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.  
Hydro-Quebec's option to curtail energy deliveries pursuant to the July 
1994 Agreement can be exercised in addition to this purchase option.  
Over the same period, 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. In 
1998, Hydro-Quebec called on us to deliver 51,968 MWh to a third party 
at a net cost to us of $232,958, which was due to higher energy 
replacement costs.  (See Note K of the Notes to Consolidated Financial 
Statements).

    
     The Company and the other Vermont Joint Owners (VJO) of the Hydro-
Quebec contract  have sought arbitration to determine whether the 
suspension of deliveries of power to Vermont during and after the 
January 1998 ice storm constitutes a default by Hydro-Quebec under the 
terms of the contract, or if there are other possible claims against 
Hydro-Quebec arising from the suspension of deliveries.  Hydro-Quebec 
appears to maintain that the "force majeure" (superior or irreversible 
force) provision in the contract applies, which could excuse its non-
delivery of power under certain circumstances.  Arbitration of the 
dispute may lead to one or more remedies having an impact on our 
obligation under the contract.


     On February 11, 1999, we entered into a contract with Morgan 
Stanley Capital Group, Inc. (MS) as a result of our power requirements 
solicitation in 1998.  A master power purchase and sales agreement 
(PPSA) dated February 11, 1999 defines the general contract terms under 
which the parties may transact.  The sales under the PPSA  commenced on 
February 12, 1999, and will terminate after all obligations under each 
transaction entered into by MS and the Company have been fulfilled, 
currently anticipated to be June 30, 2001.  The PPSA has been noticed to 
the VPSB and filed with the Federal Energy Regulatory Commission (FERC).

     The parties have also agreed to enter into two transactions subject 
to the PPSA.
- 	 Sale by the Company to MS. -- On a daily basis, and at MS's 
    discretion, we will sell power from all or part of our portfolio of 
    power resources to MS at predefined operating and pricing 
    parameters.  We can decide to sell power to MS from any power 
    resource available to us, provided the sales of power are 
    consistent with the predefined operating and pricing parameters.   
    We retain all rights and obligations related to our power 
    resources, such as dispatch, plant modifications and transfer of 
    ownership.  This transaction does not constitute a sale or lease of 
    any Company resource.
-  	Sale by MS to the Company. -- MS will sell to us, at a predefined 
    price, power sufficient to serve pre-established load requirements.  
    MS has the right but not the obligation, upon a request from us, to 
    supply additional power at prices negotiated by both parties.  The 
    power sold to us may be, but is not required to be, power that MS 
    has purchased from us under the transaction described above.

     The parties have agreed to the protocols that will be used to 
schedule power sales and purchases between the parties and to secure 
necessary transmission with respect to the two transactions described 
above.

     The PPSA provides us with a means of managing price risks 
associated with changing fossil fuel prices.  We remain responsible for 
balancing supply resources when actual loads vary from the pre-
established load requirements that MS is obligated to satisfy, and for 
resource performance and availability.

     Other Operating Expenses - Other operating expenses increased 26.9 
percent in 1998 primarily due to:
- 	Higher overhead costs resulting from less overhead charged to GMRI, 
   whose earnings are accounted for on the equity basis;
- 	Losses associated with the expected termination of the lease for 
   our corporate headquarters building; and
- 	Charges associated with a workforce reduction in 1998.

     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.

     Transmission Expenses - Transmission expenses decreased 15.6 
percent in 1998 primarily due to a refund received from CVPS in 1998 as 
a result of reduced levels of demand on the CVPS transmission system in 
1997.  We also received a refund in 1998 for charges that were 
incorrectly assessed to us during 1997 by New England Power Company.

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

     Maintenance Expenses - Maintenance expenses increased 8.5 percent 
in 1998 primarily due to scheduled plant maintenance activities at the 
Stony Brook plant and the repair of damage caused by lightning at our 
wind facility.

     Maintenance expenses increased 7.2 percent in 1997 due to scheduled 
increases in plant maintenance.

     Depreciation and Amortization - In 1998, depreciation and 
amortization expenses decreased 1.8 percent primarily due to a decrease 
in the amortization of expenditures related to the Pine Street Barge 
Canal site as a result of the VPSB Order of February 27, 1998, which 
suspended the amortization charges.
This decrease was partially offset by an increase in depreciation 
expenses associated with additional investment in our utility plant. 

     Depreciation and amortization expenses were virtually unchanged in 
1997.

     Income Taxes -- The effective federal income tax rates for the 
years 1998, 1997 and 1996 were 26.1 percent, 32.8 percent and 27.2 
percent, respectively.

     Income taxes decreased in 1998 due to a decrease in taxable income.

     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 $2 million in 1998, as 
compared to 1997, primarily due to:
- 	A $2.1 million (afer-tax)loss experienced by Mountain Energy, Inc. 
   resulting from a $1.2 million net write-off of a wind power 
   investment and start up operating losses incurred by Micronair LLC; 
   and
- 	A $900,000 disallowance in costs associated with the wind facility 
   ordered by the VPSB in its February 27, 1998 Order.
In addition, the allowance for funds used during construction decreased 
in 1998 resulting from lower construction work in progress balances 
during the period.  These decreases were partially offset by $1.8 
million reduction in losses experienced by GMRI due to the absence of 
start-up expenses in 1998 as compared to 1997.

     Other income decreased 51.3 percent in 1997 primarily due to 
diminished results by two of our 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 during the third quarter of 1997.


     Interest Charges - Interest charges increased 3.0 percent in 1998 
primarily due to an increase in short-term interest expense related to a 
higher amount of short-term debt outstanding during the year and a 
decrease in the allowance for funds used during construction resulting 
from lower construction work in progress balances in 1998.  The 
increases were partially offset by a decrease in long-term interest 
charges related to a lower amount of long-term debt outstanding in 1998.

     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 our 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.

     Dividends on Preferred Stock - Dividends on preferred stock 
decreased by 9.6 percent in 1998 primarily due to the repurchase in 1997 
of the following preferred stock:  150 shares of the 4.75 percent, Class 
B; 1,600 shares of the 9.375 percent, Class D, Series 1; and 14,000 
shares of the 8.625 percent, Class D, Series 3.

     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.

                           TRANSMISSION ISSUES

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

     On July 9, 1996, we filed with the FERC the non-discriminatory open 
access tariffs required by Order 888 and subsequent modifications to the 
tariff.  The tariff defined our transmission system to include sub-
transmission facilities that we own including Phase I and Phase II 
facilities and our entitlement to facilities owned by VELCO.  Our 
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 our  Open Access Transmission Tariff, 
and on August 30, 1997, we filed our compliance refund report.

     In accordance with Order 889, we have also functionally separated 
our transmission operations and filed with the FERC a code of conduct 
for our  transmission operations.  We are currently revising the Code of 
Conduct in response to a FERC Order issued on November 3, 1997.  We do  
not anticipate any material adverse effects or loss of wholesale 
customers due to the FERC orders mentioned above.

     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.  Our 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, 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 grand-fathered 
contracts.  Efforts by us 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 to Amendment 33.  The Company and 
other Vermont utilities have argued 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).  

     The FERC, in an order dated April 20, 1998, took no action on 
VELCO's motion other than to recommend that VELCO seek resolution of the 
issue pursuant to the dispute resolution process under the proposed 
NEPOOL Open Access tariff.  The Vermont utilities continue to deliberate 
on the appropriate approach to the NEPOOL Open Access tariff dispute 
resolution process, which includes an assessment of economic 
consequences of the tariff as currently implied.


                         ENVIRONMENTAL MATTERS

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

     We maintain a program to ensure that we are in compliance with 
environmental regulations.  This includes employee training, regular 
inspection of our facilities, research and development projects, waste 
handling and spill prevention procedures, program monitoring and other 
activities.

Pine Street Barge Canal Site 

     The Federal Comprehensive Environmental Response, Compensation, and 
Liability Act (CERCLA), commonly known as the "Superfund" law, generally 
imposes strict, joint and several liability, regardless of fault, for 
remediation of property contaminated with hazardous substances.  We have  
been notified by the Environmental Protection Agency (EPA) that we are 
one of several potentially responsible parties (PRPs) for cleanup of the 
Pine Street Barge Canal site in Burlington, Vermont, where coal tar and 
other industrial materials were deposited.  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, we were 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.  We remain 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.  In 1994, the EPA 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.

     In June 1998,  the Coordinating Council reached a consensus 
agreement on a recommended plan for remediation of the Pine Street Barge 
Canal site.  As part of the Council's process of reaching a consensus 
recommendation, the Company and certain other parties conditionally 
agreed to fund environmentally beneficial projects in the greater 
Burlington area, the cost of which may reach $3 million.  In June 1998, 
the EPA formally proposed the Council's recommended plan and received 
public comments.

     On September 29, 1998, the EPA issued its final Record of Decision, 
announcing selection of the proposed remedy.  The proposed remedy 
includes:
- 	Construction of an underwater cover over canal sediments that 
   present the highest risk to the environment;
- 	Placement of a soil cap over certain contaminated wetland areas and 
   restoration of those areas;
- 	Improvements that will better distribute storm water entering the 
   site; and
- 	Monitoring of the site to ensure that the cap is effective over the 
   long term and that harmful contamination does not migrate offsite.
The EPA estimates that the present value cost of the remedy would be 
$4.4 million, although actual costs may be higher.

As of December 31, 1998, our total expenditures related to the Pine 
Street Barge Canal site since 1982 were approximately $16 million.  This 
includes those amounts not recovered in rates, amounts recovered in 
rates, and amounts for which rate recovery has been sought but which are 
presently awaiting further VPSB action.  The bulk of these expenditures 
consisted of transaction costs.  Transaction costs include legal and 
consulting costs associated with the Company's opposition to the EPA's 
earlier proposals for the site, as well as litigation and related costs 
necessary to obtain settlements with insurers and other PRPs to provide 
amounts required to fund the clean up (remediation costs) and to address 
liability claims at the site.  A smaller amount of past expenditures was 
for site-related response costs, including costs incurred pursuant to 
the EPA and state orders that resulted in funding response activities at 
the site, and to reimbursing the EPA and the State for oversight and 
related response costs.  The EPA and the State have asserted and 
affirmed that all costs related to these orders are appropriate costs of 
response under CERCLA for which the Company and other PRPs were legally 
responsible.

      The EPA has made claims against us for additional past costs 
associated with the Pine Street Barge Canal site in an amount exceeding 
$11 million.  The EPA also has advised us that we may be responsible for 
implementation of further response activities at the site.  In early 
1998, the United States and the State asked us to begin "fast-track" 
negotiation of tentative terms of settlement of all cost reimbursement 
and natural resource damages claims of the United States and the State.  
Those negotiations began immediately, and included discussion of our 
potential contribution claims against the United States.  In May 1998, a 
confidential tentative agreement was reached on issues under discussion.

     We expect to complete negotiation soon of a final settlement with 
the United States and the State over terms of a Consent Decree that will 
cover claims addressed in the earlier negotiations and implementation of 
the selected remedy.  The Consent Decree must be submitted to a federal 
court for approval and adoption as its order.  We have entered into 
various confidential settlement agreements with other PRPs that provide 
for sharing of past response costs, future cleanup costs and related 
future federal and state monetary claims.  

     We estimate that we have recovered or secured, or will recover, 
through past settlements of litigation claims against insurers and other 
parties, amounts that exceed estimated future remediation costs, future 
federal and state government oversight costs and past EPA response 
costs.  We have concluded that our unrecovered transaction costs 
mentioned above, which were necessary to recover settlements sufficient 
to remediate the site, to oppose much more costly solutions proposed by 
the EPA, to resolve monetary claims of the EPA and the State and to 
remediate the site, are likely to be in the range of $5 to $9 million.  
In 1998, we recorded a liability of $5 million to recognize the low end 
of this range of costs.  The estimated liability is not discounted, and 
it is possible that our estimate of future costs could change by a 
material amount.  We also have recorded an offsetting regulatory asset 
and we believe it is probable that we will receive future revenues to 
recover these costs.

      Through rate cases filed in 1991, 1993, 1994, and 1995, we sought 
and received recovery for ongoing expenses associated with the Pine 
Street Barge Canal site.  Specifically, we proposed rate recognition of 
our non-recovered 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 
full rate recovery of the Pine Street Barge Canal costs, the Department, 
and as applicable, other intervenors, reached agreements with the 
Company in these cases that the full amount of the Pine Street Barge 
Canal costs reflected in those rate cases should be recovered in rates.  
Our rates, as approved by the VPSB in those proceedings, reflected the 
Pine Street Barge Canal related expenditures referred to above.

     We proposed in our rate filing made on June 16, 1997, recovery of 
an additional $3.0 million in such expenditures. In an order in that 
case released March 2, 1998, the VPSB suspended the amortization of 
expenditures associated with the Pine Street Barge Canal site pending 
further proceedings.  Although it did not eliminate the rate base 
deferral of these expenditures, or make any specific order in this 
regard, the VPSB indicated that it was inclined to agree with other 
parties in the case that the ultimate costs associated with the Pine 
Street Barge Canal site, taking into account recoveries from insurance 
carriers and other PRPs, should be "shared" between customers and 
shareholders of the Company.  In response to our Motion for 
Reconsideration, the VPSB on June 8, 1998, stated "our intent, and we 
believe the fair reading of our Order, was to reserve for a future 
docket issues pertaining to the sharing of remediation-releated costs 
between the Company and its customers." See "1997 Retail Rate Case" 
below.

     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 our financial position or results of 
operations in 1998.

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

                      LIQUIDITY AND CAPITAL RESOURCES

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



Capital expenditures over the past three years and forecasted for 1999 
are as follows: 
(Dollars in thousands and net of AFUDC and Customer Advances for 
Construction)

                                                                 Total Net
        Generation Transmission Distribution Conservation Other  Expenditures
Actual:
	1996    $6,287*      $528        $8,422       $3,090     $3,511   $21,838
	1997     3,462*       986         9,680        2,094      3,291    19,513
 1998       543        751         6,063	       1,244      4,568    13,169
Forecasted:
 1999    $1,344       $500        $8,698       $2,200     $8,618** $21,360

*Includes $4.978 and $2.868 million for wind project in 1996 and 1997,  
respectively.
**Includes $5.8 million related to Pine Street Barge Canal site.


1997 Retail Rate Case -- 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 to increase the target return on common 
equity from 11.25 percent to 13 percent.  In our final submissions to 
the VPSB we asked for an increase of 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 its 
Order dated February 27, 1998, in the then pending rate case.  The VPSB 
authorized us to increase our rates by 3.61 percent, which gave us 
increased annual revenues of $5.6 million. 
     The difference between the $22 million we asked for and the $5.6 
million the VPSB authorized was due to the following:
- 	Disallowance of the cost of power associated with the Hydro-Quebec 
   contract discussed below;
- 	The VPSB's modification of our calculation of rate base;
- 	The exclusion of future capital projects from rate base;
- 	Suspension of recovery of Pine Street Barge Canal site 
   expenditures;
- 	Various cost of service reductions in payroll and operations and 
   maintenance; and 
-		A reduction in our requested allowed return on equity from 13 
   percent to 11.25 percent.  

     The VPSB Order denied us the right to charge customers  $5.48 
million of the annual costs for power purchased under our contract with 
Hydro-Quebec.  The VPSB denied recovery of these costs for the following 
reasons:
- 	The VPSB claimed that we had acted imprudently by committing to the 
   power contract with Hydro-Quebec in August 1991 (the imprudence 
   disallowance); and 
- 	To the extent that the costs of power to be purchased from Hydro-
   Quebec are now higher than current estimates of market prices for 
   power during the contract term, after accounting for the imprudence 
   disallowance, the contract power is  not "used and useful".

Generally accepted accounting principles (GAAP) required that we 
record in the first quarter of 1998 the losses resulting from the 
disallowed recovery of a portion of the 1998 Hydro-Quebec power contract 
costs.  The amount charged to first quarter income of $4.6 million (pre-
tax) was less than the full disallowance because we expected that new 
rates would become effective in January 1999 as the result of our May 8, 
1998 rate filing.  The agreement to suspend our 1998 rate case, as 
described below, delays the date of a final decision on the 1998 rate 
case to December 15, 1999, and we recognized an additional loss of $5.25 
million in the last quarter of 1998 representing the effect of the 
presumed continued disallowance of Hydro-Quebec power costs through 
December 15, 1999.  

     In its February 27, 1998 Order, the VPSB described its policies 
that do not allow a utility to recover imprudent expenditures and the 
costs of power supply contract purchases that the VPSB decides are not 
used and useful.  The VPSB also stated in its Order that the methods and 
measures used in this rate case were provisional and applied to this 
rate case only.  If the VPSB were to apply the same, or similar, methods 
and measures that they used in the 1997 rate case Order to future power 
contract costs in our 1998 retail rate case, we would likely be required 
to take a charge to income of approximately $170 million pre-tax.   This 
$170 million estimate represents primarily the 20 percent disallowance 
for Hydro-Quebec power costs that the VPSB considered imprudent in its 
Order. We will not be able to estimate the loss to be recorded for power 
purchased after December 15, 1999, if any, until the pending 1998 rate 
case is completed.

If the VPSB does not modify in future regulatory proceedings its 
ruling that the costs of power purchased from Hydro-Quebec are above 
estimated market rates and are not used and useful and, therefore, a 
portion of such costs is not recoverable, we would likely conclude that 
the VPSB has changed its approach to setting rates from cost-based rate 
making to another form of regulation.  We would then be required to 
discontinue application of Statement of Financial Accounting Standards 
No. 71(SFAS 71), Accounting for the Effects of Certain Types of 
Regulation, described below, and eliminate all regulatory assets and 
liabilities that arose from prior actions of the VPSB.  The write-off of 
these regulatory assets and liabilities, net of any tax effects, would 
be charged to income as an extraordinary item for the financial 
reporting period in which the discontinuation of SFAS 71 occurs. 

     SFAS 71 provides guidance in preparing financial statements for 
public utilities that meet certain criteria of SFAS 71.  The three 
criteria that we must meet in order to follow the accounting guidance 
under SFAS 71 are:
- 	Our rates for regulated services and products provided to our 
   customers must be established by or be subject to approval by an 
   independent, third-party regulator;
- 	The regulated rates are designed to recover our specific costs of 
   providing the regulated services or products; and
- 	Depending on demand for regulated services and products, and the 
   level of competition, direct and indirect, it is reasonable to 
   assume that our rates are set at levels that will recover our costs 
   and that these rates can be charged to and collected from our 
   customers.  This criterion must also take into account anticipated 
   changes in levels of demand or competition during the recovery 
   period for any capitalized costs.

     We meet these criteria at present and, therefore the provisions of 
SFAS 71 apply to us.  Under SFAS 71 we are required to defer certain 
costs that would typically be expensed under GAAP; these costs are 
referred to as deferred charges or regulatory assets.

Our ability to defer a cost is subject to our ability to provide 
evidence that the following additional criteria are met:
- 	It is probable that the inclusion of the capitalized (deferred) 
   cost in allowed costs for ratemaking purposes will provide future 
   revenue in an amount at least equal to the capitalized (deferred) 
   cost; and
- 	The future revenue will be provided to permit recovery of the 
   previously incurred cost rather than to provide for expected levels 
   of similar future costs. 

     Based on the December 31, 1998 balance sheet, if we were required 
to discontinue the application of SFAS 71,  we would be required to take 
an after-tax charge to earnings of approximately $24.6 million 
attributable to net regulatory assets.  

     On March 20, 1998, we filed with the VPSB a Motion for 
Reconsideration of and to Alter or Amend the VPSB's Order released on 
March 2, 1998.  The principal areas in which we requested that the VPSB 
change its ruling included the following:
- 	A correction to the VPSB's calculation of the $5.48 million Hydro-
   Quebec contract power cost disallowance;
- 	Reversal of the accounting treatment specified by the VPSB for cash 
   payments made by Hydro-Quebec under arrangements that we had 
   previously negotiated in order to avoid rate increases in prior 
   years for customers;
- 	Restoration of $418,000  of costs associated with the construction 
   of the Searsburg wind generation facility;
- 	Restoration of various other compensation and payroll costs;
- 	Reversal of the suspension of amortization of costs associated with 
   the Pine Street Barge Canal site; and
- 	Reconsideration of our request to increase the allowed rate of 
   return from 11.25 percent to 12 percent.

     Immediately following the issuance of the June 8, 1998 VPSB Order 
on our Motion for Reconsideration, which largely reaffirmed the earlier 
Order, Duff & Phelps and Standard & Poor's lowered our securities credit 
ratings.  Moody's also subsequently lowered our securities credit 
ratings. 

     In June 1998, we appealed the VPSB's February 27, 1998 Order and 
the June 8, 1998 Reconsideration Order to the Vermont Supreme Court.  
The briefing of the case by all parties was completed in January 1999.  
A hearing before the Vermont Supreme Court is scheduled for March 16, 
1999. A number of other Vermont utilities have submitted briefs in 
support of the Company.  

     We believe that the decisions in the VPSB's February 27, 1998 Order 
and June 8, 1998 Reconsideration Order are factually inaccurate and 
legally incorrect.  Specifically, we are appealing the VPSB's 
determination that we were imprudent in committing to the Hydro-Quebec 
contract in August 1991, and VPSB ruling that because the contract power 
is priced over-market under current forecasts of market prices, it is 
therefore considered "not used and useful."  The Company asserts, among 
other arguments, that the VPSB's Order deprives the Company's 
shareholders of their property in an unconstitutional manner.  The 
VPSB's decision, if not changed, could have a significant negative 
impact on our reported financial condition, and could impact our credit 
ratings, dividend policy and financial viability.

1998	 Retail Rate Case -- On May 8, 1998, we filed a request with the VPSB to 
increase our retail rates by 12.93 percent due to the following increases 
in our cost of service:
- 	The higher cost of power; 
- 	The cost of the January 1998 ice storm; and
- 	Investments in new plant and equipment.  

 The VPSB suspended the tariff filings on June 15, 1998.  We 
submitted testimony in the case that included analysis of viable 
alternatives to the Hydro-Quebec contract at various times in 1991 and 
1992.  The VPSB had taken the viewpoint in our 1997 rate case that we 
would have been able to terminate the Hydro-Quebec contract without 
penalty during that time period, and would have been able to access the 
market for power at that time.  Our analysis showed that, based on price 
only, the Hydro-Quebec contract was less expensive than virtually all 
other long term power resources available at that time.  The analysis 
also showed that when other non-price benefits, like environmental 
benefits and the reliability of a system power resource, are taken into 
account, the Hydro-Quebec contract was still less costly than 
alternatives.  We have testified that even today, when costs and 
benefits for society are accounted for, as Vermont regulators and 
statutes require, the Hydro-Quebec power is not more costly than market 
power.

     In testimony submitted on September 21, 1998, the Vermont 
Department of Public Service (Department) argued for the following:

- 	A $22 million disallowance of Hydro-Quebec contract costs; 
- 	A rate decrease of 3.6 percent; 
- 	The elimination of our common stock dividend; and
- 	Various other restrictions.

     Additionally, the Department's recommendation was that 
approximately $12.5 million of the disallowance of Hydro-Quebec contract 
costs be suspended for one year, which would provide us with a 4.5 
percent rate increase only for that year, followed by automatic 
reinstatement of the larger power cost disallowance with a resulting 
decrease (in 2000) from our rate levels today, absent further VPSB 
order.   The Department recommended this one year delay in the Hydro-
Quebec contract cost disallowance in order to allow us time to negotiate 
lower costs of power under the Hydro-Quebec contract.

     IBM, our largest customer, argued for a rate decrease of 0.2 
percent, a disallowance of Hydro-Quebec power costs in the amount of $13 
million, and the elimination of the common stock dividend.

     In our rebuttal case, we intended to present the VPSB with 
testimony that:
- 	The Department's and IBM's recommendations amount to improper rate 
   making that will have adverse economic and accounting impacts under 
   applicable accounting rules;
- 	The only cogent evidence of alternative portfolios of power 
   resources available in 1991 presented to the VPSB is from our 
   witnesses and the only conclusion that can be drawn from that 
   evidence justifies a determination that there should be no Hydro-
   Quebec power contract cost disallowance; and
- 	We require substantial rate relief in order to ensure our financial 
   stability, access to capital markets and the continuation of 
   adequate, reliable and safe service to our customers.  

     We also intended to present to the VPSB considerable evidence that:
- 	We have made, and continue to make, efforts to achieve a negotiated 
   reformulation of the arrangement with Hydro-Quebec;
- 	Placing us at risk of bankruptcy will not improve our prospects of 
   achieving success in such a negotiation;
- 	Bankruptcy reorganization is not an appropriate public policy 
   solution to high power cost obligations; and  
- 	Our default of obligations to Hydro-Quebec and other creditors 
   would cause substantial risks of default in the same contractual 
   relationships by many other Vermont utilities under "step-up" or 
   similar provisions contained in such arrangements.

     On November 18, 1998, by Memorandum of Understanding (MOU), the 
Company, the Department and IBM agreed to stay, effective November 16, 
1998, rate proceedings in the 1998 rate case until or after September 1, 
1999, or such earlier date as the parties may later agree to or the VPSB 
may order.  The MOU provides for a 5.7 percent temporary retail rate 
increase, to produce $9.19 million in annualized additional revenue, 
effective with service rendered December 15, 1998.  An additional 
surcharge in 1999 will be permitted, without further VPSB order, in 
order to produce additional revenues necessary to provide the Company 
with the capacity to finance estimated 1999 Pine Street Barge Canal site 
expenditures of $5.8 million.  

     The stay and suspension of this pending rate case and the temporary 
rate levels agreed to in the MOU are designed to allow us to continue to 
provide adequate and efficient service to our customers while we seek 
mitigation of power supply costs.

     Following the stay, which expires on September 1, 1999 or such 
earlier date as agreed to by the parties or ordered by the VPSB, the 
remaining proceedings in the case would commence and, as noted above, a 
final VPSB decision would be issued by December 15, 1999.  In the event 
that the VPSB issues a final order that allows a retail rate increase 
that is less than the temporary rates, all sums collected in excess of 
such final rates would be refunded by adjusting rates on a prospective 
basis, by customer class, to reflect the appropriate refund amounts.

      The MOU does not provide for any specific disallowance of power 
costs under our purchase power contract with Hydro-Quebec.  Issues 
respecting recovery of such power costs are preserved for future 
proceedings.

     We agreed not to file with the VPSB a petition requesting any 
further increase in retail electric rates prior to September 1, 1999, 
except that this MOU does not preclude us from filing a request for 
additional temporary rate increases pursuant to 30 V.S.A. Section 226(a).

     The temporary rates include $1 million that is to be used for 
enhanced right of way maintenance and pole testing and treatment.  

     Regulatory asset account balances of $5.1 million, which are 
subject to recovery in this docket, are to be amortized over seven 
years, beginning January 1999.  These balances reflect only the amount 
filed in the May 1998 rate case, and are related to regulatory 
commission expense, tree trimming, storm damage and the costs associated 
with the ice storm of 1998.  This amortization period will be subject to 
review by the VPSB after the expiration of the stay.  

     In the event that the Vermont Supreme Court issues an order 
reversing the VPSB's orders in our 1997 rate case prior to issuance of a 
final order in the 1998 rate case, any resulting adjustments in rates 
will not become effective until the VPSB issues a final order in the 
1998 rate case.  The MOU provides that nothing in it will reduce or 
limit  our entitlement to full recovery of any amounts due us if we 
should prevail on the appeal.  

     The MOU was approved by the VPSB on December 11, 1998.  The 
temporary rates, as adjusted by any surcharge related to the Pine Street 
Barge Canal site described above, will remain in effect until the VPSB 
issues a final order in the rate case docket, expected by December 15, 
1999.
	
     Notwithstanding the interim rate settlement, we are unable to 
predict whether the MOU or other future events, singularly or in 
combination, could cause our lending banks to refuse to allow further 
borrowings under our revolving loan agreement, to seek to enter into a 
new credit agreement with us and/or to immediately call in all 
outstanding loans.  If we are unable to borrow on a short-term basis, we 
will evaluate all potential alternatives available at the time, 
including, but not limited to, the filing of a petition for 
reorganization under the United States Bankruptcy Code.

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

     Our  dividend policy reflects changes affecting the electric 
utility industry, which is moving away from the traditional cost-of-
service regulatory model to a competition based market for power supply, 
as well as earnings projections associated with the rate case 
developments referred to above.   Our current environment has prompted 
us to reassess the appropriateness of our dividend.  The Board of 
Directors will continue to assess and adjust the dividend when 
appropriate, as the Vermont electricity industry evolves towards 
competition. In addition, if other events beyond our control cause our 
financial situation to deteriorate further, the Board of Directors will 
also consider whether the current dividend level is appropriate or if 
the dividend should be reduced or eliminated. 

Financing and Capitalization -- For the period 1996 through 1998, 
internally generated funds, after payment of dividends, provided 
approximately 60 percent of total capital requirements for construction, 
sinking funds and other requirements. Internally generated funds 
provided 25 percent of such requirements for 1998.  We anticipate that 
for 1999, internally generated funds will provide approximately 90 
percent of total capital requirements for regulated operations.

     At December 31, 1998, our capitalization consisted of 50.1 percent 
common equity, 42.3 percent long-term debt and 7.6 percent preferred 
equity.  

     We have a revolving credit agreement in the amount of $45 million 
with three banks, with borrowings outstanding of $7 million on December 
31, 1998.  We also have an uncommitted line of credit in the amount of 
$500,000, under which no amounts were outstanding at December 31, 1998.

     The revolving credit agreement requires us to certify on a 
quarterly basis that we have not suffered a "material adverse change."  
Similarly, as a condition to further borrowings, we must certify that 
nothing has happened that has had or could reasonably be expected to 
have a materially adverse effect on us since the date that we last 
borrowed under this agreement.  When the VPSB issued its Order dated 
February 27, 1998, disallowing certain costs associated with our 
contract to purchase power from Hydro-Quebec, the three banks required 
modification of the terms of the revolving credit agreement that had 
been made originally on August 12, 1997, which was unsecured and had a 
three-year term.  The modified agreement allows us to continue to borrow 
until such time that:
- 	A "material adverse effect" has occurred;
- 	We are no longer in compliance with all other provisions of the 
   agreement, in which case further borrowing will not be permitted; 
   or
- 	There has been a "material adverse change", in which case the banks 
   may declare us in default.  
The modified terms also call in part for the following:
- 	A reduction in the term of the agreement from three years to one 
   year, expiring June 30,1999; 
- 	A second priority mortgage, lien and security interest in the 
   collateral pledged under our first mortgage bond indenture granted 
   to the banks; and 
- 	An increase in the interest rates, facility fees and other fees 
   required to be paid by us under the agreement.

      Required regulatory approval was obtained on June 3, 1998.  The 
restated credit agreement and related loan documents were effective on 
August 17, 1998.  

      There are a number of future events that, singularly or in 
combination, could lead the banks to refuse to allow further borrowings 
under the existing credit agreement, to seek to enter into a new credit 
agreement with us and/or to immediately call in all outstanding loans.  
Some of those events are:
- 	The VPSB issues an order in our pending 1998 rate case that 
   triggers a "material adverse change" for us; or
- 	Hydro-Quebec is unwilling to make new arrangements regarding the 
   cost of power that we purchase  under our contract with them.

     Due to the negative outcome of the 1997 rate case, which was 
decided by the VPSB's orders dated February 27 and June 8, 1998, (See 
Note I of the Notes to Consolidated Financial Statements), the credit 
ratings of our securities by the three rating agencies that rate us were 
lowered as follows:



                             Duff & Phelps     Moody's       Standard & Poor's 
                               From    To     From     To     From     To
                             -------------    -----------    ---------------
  First Mortgage Bonds        BBB+    BBB     Baa2   Baa3     A-      BBB
  Unsecured medium term       BBB     BBB-     -      -       BBB     BB+
  Preferred stock             BBB     BB+     baa3   ba1      BBB     BB

     Standard & Poor's also lowered our corporate credit rating from 
"BBB+" to "BBB-".  Duff & Phelps' and Standard & Poor's credit ratings 
for us were placed and remain on Rating Watch-Down and Credit Watch 
Negative, respectively, due to the high level of regulatory and public 
policy uncertainty in Vermont and certain positions argued by the 
Department  in our rate cases.  Moody's also lowered our ratings due to 
"a difficult regulatory environment in Vermont and the resulting high 
degree of financial uncertainty for GMP" and placed all of our ratings 
on review for possible further downgrade.  See Note F of the Notes to 
Consolidated Financial Statements for a discussion of the bank credit 
facilities available to the Company.  

    Standard & Poor's announced the generic implementation of a single 
credit rating scale for both debt and preferred stock.  As a result, on 
February 23, 1999, they re-rated all preferred stock issues, including 
the Company's, which resulted in the Company's preferred stock being 
rated BB.

Corporate Headquarters Lease - As part of our efforts to reduce 
operating costs, we evaluated options to our corporate headquarters 
lease, which runs through June 2009. We are in the process of 
negotiating the termination of our operating lease for our corporate 
headquarters and two of our service centers.  See Note I of the Notes to 
Consolidated Financial Statements.

     It is probable that we will purchase the lease and sell our 
corporate headquarters in 1999.  We have recorded a loss of 
approximately $1.9 million  (pre-tax) in 1998 to reflect the probable 
loss of completing these transactions.  We would retain ownership of our 
two service centers. 

Year 2000 Computer Compliance -- We use computer software, hardware, and 
other equipment in our business that could be affected by the date 
transition to the next century.  Our primary Year 2000 concern is the 
possibility of interruptions in delivery of electricity to our 
customers.  We are not able to predict the impact of any interruption on 
our operations or earnings, but the impact could be material.  

     In the past several years, we purchased and have nearly completed 
installing new customer service and financial management systems.  These 
systems have greatly reduced our exposure to date-related problems.  We 
will implement and test further upgrades to these systems during 1999 to 
ensure that they are Year 2000 compliant.  We have also replaced 
equipment that would have been affected by the date change.  

     Management has established a project team to address Year 2000 
issues.  The team is focused on three elements that are integral to the 
project: business continuity, project management and risk management.  
Business continuity involves the continuation of reliable electric 
supply and service in a safe and cost-effective manner.  Project 
management involves defining and meeting the project scope schedule and 
budget.  Risk management involves customer management, contingency 
planning and legal issues.  In addition to these internal efforts, we 
are working with various industry groups to coordinate electric utility 
industry Year 2000 efforts.

     The approach to identifying and addressing non-compliant software 
applications and embedded systems consists of the following stages: 
inventory and awareness, assessment, renovation, testing and 
implementation.  The first stage is to inventory all applications and 
systems.  The assessment stage involves determining whether software 
applications and embedded systems are Year 2000 compliant and 
prioritizing remediation needs based on risk management.  The renovation 
stage involves remediating or upgrading applications and systems to make 
them Year 2000 ready.  The testing stage determines whether the 
renovated applications and systems are Year 2000 ready.  The 
implementation stage occurs when the tested applications and systems are 
deployed.  

     We have also developed contingency plans for major outages and are 
adapting these to the special problems posed by the date change to the 
next century.  If an unexpected outage does occur we can operate 
equipment manually and will have personnel at important locations on New 
Years Eve 1999 and into 2000.  

     Our Year 2000 project focuses on those facets of our business that 
are required to deliver reliable electric service.  The project 
encompasses the computer systems that support our core business 
functions such as customer information and billing, finance, 
procurement, supply and personnel as well as the components of metering, 
transmission, distribution and generation support.  The project also 
focuses on embedded systems, instrumentation and control systems in 
facilities.

     The following table summarizes the status of our progress toward 
achieving Year 2000 readiness.  The figures set forth in the table 
represent the estimated extent to which each phase of the Year 2000 
project for software applications and embedded systems have been 
completed.

                                          Software          Embedded
                                          Applications      Systems
                   Inventory . . . . . . . .100%               100%
                   Assessment  . . . . . . . 75%               100%
                   Renovation  . . . . . . . 30%                90%
                   Testing . . . . . . . . . 30%                90%
                   Implementation  . . . . . 30%                90%

     Our current schedule is subject to change, depending on 
developments that may arise through unforeseen business circumstances, 
and through remediation and testing phases of our compliance effort. Our 
ability to deliver electricity to our customers could also be impacted 
if one of our major power suppliers or vendors of telecommunication 
service experienced a date-related system failure.  An interruption in 
power supplied by other delivery systems, such as the independent system 
operator (ISO) for New England, could also cause power delivery problems 
for us.  We are participating in the efforts of the ISO's New England 
Joint Oversight Committee to ensure that the systems and delivery of 
electricity in New England are in compliance.  We have asked these 
companies to send written reports on their status in eliminating Year 
2000 issues that could negatively affect their ability to serve us.  All 
other major vendors or businesses that we depend on for services or 
supplies have also been asked to report on their status.  

     The total cost of remediating or upgrading software that would not 
otherwise be replaced in accordance with our business plans is 
approximately $376,000.  Approximately $50,000 has been expended as of 
December 31, 1998 for external labor, hardware and software costs, and 
for the costs of employees who are dedicated to the Year 2000 project.  
The foregoing amounts do not include the cost of new software 
applications installed as a result of strategic replacement projects 
described earlier.  Such replacement projects have not been accelerated 
because of Year 2000 issues. 

     The cost of the project and the dates on which we plan to complete 
our Year 2000 modifications are based on management's best estimates, 
which were derived utilizing numerous assumptions of future events, 
including the continued availability of certain resources, third 
parties' Year 2000 readiness and other factors.   Further, we expect to 
incur additional costs after 1999 to remediate and replace less critical 
software applications and embedded systems.

     We have also begun the process of developing contingency plans to 
address the most reasonably likely worst case scenarios that could occur 
in the event that various Year 2000 issues are not resolved in a timely 
manner.  Contingency planning is an ongoing process and will continue 
through the fourth quarter of 1999.

     The phases of our contingency planning process include business 
impact analysis, contingency planning and testing.  Business impact 
analysis requires business unit personnel to evaluate the impact of 
mission-critical systems failure on our core business operations, 
focusing on specific failure scenarios and how they can be mitigated.  
The necessary conditions for enacting the plans will be documented along 
with the appropriate personnel responsible in each of the business units 
should a Year 2000 failure occur.  Additionally we have participated in 
system readiness drills to simulate major outages and restart capability 
and will continue to participate in scheduled drills in 1999.

     Based on our current schedule for completion of Year 2000 tasks, we 
believe that our planning is adequate to secure Year 2000 readiness of 
our critical systems.  Nevertheless, achieving Year 2000 readiness is 
subject to various risks and uncertainties, many of which are described 
above.  We are not able to predict all the factors that could cause 
actual results to differ materially from our current expectations as to 
our Year 2000 readiness.  However, if we, or third parties with whom we 
have significant business relationships, fail to achieve Year 2000 
readiness with respect to critical systems, there could be a material 
adverse effect on our results of operations, financial position and cash 
flows.  

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 AND ORGANIZATIONAL CHANGES

     In 1998, in response to changes in the electric utility industry, 
we initiated work to reduce our non-power supply costs and position the 
Company as a distribution company with potential to grow.  Through an 
early retirement incentive option and voluntary severance packages 
offered in 1998, we reduced the core workforce by 10 percent.  The cost 
associated with this workforce change was approximately $3 million 
pretax in 1998, but is expected to result in significant future cost 
savings.  We expensed $1.3 million of these costs, and received an 
accounting order from the VPSB allowing us to defer the remaining $1.7 
million expended in 1998, which we plan to seek and expect to receive 
recovery of in our current or future rate proceedings.

     Concurrently, three of the senior management team left the Company 
on December 31, 1998, thereby reducing the executive ranks by 20 
percent.  The officers were:
- 	Richard B. Hieber, Senior Vice President and Chief Operating 
   Officer,
- 	Edwin M. Norse, Vice President, Chief Financial Officer and 
   Treasurer, and 
- 	Robert C. Young, Assistant Vice President, Customer Operations.
     On November 23, 1998, Nancy R. Brock was elected Vice President, 
Chief Financial Officer and Treasurer by the Company's Board of 
Directors.  On February 8, 1999, the Company's Board of Directors 
elected Mary G. Powell, Vice President, Administration.


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, 1998, 1997, and 1996 . . . . . . . .  48

Consolidated Statements of Cash Flows For the 
    Years Ended December 31, 1998, 1997 and 1996  . . . . . . . . . . . .  49

Consolidated Balance Sheets as of
    December 31, 1998 and 1997  . . . . . . . . . . . . . . . . . . . . .  50

Consolidated Capitalization Data as of
    December 31, 1998 and 1997  . . . . . . . . . . . . . . . . . . . . .  52

Notes to Consolidated Financial Statements  . . . . . . . . . . . . . . .  53

Quarterly Financial Information . . . . . . . . . . . . . . . . . . . . .  67

Report of Independent Public Accountants  . . . . . . . . . . . . . . . .  81

Schedules

For the Years Ended December 31, 1998, 1997 and 1996:

    II  Valuation and Qualifying Accounts and Reserves  . . . . . . . . .  82

             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  . . . . . . . . .81,95

             Arthur Andersen LLP                                       


<TABLE>
<CAPTION>


                            CONSOLIDATED STATEMENTS OF INCOME

        GREEN MOUNTAIN POWER CORPORATION   For the Years Ended December 31




                                                                      1998                1997                1996
                                                                -----------------    ---------------     ---------------
                                                                         (In thousands, except amounts per share)

<S>                                                                     <C>                <C>                 <C>
Operating Revenues..............................................        $184,304           $179,323            $179,009
                                                                -----------------    ---------------     ---------------
Operating Expenses
  Power Supply 
     Vermont Yankee Nuclear Power Corporation...................          32,910             32,817              30,596
     Company-owned generation...................................           6,412              5,327               3,330
     Purchases from others......................................          81,706             62,222              66,320
  Other operating...............................................          21,291             16,780              17,615
  Transmission.................................................            9,389             11,122              10,833
  Maintenance...................................................           5,190              4,785               4,463
  Depreciation and amortization.................................          16,059             16,359              16,280
  Taxes other than income.......................................           7,242              7,205               6,982
  Income taxes..................................................          (1,367)             7,191               6,463
                                                                -----------------    ---------------     ---------------
     Total operating expenses...................................         178,832            163,808             162,882
                                                                -----------------    ---------------     ---------------
       Operating Income.........................................           5,472             15,515              16,127
                                                                -----------------    ---------------     ---------------

Other Income
  Equity in earnings of affiliates and 
     non-utility operations.....................................             (28)               427               2,880
  Allowance for equity funds used during construction...........             104                357                 175
  Other income (deductions), net................................            (549)               789                 175
                                                                -----------------    ---------------     ---------------
    Total other income (deductions).............................            (473)             1,573               3,230
                                                                -----------------    ---------------     ---------------
      Income before interest charges............................           4,999             17,088              19,357
                                                                -----------------    ---------------     ---------------

Interest Charges
  Long-term debt................................................           6,991              7,274               6,872
  Other.........................................................           1,016                691                 994
  Allowance for borrowed funds used during 
     construction...............................................            (131)              (315)               (468)
                                                                -----------------    ---------------     ---------------
    Total interest charges......................................           7,876              7,650               7,398
                                                                -----------------    ---------------     ---------------
Net Income (Loss)...............................................          (2,877)             9,438              11,959

Dividends on preferred stock....................................           1,296              1,433               1,010
                                                                -----------------    ---------------     ---------------
Net Income (Loss) Applicable to Common Stock....................         ($4,173)            $8,005             $10,949
                                                                =================    ===============     ===============

Common Stock Data
  Earnings (loss) per share.....................................          ($0.80)             $1.57               $2.22

  Cash dividends declared per share.............................         $0.9625              $1.61               $2.12

  Weighted average shares outstanding...........................           5,243              5,112               4,933


                       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


                                                                         1998          1997          1996
                                                                       ---------     ---------     ---------
                                                                                  (In thousands)

<S>                                                                     <C>            <C>          <C>
Operating Activities:
  Net Income (Loss).................................................... ($2,877)       $9,438       $11,959
  Adjustments to reconcile net income to net cash
    provided by operating activities:
      Depreciation and amortization....................................  16,059        16,359        16,280
      Dividends from associated companies less equity income...........     812           (90)          254
      Allowance for funds used during construction.....................    (235)         (672)         (643)
      Deferred purchased power costs...................................  (7,830)         (331)       (5,917)
      Amortization of purchased power costs............................   6,405         5,212         5,187
      Deferred income taxes............................................    (112)       (2,715)        1,937
      Amortization of investment tax credits...........................    (282)         (282)         (282)
      Environmental proceedings costs, net.............................   3,010        (2,123)       (1,720)
      Conservation expenditures........................................  (1,833)       (2,411)       (3,207)
      Changes in:
        Accounts receivable............................................  (1,611)          368           347
        Accrued utility revenues.......................................    (105)          156          (139)
        Fuel, materials and supplies...................................     122           359          (309)
        Prepayments and other current assets...........................    (983)       (6,749)         (354)
        Accounts payable...............................................  (1,893)        1,728           221
        Taxes accrued..................................................  (2,473)        1,856           415
        Interest accrued...............................................    (108)          (71)         (465)
        Other current liabilities......................................   3,229          (164)        1,065
      Other............................................................     644         6,635         1,738
                                                                       ---------     ---------     ---------
    Net cash provided by operating activities..........................   9,939        26,503        26,367
                                                                       ---------     ---------     ---------

Investing Activities:
    Construction expenditures.......................................... (10,900)      (16,409)      (17,541)
    Investment in non-utility property.................................  (1,442)          218        (2,203)
    Proceeds from sale of propane subsidiary...........................  11,500          --            --
                                                                       ---------     ---------     ---------
      Net cash used in investing activities............................    (842)      (16,191)      (19,744)
                                                                       ---------     ---------     ---------
Financing Activities:
    Issuance of preferred stock........................................    --            --          12,000
    Reduction in preferred stock.......................................  (1,650)       (1,575)       (1,620)
    Issuance of common stock...........................................   1,587         3,023         4,642
    Short-term debt, net...............................................   4,384         1,600        (7,400)
    Issuance of long-term debt.........................................    --            --          14,000
    Reduction in long-term debt........................................  (6,767)       (4,201)      (16,201)
    Cash dividends.....................................................  (6,332)       (9,637)      (11,455)
                                                                       ---------     ---------     ---------
      Net cash used in financing activities............................  (8,778)      (10,790)       (6,034)
                                                                       ---------     ---------     ---------

    Net increase (decrease) in cash and cash equivalents...............     319          (478)          589
    Cash and cash equivalents at beginning of year.....................     271           749           160
                                                                       ---------     ---------     ---------
Cash and Cash Equivalents at End of Year...............................    $590          $271          $749
                                                                       =========     =========     =========

        The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>



<TABLE>
<CAPTION>

                          CONSOLIDATED BALANCE SHEETS

                   GREEN MOUNTAIN POWER CORPORATION    December 31


                                                                1998               1997
                                                              ---------          ---------
                                                                     (In thousands)
ASSETS
<S>                                                           <C>                <C>
Electric Utility
Utility Plant 
    Utility plant, at original cost...........................$276,853           $265,441
    Less accumulated depreciation.............................  94,604             87,689
                                                              ---------          ---------
      Net utility plant....................................... 182,249            177,752
    Property under capital lease..............................   7,696              8,342
    Construction work in progress.............................   5,611             10,626
                                                              ---------          ---------
      Total utility plant, net................................ 195,556            196,720
                                                              ---------          ---------
Other Investments
    Associated companies, at equity ..........................  15,048             15,860
    Other investments ........................................   5,630              6,137
                                                              ---------          ---------
      Total other investments.................................  20,678             21,997
                                                              ---------          ---------
Current Assets
    Cash and cash equivalents.................................     439                118
    Accounts receivable, customers and others, less allowance
      for doubtful accounts of $449 and $385..................  18,977             17,365
    Accrued utility revenues..................................   6,611              6,505
    Fuel, materials and supplies, at average cost.............   3,139              3,261
    Prepayments...............................................   6,091              1,563
    Other.....................................................     443                313
                                                              ---------          ---------
      Total current assets....................................  35,700             29,125
                                                              ---------          ---------
Deferred Charges
    Demand side management programs...........................  10,590             13,692
    Purchased power costs.....................................   5,708              4,283
    Other.....................................................  14,278              9,415
                                                              ---------          ---------
      Total deferred charges..................................  30,576             27,390
                                                              ---------          ---------
Non-Utility
    Cash and cash equivalents.................................     151                153
    Other current assets......................................   7,823             11,501
    Property and equipment....................................   1,213             10,784
    Intangible assets.........................................   1,658              2,116
    Equity investment in energy-related businesses............  12,357             12,824
    Other assets..............................................   4,112              4,682
                                                              ---------          ---------
      Total non-utility assets................................  27,314             42,060
                                                              ---------          ---------
Total Assets..................................................$309,824           $317,292
                                                              =========          =========

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



                   GREEN MOUNTAIN POWER CORPORATION    December 31

                                                                1998               1997
                                                              ---------          ---------
                                                                     (In thousands)

CAPITALIZATION AND LIABILITIES

Electric Utility
Capitalization (See Capitalization Data)
    Common Stock Equity 
      Common stock............................................ $17,711            $17,318
      Additional paid-in capital..............................  71,914             70,720
      Retained Earnings.......................................  17,508             26,717
      Treasury stock, at cost.................................    (378)              (378)
                                                              ---------          ---------
        Total common stock equity............................. 106,755            114,377
    Redeemable cumulative preferred stock.....................  16,085             17,735
    Long-term debt, less current maturities ..................  88,500             93,200
                                                              ---------          ---------
        Total capitalization.................................. 211,340            225,312
                                                              ---------          ---------

Capital Lease Obligation .....................................   7,696              8,342
                                                              ---------          ---------

Current Liabilities
    Current maturuties of long-term debt......................   1,700              1,700
    Short-term debt...........................................   7,000              2,616
    Accounts payable, trade, and accrued liabilities..........   5,453              6,828
    Accounts payable to associated companies..................   7,143              7,661
    Dividends declared........................................     362                350
    Customer deposits.........................................     336                721
    Taxes Accrued.............................................     370              2,843
    Interest accrued..........................................   1,203              1,311
    Other.....................................................   5,258              1,256
                                                              ---------          ---------
        Total current liabilities.............................  28,825             25,286
                                                              ---------          ---------
Deferred Credits
    Accumulated deferred income taxes.........................  23,389             23,501
    Unamortized investment tax credits........................   4,260              4,542
    Pine street Marsh clean-up................................   5,000               --
    Other.....................................................  22,240             17,239
                                                              ---------          ---------
        Total deferred credits................................  54,889             45,282
                                                              ---------          ---------

Non-Utility
    Current liabilities.......................................     720              1,119
    Other liabilities.........................................   6,354             11,951
                                                              ---------          ---------
        Total non-utility liabilities.........................   7,074             13,070
                                                              ---------          ---------
Total Capitalization and Liabilities..........................$309,824           $317,292
                                                              =========          =========

  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        1998         1997         1998         1997
                                                                    -----------    ----------   ----------    ---------    ---------
                                                                                                                    (In thousands)
<S>                                                                   <C>            <C>          <C>            <C>          <C> 
Common Stock,$3.33 1/3 par value (Note C)........................   10,000,000     5,313,296    5,195,432      $17,711      $17,318
                                                                                                              =========    =========
     -----------------------------------------------------------------------------------------------------------------

                                                                                            Outstanding
                                                         Authorized   Issued          1998         1997         1998         1997
                                                         ---------- -----------    ----------   ----------    ---------    ---------
                                                                                                                  (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         2,250        2,850         $225         $270
   7%,Class C, redeemable at
     $101 per share......................................    15,000     15,000         4,200        4,650          420          465
   9.375%,Class D,Series 1,
     redeemable at $101 per share........................    40,000     40,000         6,400        9,600          640          800
   8.625%,Class D,Series 3,
     redeemable at $101.919 per share....................    70,000     70,000        28,000       56,000        2,800        4,200
   7.32%,Class E,Series 1,...............................   200,000    120,000       120,000      120,000       12,000       12,000
                                                                                                              ---------    ---------
Total Preferred Stock....................................                                                      $16,085      $17,735
                                                                                                              =========    =========


LONG-TERM DEBT (Note E)                                                                                         1998         1997
                                                                                                              ---------    ---------
                                                                                                                  (In thousands)

First Mortgage Bonds
  7% Series due 1998..........................................................................................$   --         $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................................................................................................  10,200       11,900
  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..............................................................................  90,200       94,900
  Less Current Maturities (due within one year)...............................................................   1,700        1,700
                                                                                                              ---------    ---------
Total Long-term Debt, Net..................................................................................... $88,500      $93,200
                                                                                                              =========    =========

                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 electric services company located in Vermont that 
serves approximately one-quarter of the State's 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 83,500 retail and wholesale 
customers.  At December 31, 1998, the Company's primary subsidiary 
investment was in Mountain Energy Inc., which invests in energy 
generation, energy efficiency and wastewater treatment projects across 
the United States.  In 1998 the Company sold the assets of its wholly 
owned propane gas subsidiary, Green Mountain Propane Gas Company (GMPG).  
The impact of this transaction did not have a material impact on the 
Company's results of operations.  In 1998, through its subsidiary, Green 
Mountain Resources, Inc. (GMRI), the Company agreed to sell its 
remaining interest in Green Mountain Energy Resources L.L.C. (GMER) to 
Green Funding I in early 1999.  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   
                                          1998          1997          1996
                                          ----          ----          ----
                                                (In thousands)
   Revenues . . . . . . . . . . . . .  $ 4,967       $11,842        $11,997
   Expenses . . . . . . . . . . . . .    7,035        13,439         11,207
                                       --------      --------        ------
   Net Income (Loss)  . . . . . . . .  $(2,068)      ($1,597)          $790
                                       ========      ========        ======


     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 Vermont Public Service Board (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 accounts 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 its costs 
of providing regulated service, 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 its 
net regulatory assets and liabilities which totaled $24.6 million as of 
December 31, 1998.

     SFAS 121, Accounting for the Impairment of Long Lived Assets, 
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, 1998, based upon the 
regulatory environment within which the Company currently operates, no 
impairment loss was recorded under SFAS 121.  Competitive influences or 
regulatory developments may impact this status in the future.  


     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:
                                            1998        1997       1996
                                            ----        ----       ----
                                                  (In thousands)
   Interest  . . . . . . . . . . . . . .  $7,857      $7,800     $8,104
   Income Taxes (Net of refunds) . . . .   2,285       5,853      3,727

     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 3.7 percent of 
total depreciable property at the beginning of 1998 and 3.6 percent at 
the beginning of 1997 and 1996.


     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, 1998, other deferred charges totaled $14.3 million, 
consisting of regulatory proceedings expenses, regulatory deferrals of 
storm damages, deferred termination costs associated with the Company's 
workforce reduction, preliminary survey and investigation charges, 
rights-of-way maintenance, unamortized debt expense, repair costs for 
the Essex and Vergennes hydroelectric facilities and transmission 
interconnection charges and various other projects and deferrals. 
    
    8. Earnings (Loss) Per Share.  Earnings (loss) per share are based 
on the weighted average number of shares of common stock outstanding 
during each year.

     Statement of Financial Accounting Standards No. 128, Earnings per 
Share (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 14.7, 14.0 and 
13.2 percent of operating revenues in 1998, 1997 and 1996, respectively.


     10. Pension and Retirement Plans.  The Company has a defined 
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.   As a result of a rate order issued by the VPSB, the 
Company now accounts for its deferred pension plan under the provisions 
of SFAS 87, Employers' Accounting for Pensions.  Prior to this, the 
Company recorded annual expense based on amounts funded in accordance 
with methods approved in the rate-setting process.  

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

     Accrued postretirement health care expenses are recovered in rates 
if those expenses are funded.  In order to maximize the tax deductible 
contributions that are allowed under IRS regulations, the Company 
amended its pension plan to establish a 401-h subaccount and 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.

     In 1998, the Company adopted SFAS 132, Employers' Disclosures about 
Pensions and Other Postretirement Benefits.  The provisions of SFAS 132 
revise employers' disclosures about pension and other postretirement 
benefit plans. It does not change the measurement or recognition of 
these plans but standardizes the disclosure requirements for pensions 
and other postretirement benefits to the extent possible.

The following provides a reconciliation of benefit obligations, plan 
assets and funded status of the plans as of December 31, 1998 and 1997. 



<TABLE>
<CAPTION>
                                                                                            Other
                                                      Pension Benefits             Postretirement Benefits
                                                    ---------------------          -------------------------
                                                       1998       1997                 1998        1997
                                                    ---------------------          -------------------------
                                                      (In thousands)                    (In thousands)
<S>                                                    <C>       <C>                   <C>           <C> 
Change in Projected Benefit Obligation:
 Projected benefit obligation as of prior year end..   $28,630   $25,615               $11,046       $9,202
 Service cost.......................................       787       720                   282          228
 Interest cost......................................     2,043     2,069                   799          763
 Loss on immediate retirement.......................    --         --                       42       --
 Special termination benefit........................     2,026     --                       44       --
 Change in discount rate............................    --         --                      897          964
 Other..............................................    --         --                    --             435
 Actuarial loss.....................................       438     2,290                 --          --
 Benefits paid......................................    (3,064)   (1,852)                 (558)        (546)
 Curtailment........................................    --          (212)                --          --
                                                    ---------------------          -------------------------
Projected benefit obligation as of year end.........   $30,860   $28,630               $12,552      $11,046
                                                    =====================          =========================

Change in Plan Assets:
 Fair value of plan assets as of prior year end.....   $35,773   $31,286                $7,893       $6,327
 Contributions......................................    --         --                       76       --
 Actual return on plan assets.......................     5,321     6,339                 1,766        1,566
 Benefits paid......................................    (3,064)   (1,852)                --          --
                                                    ---------------------          -------------------------
Fair value of plan assets as of year end............   $38,030   $35,773                $9,735       $7,893
                                                    =====================          =========================

Funded status as of year end........................    $7,170    $7,143               ($2,817)     ($3,153)
Unrecognized transition obligation (asset)..........    (1,021)   (1,249)                4,926        5,278
Unrecognized prior service cost.....................     1,113     1,247                  (743)        (805)
Unrecognized net actuarial gain.....................    (7,569)   (5,962)               (1,471)      (1,400)
Adjustments due to actions of regulator.............       --     (1,179)                  --           --
                                                    ----------------------         --------------------------
Prepaid (accrued) benefit cost as of year end.......     ($307)     $--                  ($105)        ($80)
                                                    ======================         ==========================

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, 1998, 1997 and 1996 were $397,000, $456,000 and $494,000, respectively, under this plan.
This plan is funded in part through insurance contracts.


                                                                                            Other
                                                      Pension Benefits             Postretirement Benefits
                                                    ---------------------          -------------------------
                                                       1998       1997                 1998        1997
                                                    ---------------------          -------------------------
<S>                                                       <C>       <C>                   <C>          <C>
Weighted average assumptions as of year end:
Discount rate.......................................      6.75%     7.25%                 6.75%        7.25%
Expected return on plan assets......................      9.00%     9.00%                 8.50%        8.50%
Rate of compensation increase.......................      4.00%     4.50%                --          --

Net periodic pension and other postretirement
benefit costs include the following components:

                                                                                                  Other
                                                            Pension Benefits               Postretirement Benefits
                                                    ------------------------------ ------------------------------------
                                                       1998       1997     1996        1998        1997        1996
                                                    ------------------------------ ------------------------------------
                                                                        (In Thousands)
<S>                                                     <C>        <C>      <C>           <C>          <C>        <C>
Service cost........................................      $787      $720     $689         $282         $228       $247
Interest cost.......................................     2,043     2,069    1,912          799          763        698
Expected return on plan assets......................    (3,081)   (2,739)  (2,513)        (671)        (539)      (464)
Amortization of transition asset....................      (228)     (228)    (228)       --          --           --
Amortization of net gain from earlier periods.......      --         --        --          (17)         (28)       (45)
Amortization of prior service cost..................       134       143      141          (61)         (61)       (61)
Amortization of the transition obligation...........      --         --        --          351          351        352
Recognized net actuarial gain.......................      (195)      (83)     (27)       --          --           --
Special termination benefit.........................     2,026       --        --           44       --           --
Effect of voluntary retirement programs.............      --         --       416        --          --           --
Adjustment due to actions of regulator..............      --         126     (366)       --          --           --
                                                    ------------------------------ ------------------------------------
Net periodic benefit cost...........................    $1,486        $8      $24         $727         $714       $727
                                                    ============================== ====================================

For postretirement benefit cost measurement purposes, a 5.6 percent annual rate of increase in the per capita
cost of covered benefits was assumed for 1998; the rate was assumed to decrease gradually to 5.0 percent by
the year 2002 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, 1998
by $1.9 million and the aggregate of the service and interest components of net periodic postretirement benefit cost
fot the year ended December 31, 1998 by $170,000.

The special termination benefit recorded in 1998 resulted from the early retirement incentive option offered to
employees in 1998.

The curtailment recorded in 1997 resulted from the effect of the voluntary retirement option offered
to employees in 1996.

Prior to 1998 the Company recorded annual expense and prepaid (accrued) benefit cost on the cash basis in accordance
with methods approved in the rate-setting process. The adjustment to accomplish this accounting was through
the line item "Adjustments due to actions of regulator."

</TABLE>

     11. Fair Value of Financial Instruments.  If the first mortgage 
bonds and preferred stock outstanding at December 31, 1998 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 increase from the amounts outstanding on the 
December 31, 1998 balance sheet by approximately 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.


     12. Deferred Credits.  At December 31, 1998, the Company had other 
deferred credits and long-term liabilities of $22.2 million, consisting 
of operating lease equalization, reserves for damage claims and 
environmental liabilities and accruals for employee benefits and 
deferred compensation.


     13.  Segments and Related Information.  In 1998, the Company 
adopted SFAS No. 131, Disclosures About Segments of an Enterprise and 
Related Information.

     The Company has two reportable segments, the electric utility and 
Mountain Energy, Inc.  The electric utility is engaged in supplying 
electrical energy in the State of Vermont and also reports the results 
of its wholly-owned unregulated subsidiaries (GMPG, GMRI, GMP Real 
Estate, Lease-Elec, Inc., and the rental water heater program) as a 
separate line item in the Other Income Section in the Consolidated 
Statement of Income.

     Mountain Energy, Inc. is an unregulated business that invests in 
energy generation, energy efficiency and waste water treatment projects.  

     Segment information for the year ended December 31, 1998 includes 
the following:

                                           Electric       Mountain Energy
                                           --------       ---------------
                                                 (In thousands)
Revenues-external . . . . . . . . . . . .  $184,304          $2,092
Interest income   . . . . . . . . . . . .       ---           1,344   
Depreciation and amortization . . . . . .    16,059             382
Interest expense  . . . . . . . . . . . .     7,876             183
Income taxes  . . . . . . . . . . . . . .    (1,367)         (1,463)
Earnings (loss) of equity investments . .       (28)          1,840
Segment loss  . . . . . . . . . . . . . .    (2,087)         (2,086)
Segment assets  . . . . . . . . . . . . .   283,014          26,810
Capital expenditures  . . . . . . . . . .    10,879              21
Equity investments  . . . . . . . . . . .    15,048          12,413


Segment information for the year ended December 31, 1997 includes the 
following:

                                           Electric       Mountain Energy
                                           --------       ---------------
                                                 (In thousands)
Revenues-external . . . . . . . . . . . .  $179,323          $4,500
Interest income . . . . . . . . . . . . .       ---           2,654
Depreciation and amortization . . . . . .    16,359             125
Interest expense  . . . . . . . . . . . .     7,650             207
Income taxes  . . . . . . . . . . . . . .     7,191             104
Earnings of equity investments  . . . . .       427             305
Segment profit  . . . . . . . . . . . . .     7,863             142
Segment assets  . . . . . . . . . . . . .   292,246          25,046
Capital expenditures  . . . . . . . . . .    16,394              15
Equity investments  . . . . . . . . . . .    15,860          11,449


Segment information for the year ended December 31, 1996 includes the 
following:

                                           Electric       Mountain Energy
                                           --------       ---------------
                                                 (In thousands)
Revenues-external  . . . . . . . . . . .  $179,009          $2,848
Interest income  . . . . . . . . . . . .      ---            1,276
Depreciation and amortization  . . . . .    16,280              13
Interest expense . . . . . . . . . . . .     7,398             213
Income taxes . . . . . . . . . . . . . .     6,463             803
Earnings of equity investments . . . . .     2,880           1,631
Segment profit . . . . . . . . . . . . .     9,633           1,316
Segment assets . . . . . . . . . . . . .   285,877          21,498
Capital expenditures . . . . . . . . . .    17,538               3
Equity investments . . . . . . . . . . .    15,769          12,944
   
     Net income (loss) of Mountain Energy, Inc.  is included in the 
Equity (Loss) in Earnings of Affiliates and Non-Utility Operations line 
of the Consolidated Statement of Income.

	The following table is a reconciliation of Mountain Energy's income 
(loss) to the equity (loss) in earnings of affiliates and non-utility 
operations:
                                               For the year ended December 31,
                                               1998        1997       1996
                                               ----        ----       ----
                                                       (In thousands)
Mountain Energy income (loss) . . . . . . . ($2,086)     $  142    $ 1,316
Electric equity (loss) in earnings of 
  affiliates and non-utility operations . .   2,058         285      1,564
                                            --------     ------    -------
Total equity (loss) in earnings of 
  affiliates and non-utility operations . .    ($28)     $  427    $ 2,880
                                            ========     =======   =======

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

15.	New Accounting Pronouncements.  
           Statement of Position (SOP 98-1).    In 1998, the Company 
adopted SOP 98-1, Accounting for the Costs of Computer Software 
Developed or Obtained for Internal Use.  The provisions of SOP 98-1 
require that administrative and general costs, training costs, and 
overheads incurred during software development be expensed. The Company 
has historically capitalized these costs.  Adoption of SOP 98-1 did not 
have a material impact on the Company's reported financial position or 
its results of operations for 1998.

          SFAS 133.  In June 1998, the Financial Accounting Standards 
Board issued Statement of Financial Accounting Standards No. 133 (SFAS 
133), Accounting for Derivative Instruments and Hedging Activities.  
SFAS 133 establishes accounting and reporting standards requiring that 
every derivative instrument (including certain derivative instruments 
embedded in other contracts) be recorded in the balance sheet as either 
an asset or liability measured at its fair value.  SFAS 133 requires 
that changes in the derivative's fair value be recognized currently in 
earnings unless specific hedge accounting criteria are met.  Special 
accounting for qualifying hedges allows a derivative's gains and losses 
to offset related results on the hedged item in the income statement, 
and requires that a company must formally document, designate, and 
assess the effectiveness of transactions that receive hedge accounting.   
SFAS 133 is effective for fiscal years beginning after June 15, 1999. 
SFAS 133 must be applied to (a) derivative instruments and (b) certain 
derivative instruments embedded in hybrid contracts that were issued, 
acquired, or substantively modified after December 31, 1997 (and, at the 
Company's election, before January 1, 1998).

     The Company has not yet quantified the impacts of adopting SFAS 133 
on its financial statements and has not determined the timing of or 
method of its adoption of SFAS 133.  However, SFAS 133 could increase 
volatility in earnings and other comprehensive income.

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

B. 	INVESTMENTS IN ASSOCIATED COMPANIES

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

                          Percent Ownership      Investment in Equity
                         at December 31, 1998       December 31,    
                         --------------------    --------------------
                                                    1998         1997
                                                    ----         ----
                                                    (In thousands)
VELCO - Common . . . . . . . . . . 29.5%          $1,828       $1,833
      - Preferred  . . . . . . . . 30.0%             829          961
                                                   -----        -----
Total VELCO  . . . . . . . . . . .                 2,657        2,794
Vermont Yankee - Common  . . . . . 17.9%           9,759        9,701
New England Hydro-Transmission -
     Common  . . . . . . . . . . .  3.18%          1,015        1,063
New England Hydro-Transmission
      Electric -  Common . . . . .  3.18%          1,615        1,811
                                                 -------      -------
                                                 $15,046      $15,369
                                                 =======      =======

     Undistributed earnings in associated companies totaled $699,000 at 
December 31, 1998.


     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 its transmission system.  The Company's purchases of transmission 
services from VELCO were $7.1 million, $7.6 million and $7.7 million for 
the years 1998, 1997 and 1996, 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,
                                                   1998       1997       1996 
                                                   ----       ----       ----
                                                       (In thousands)
Company's equity in net income . . . . . . . .   $  338     $  354     $  383
                                                 ======     ======     ======
Total assets . . . . . . . . . . . . . . . . .  $67,658    $70,566    $74,065
Less:
    Liabilities and long-term debt . . . . . .   58,690     61,162     61,159
                                                 ------     ------    -------
Net assets . . . . . . . . . . . . . . . . . .   $8,968     $9,404    $ 9,906
                                                 ======     ======    =======
Company's equity in net assets . . . . . . . .   $2,657     $2,794    $ 2,952
                                                 ======     ======    =======


     Vermont Yankee.  The Company is responsible for 17.9 percent of 
Vermont Yankee's expenses of operations, including costs of equity 
capital and estimated costs of decommissioning, and is entitled to a 
similar share of the power output of the nuclear plant, which has a net 
capacity of 531 megawatts.  Vermont Yankee's current estimate of 
decommissioning costs is approximately $407 million, of which $260 
million has been funded.  At December 31, 1998, the Company's portion of 
Vermont Yankee's net unfunded liability was $26 million, which it 
expects will be recovered through rates over Vermont Yankee's remaining 
operating life.  Vermont Yankee is in the process of preparing an 
updated site decommissioning cost study.  Preliminary results indicate 
that the revised estimate could exceed $500 million in 1998 dollars.  
Vermont Yankee is required to file the results of the new study with the 
FERC by March 31, 1999, and expects that any resulting change in rates 
will be effective January 1, 2000.  As a sponsor of Vermont Yankee, the 
Company also is obligated to provide 20 percent of capital requirements 
not obtained by outside sources.  During 1998, the Company incurred 
$27.2 million in Vermont Yankee annual capacity charges, which included 
$2.0 million for interest charges.  The Company's share of Vermont 
Yankee's long-term debt at December 31, 1998 was $16.7 million.

     The Price-Anderson Act currently sets  the statutory liability from 
a single incident at a nuclear power plant at $9.8 billion.  Any damages 
beyond $9.8 billion are indemnified under the Price-Anderson Act, but 
subject to Congressional approval.  The first $200 million of liability 
coverage is the maximum provided by private insurance.  The Secondary 
Financial Protection Program is a retrospective insurance plan providing 
additional coverage up to $9.6 billion per incident by assessing each of 
the 109 reactor units that are currently subject to the Program in the 
United States for a total of $88.1 million, limited to a maximum 
assessment of $10 million per incident per nuclear unit in any one year.  
The maximum assessment is adjusted at least every five years to reflect 
inflationary changes.

     The above insurance 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.  
However, Vermont Yankee does 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.
     For recent events related to Vermont Yankee, see NOTE L-3 -- 
Subsequent Events.



     Summarized financial information for Vermont Yankee is as follows:
                                                    December 31,
                                               1998       1997        1996  
                                               ----       ----        ----
                                                    (In thousands)
Earnings:
   Operating revenues . . . . . . . . .    $195,249   $173,106    $181,715
   Net income applicable to common 
      Stock . . . . . . . . . . . . . .       7,125      6,834       6,985
   Company's equity in net income . . .       1,267      1,244       1,232
Total assets  . . . . . . . . . . . . .    $635,874   $610,024    $565,000
Less:
   Liabilities and long-term debt . . .     581,231    555,735     510,202
                                           --------   --------    --------
Net assets  . . . . . . . . . . . . . .    $ 54,643   $ 54,289      54,798
                                           ========   ========    ========
Company's equity in net assets  . . . .    $  9,759   $  9,701    $  9,768
                                           ========   ========    ========

C. COMMON STOCK EQUITY

     The Company maintains a Dividend Reinvestment and Stock Purchase 
Plan (DRIP) under which 300,504 shares were reserved and unissued at 
December 31, 1998.  The Company also funds an Employee Savings and 
Investment Plan (ESIP).  At December 31, 1998, there were 86,807 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 1998, 6,531 shares were 
returned to the Company resulting from the termination of employment of 
several participants.  At December 31, 1998, there were 26,614 shares 
reserved and unissued under the Compensation Program.

    On June 17, 1998, the Company adopted a Shareholder Rights Plan that 
authorized assignment of one share purchase right for each outstanding 
share of Common Stock, par value $3.33 1/3 per share, of the Company.  
The Rights were assigned on June 26, 1998 to the shareholders of record 
on that date. Each Right entitles the registered holder to purchase from 
the Company one Share at a price of $45.00 per Share, when the Rights 
become exercisable.     

     The Plan is designed to improve the Company's ability to represent 
the interests of shareholders in dealing with unilateral actions by 
hostile acquirors that are calculated to deprive the Company's Board and 
its shareholders of their ability to determine the destiny of the 
Company and to optimize shareholder value.

   Changes in common stock equity for the years ended December 31, 1996, 
1997 and 1998 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, 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      -$1.61 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

Common Stock Issuance:
  DRIP...................................     88,004         293         928                                           1,221
  ESIP...................................     36,391         121         427                                             548
  Compensation Program:
    Restricted Shares....................     (6,531)        (21)       (161)                                           (182)
Net Loss.................................                                         (2,877)                             (2,877)
Cash Dividends on Capital Stock:
  Common Stock      -$0.9625 per share...                                         (5,035)                             (5,035)
  Preferred Stock   -$4.75 per share.....                                            (12)                                (12)
                    -$7.00 per share.....                                            (32)                                (32)
                    -$9.375 per share....                                            (72)                                (72)
                    -$8.625 per share....                                           (302)                               (302)
                    -$7.32 per share.....                                           (879)                               (879)
                                         ------------------------------------------------------------------------------------
BALANCE, December 31, 1998...............  5,313,296     $17,711     $71,914     $17,508      15,856       ($378)   $106,755
                                         ====================================================================================

</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, $8.5 million of retained 
earnings were free of restrictions at December 31, 1998.

     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, 1998, $59,000 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 
1999, $1,640,000 for 2000, $235,000 for 2001-2002 and $75,000 for 2003.

     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 $0.916 per share until 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)
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
2003 . . . . . . . . . . .   1,700     8,000       9,700


     Non-Utility.  At December 31, 1998, Mountain Energy, Inc., the 
Company's subsidiary that invests in energy generation, energy 
efficiency and wastewater treatment projects, had unsecured long-term 
debt of $1,416,667.  The annual sinking fund requirements and maturities 
for the next two years are:
                            Sinking
                             Funds    Maturities    Total
                            -------   ----------    -----
                                    (In thousands)
1999 . . . . . . . . . . . . . $167     $  ---      $  167
2000 . . . . . . . . . . . . .   83       1,167      1,250


F. SHORT-TERM DEBT

     The Company has a revolving credit agreement in the amount of $45 
million with three banks, with borrowings outstanding of $7.0 million on 
December 31, 1998 and an uncommitted line of credit in the amount of 
$500,000, under which no amounts were outstanding at December 31, 1998.

     The revolving credit agreement requires the Company to certify on a 
quarterly basis that the Company has not suffered a "material adverse 
change."  Similarly, as a condition to further borrowings, the Company 
must certify that nothing has happened that has had or could reasonably 
be expected to have a materially adverse effect on the Company since the 
date that it last borrowed under this agreement. When the VPSB issued 
its Order dated February 27, 1998, disallowing certain costs associated 
with the Company's contract to purchase power from Hydro-Quebec, the 
three banks required modification of the terms of the revolving credit 
agreement, which had been made originally on August 12, 1997, which was 
unsecured and had a three-year term.  The modified agreement allows the 
Company to continue to borrow until such time that:
- 	A "material adverse effect" has occurred;
- 	The Company is no longer in compliance with all other provisions of 
   the agreement, in which case further borrowing will not be 
   permitted; or
- 	There has been a "material adverse change", in which case the banks 
   may declare the Company in default.

The modified terms also call in part for the following:

- 	A reduction in the term of the Agreement from three years to one, 
   expiring June 30, 1999;
- 	A second priority mortgage, lien and security interest in the 
   collateral pledged under our first mortgage bond indenture granted 
   to the banks; and
- 	An increase in the interest rates, facility fees and other fees 
   required to be paid by the Company under the agreement.

      Required regulatory approval was obtained on June 3, 1998. The 
restated credit agreement and related loan documents were effective on 
August 17, 1998.  

      There are a number of future events that, singularly or in 
combination, could lead the banks to refuse to allow further borrowings 
under the existing credit agreement, to seek to enter into a new credit 
agreement with the Company and/or to immediately call in all outstanding 
loans.  Some of those events are:

- 	The VPSB issues an order in the Company's pending 1998 rate case 
   that triggers a "material adverse change" for the Company; or
- 	Hydro-Quebec is unwilling to make new arrangements regarding the 
   cost of power that the Company purchases under its contract with 
   Hydro-Quebec. 

 
     The weighted average interest rate on borrowings outstanding at 
December 31, 1998 and December 31, 1997 was 6.2 percent and 7.0 percent, 
respectively.

     There was no non-utility short term debt outstanding at December 
31, 1998.


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, 1998 and 1997, the net regulatory assets were 
$2,214,000 and $1,704,000, respectively.

     The temporary differences which gave rise to the net deferred tax 
liability at December 31, 1998 and December 31, 1997, were as follows:

                                        At December 31, 	  At December 31,
                                       	   1998                  1997     
                                        ---------------    ---------------
                                                 (In thousands)
Deferred Tax Assets
Contributions in aid of construction . . .  $8,551                $ 7,946 
 Deferred compensation and
   post retirement benefits  . . . . . . .   4,455                  3,199
 Alternative minimum tax credit  . . . . .     (56)                    15
Self-insurance and other reserves  . . . .   2,009                     67 
Pine street reserve  . . . . . . . . . . .   2,469                  1,142
Other  . . . . . . . . . . . . . . . . . .     995                  2,003
                                            ------                 ------
                                            18,423                 14,372
                                            ------                 ------
Deferred Tax Liabilities
 Property-related and other  . . . . . . .  34,806                 31,864
 Demand side management costs  . . . . . .   3,557                  4,775
 Deferred purchased power costs  . . . . .   3,449                  1,234
                                            ------                 ------
                                            41,812                 37,873
                                            ------                 ------
Net accumulated deferred income tax
   liability . . . . . . . . . . . . . . .($23,389)              ($23,501)
                                          =========              =========

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,
                                              1998         1997      1996
                                              ----         ----      ----
                                                (In thousands)
Net change in deferred income tax 
  liability per above table  . . . . . . .  ($112)      ($3,225)   $1,434
Change in income tax related regulatory
  assets and liabilities   . . . . . . . .    510           509       504
Change in alternative minimum tax credit .    (70)          567       109
                                             -----      --------   -------
Deferred income tax expense for the 
Period . . . . . . . . . . . . . . . . . .   $328       ($2,149)   $2,047
                                             =====      ========   ======     

The components of the provision (benefit) for income taxes are as 
follows:
                                             Year Ended December 31,
                                           1998         1997       1996
                                           ----         ----       ----
                                               (In thousands)
Current federal income taxes  . . . . . ($1,047)      $7,355     $3,708
Current state income taxes  . . . . . .    (366)       2,267        990
                                        --------      ------      -----
Total current income taxes  . . . . . . ($1,413)       9,622      4,698 
                                        --------      ------      -----

Deferred federal income taxes . . . . .     219       (1,623)     1,588
Deferred state income taxes . . . . . .     109         (526)       459
                                        --------      -------     ------
Total deferred income taxes . . . . . .     328       (2,149)     2,047
                                        --------      -------     ------

Investment tax credits - net  . . . . .    (282)        (282)      (282)
                                        --------      -------    -------
Income taxes charged (credited) 
   to operations  . . . . . . . . . . . ($1,367)      $7,191     $6,463
                                        ========      ======     ======

     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,
                                          1998        1997       1996
                                          ----        ----       ----
                                           (Dollars in thousands)
Income (loss) before income tax . . .  ($4,244)    $16,630   $ 18,422
Federal statutory rate. . . . . . . .       34%      34.5%        34%
Computed "expected" federal
  income taxes  . . . . . . . . . . .  ($1,443)    $ 5,737    $ 6,263
Increase (decrease) in taxes
  resulting from:
  Tax versus book depreciation  . . .      153         349        327
  Dividends received and paid 
   Credit . . . . . . . . . . . . . .     (480)       (575)      (524)
  AFUDC - equity funds  . . . . . . .      (36)       (123)       (59)
  Amortization of ITC . . . . . . . .     (282)       (282)      (282)
  State tax benefit (provision) . . .       87        (601)      (493)
  Excess deferred taxes . . . . . . .      (60)        (60)       (60)
  Taxes attributable to subsidiaries       845         682       (140)
  Tax reserve . . . . . . . . . . . .       45         270       (101)
  Other . . . . . . . . . . . . . . .       61          53         83
                                       --------     -------    -------
Total federal income taxes  . . . . .  ($1,110)     $5,450     $5,014
                                       ========     =======    =======
Effective federal income tax rate . .     26.1%       32.8%      27.2%

     The decrease in 1998 is primarily due to taxes attributable to the 
subsidiaries.  The increase in 1997 is due to taxes attributable to the 
subsidiaries in 1996 as well as an increase in the tax reserve for 1996.

     Non-Utility.  The Company's non-utility subsidiaries had 
accumulated deferred income taxes of $4.6 million on their balance 
sheets at December 31, 1998, largely attributable to property-related 
transactions.



     The components of the provision (benefit) for income taxes for the 
non-utility operations are:
                                         Year Ended December 31,
                                       1998        1997       1996
                                       ----        ----       ----
                                             (In thousands)
State income taxes . . . . . . . . .  ($503)        $78       $154
Federal income taxes . . . . . . . . (1,332)     (1,071)       207
Investment tax credits . . . . . . .   (111)        (45)       (45)
                                    --------    --------      -----
Income tax (benefit)/provision 
   charged (credited) to operations $(1,946)    ($1,038)      $316
                                    ========    ========      =====


     The effective federal income tax rates for the non-utility 
operations were 32.6 percent, 37.0 percent, and 22.4 percent for the 
years ended December 31, 1998, 1997 and 1996, respectively.  

      The decrease in 1998 is primarily due to a relatively large state 
tax benefit in 1998. The increase in 1997 is primarily due to a 
relatively large federal tax benefit in 1997.

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.

                                            1998 Quarter Ended
                                 March     June      Sept.     Dec.     Total
                                 -----     ----      -----     ----     -----
                                     (Dollars in thousands, except per share)
Operating Revenues . . . . . . .$46,932  $43,733   $47,984  $45,655  $184,304
Operating Income . . . . . . . .    316    2,811     3,147     (802)    5,472
Net Income . . . . . . . . . . . (3,065)   1,271     1,943   (3,026)   (2,877)
Net Income Applicable to
  Common Stock . . . . . . . . . (3,405)     931     1,633   (3,332)   (4,173)
Earnings per Average Share of
  Common Stock . . . . . . . . . ($0.66)   $0.18     $0.31   ($0.63)   ($0.80)
Weighted Average Number of
  Common Shares Outstanding  . .  5,196    5,222     5,261    5,291     5,243

                                            1997 Quarter Ended
                                 March     June      Sept.     Dec.     Total
                                 -----     ----      -----     ----     -----  
                                   (Dollars 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 
  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


I. 	COMMITMENTS AND CONTINGENCIES



       1.  Industry Restructuring.  The electric utility business is 
experiencing rapid and substantial changes.  These changes are the 
result of the following trends:

- 	Surplus generating capacity;
- 	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, 
   also known as "restructuring".

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


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


Pine Street Barge Canal Site 

     The Federal Comprehensive Environmental Response, Compensation, and 
Liability Act (CERCLA), commonly known as the "Superfund" law, generally 
imposes strict, joint and several liability, regardless of fault, for 
remediation of property contaminated with hazardous substances.  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.  
In 1994, the EPA 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.

     In June 1998, the Coordinating Council reached a consensus 
agreement on a recommended plan for remediation of the Pine Street Barge 
Canal site.  As part of the Council's process of reaching a consensus 
recommendation, the Company and certain other parties conditionally 
agreed to fund environmentally beneficial projects in the greater 
Burlington area, the cost of which may reach $3 million.  In June 1998, 
the EPA formally proposed the Council's recommended plan and received 
public comments.

     On September 29, 1998, the EPA issued its final Record of Decision, 
announcing selection of the proposed remedy.  The proposed remedy 
includes:
- 	Construction of an underwater cover over canal sediments that 
   present the highest risk to the environment;
- 	Placement of a soil cap over certain contaminated wetland areas and 
   restoration of those areas;
- 	Improvements that will better distribute storm water entering the 
   site; and
- 	Monitoring of the site to ensure that the cap is effective over the 
   long term and that harmful contamination does not migrate offsite.

The EPA estimates that the present value cost of the remedy will be $4.4 
million, although actual costs may be higher.

As of December 31, 1998, the Company's total expenditures related 
to the Pine Street Barge Canal site since 1982 were approximately $16 
million.  This includes those amounts not recovered in rates, amounts 
recovered in rates, and amounts for which rate recovery has been sought 
but which are presently awaiting further VPSB action.  The bulk of these 
expenditures consisted of transaction costs.  Transaction costs include 
legal and consulting costs associated with the Company's opposition to 
the EPA's earlier proposals for the site, as well as litigation and 
related costs necessary to obtain settlements with insurers and other 
PRPs to provide amounts required to fund the clean up (remediation 
costs) and to address liability claims at the site.  A smaller amount of 
past expenditures was for site-related response costs, including costs 
incurred pursuant to the EPA and state orders that resulted in funding 
response activities at the site, and to reimbursing the EPA and the 
State for oversight and related response costs.  The EPA and the State 
have asserted and affirmed that all costs related to these orders are 
appropriate costs of response under CERCLA for which the Company and 
other PRPs were legally responsible.

      The EPA has made claims against the Company for additional past 
costs associated with the Pine Street Barge Canal site in an amount 
exceeding $11 million.  The EPA also has advised the Company that the 
Company may be responsible for implementation of further response 
activities at the site.  In early 1998, the United States and the State 
asked the Company to begin "fast-track" negotiation of tentative terms 
of settlement of all cost reimbursement and natural resource damages 
claims of the United States and the State.  Those negotiations began 
immediately, and included discussion of the Company's potential 
contribution claims against the United States.  In May 1998, a 
confidential tentative agreement was reached on issues under discussion.

     The Company expects to complete negotiation soon of a final 
settlement with the United States and the State over terms of a Consent 
Decree that will cover claims addressed in the earlier negotiations and 
implementation of the selected remedy.  The Consent Decree must be 
submitted to a federal court for approval and adoption as its order.  
The Company has entered into various confidential settlement agreements 
with other PRPs that provide for sharing of past response costs, future 
cleanup costs and related future federal and state monetary claims.  

     The Company estimates that  it has recovered or secured, or will 
recover, through past settlements of litigation claims against insurers 
and other parties, amounts that exceed estimated future remediation 
costs, future federal and state government oversight costs and past EPA 
response costs. The Company has concluded that its unrecovered 
transaction costs mentioned above, which were necessary to recover 
settlements sufficient to remediate the site, to oppose much more costly 
solutions proposed by the EPA, to resolve monetary claims of the EPA and 
the State and to remediate the site, are likely to be in the range of $5 
to $9 million.  In 1998, the Company recorded a liability of $5 million 
to recognize the low end of this range of costs.  The estimated 
liability is not discounted, and it is possible that the Company's 
estimate of future costs could change by a material amount.  The Company 
also has recorded an offsetting regulatory asset and the Company 
believes it is probable that  it will receive future revenues to recover 
these costs.  

     Through rate cases filed in 1991, 1993, 1994, and 1995, the Company 
sought and received recovery for ongoing expenses associated with the 
Pine Street Barge Canal site.  Specifically, the Company proposed rate 
recognition of its non-recovered 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 
full rate recovery of the  Pine Street Barge Canal costs, the 
Department, and as applicable, other intervenors, reached agreements 
with the Company in these cases that the full amount of the Pine Street 
Barge Canal costs reflected in those rate cases should be recovered in 
rates.  The Company's rates, as approved by the VPSB in those 
proceedings, reflected the Pine Street Barge Canal related expenditures 
referred to above.

     The Company proposed in its rate filing made on June 16, 1997, 
recovery of an additional $3.0 million in such expenditures. In an order 
in that case released March 2, 1998, the VPSB suspended the amortization 
of expenditures associated with the Pine Street Barge Canal site pending 
further proceedings.  Although it did not eliminate the rate base 
deferral of these expenditures, or make any specific order in this 
regard, the VPSB indicated that it was inclined to agree with other 
parties in the case that the ultimate costs associated with the Pine 
Street Barge Canal site, taking into account recoveries from insurance 
carriers and other PRPs, should be "shared" between customers and 
shareholders of the Company.  In response to the Company's Motion for 
Reconsideration, the VPSB on June 8, 1998 stated "our intent, and we 
believe the fair reading of our Order, was to reserve for a future 
docket issues pertaining to the sharing of remediation-related costs 
between the Company and its customers." 

     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 its financial position or results of 
operations in 1998.


     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 the Company's power supply purchase contracts, 
which expired in early 1998, related to a generating plant that was 
affected by Phase I of the acid rain provisions of this legislation, 
which went into effect January 1, 1995.  

     3. Operating Leases. The Company has an operating lease for its 
corporate headquarters building and two of its service center buildings. 
See Item 6 below.

     4. Jointly-Owned Facilities.  The Company had joint-ownership 
interests in electric generating and transmission facilities at December 
31, 1998, as follows:

                       Ownership  Share of    Utility  Accumulated
                        Interest  Capacity     Plant  Depreciation
                       ---------  --------    ------- ------------
                         (In %)    (In MW)        (In thousands)
Highgate  . . . . . .    33.8       67.6       $10,532     $3,573
McNeil  . . . . . . .    11.0        5.9       $ 8,729     $3,898
Stony Brook (No. 1) .     8.8       31.0       $10,331     $6,752
Wyman(No.4) . . . . .     1.1        6.8       $ 2,370     $1,448
Metallic Neutral 
   Return (1). . .. .    59.4        ---       $ 1,563     $  494
(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. 1997 Retail Rate Case -- 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 to increase the target return 
on common equity from 11.25 percent to 13 percent.  In its final 
submissions to the VPSB, the Company asked for an increase of 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 its Order dated February 27, 1998, in the then pending 
rate case.  The VPSB authorized the Company to increase its rates by 
3.61 percent, which gave it increased annual revenues of $5.6 million. 
     The difference between the $22 million we asked for and the $5.6 
million the VPSB authorized was due to the following:
- 	Disallowance of the cost of power associated with the Hydro-Quebec 
   contract discussed below;
- 	The VPSB's modification of our calculation of rate base;
- 	The exclusion of future capital projects from rate base;
- 	Suspension of recovery of Pine Street Barge Canal site 
   expenditures;
- 	Various cost of service reductions in payroll and operations and 
   maintenance; and 
-  A reduction in our requested allowed return on equity from 13 
   percent to 11.25 percent.  

     The VPSB Order denied us the right to charge customers  $5.48 
million of the annual costs for power purchased under our contract with 
Hydro-Quebec.  The VPSB denied recovery of these costs for the following 
reasons:
- 	The VPSB claimed that we had acted imprudently by committing to the 
   power contract with Hydro-Quebec in August 1991 (the imprudence 
   disallowance); and 
- 	To the extent that the costs of power to be purchased from Hydro-
   Quebec are now higher than current estimates of market prices for 
   power during the contract term, after accounting for the imprudence 
   disallowance, the contract power is  not "used and useful".

Generally accepted accounting principles (GAAP) required that we 
record in the first quarter of 1998 the losses resulting from the 
disallowed recovery of a portion of the 1998 Hydro-Quebec power contract 
costs.  The amount charged to first quarter income of $4.6 million (pre-
tax) was less than the full disallowance because we expected that new 
rates would become effective in January 1999 as the result of our May 8, 
1998 rate filing.  The agreement to suspend our 1998 rate case, as 
described below, delays the date of a final decision on the 1998 rate 
case to December 15, 1999, and we recognized an additional loss of $5.25 
million in the last quarter of 1998 representing the effect of the 
presumed continued disallowance of Hydro-Quebec power costs through 
December 15, 1999.  

     In its February 27, 1998 Order, the VPSB described its policies 
that do not allow a utility to recover imprudent expenditures and the 
costs of power supply contract purchases that the VPSB decides are not 
used and useful.  The VPSB also stated in its Order that the methods and 
measures used in this rate case were provisional and applied to this 
rate case only.  If the VPSB were to apply the same, or similar, methods 
and measures that they used in the 1997 rate case Order to future power 
contract costs in our 1998 retail rate case, we would likely be required 
to take a charge to income of approximately $170 million pre-tax.   This 
$170 million estimate represents primarily the 20 percent disallowance 
for Hydro-Quebec power costs that the VPSB considered imprudent in its 
Order. We will not be able to estimate the loss to be recorded for power 
purchased after December 15, 1999, if any, until the pending 1998 rate 
case is completed.

If the VPSB does not modify in future regulatory proceedings its 
ruling that the costs of power purchased from Hydro-Quebec are above 
estimated market rates and are not used and useful and, therefore, a 
portion of such costs is not recoverable, we would likely conclude that 
the VPSB has changed its approach to setting rates from cost-based rate 
making to another form of regulation.  We would then be required to 
discontinue application of Statement of Financial Accounting Standards 
No. 71(SFAS 71), Accounting for the Effects of Certain Types of 
Regulation, described below, and eliminate all regulatory assets and 
liabilities that arose from prior actions of the VPSB.  The write-off of 
these regulatory assets and liabilities, net of any tax effects, would 
be charged to income as an extraordinary item for the financial 
reporting period in which the discontinuation of SFAS 71 occurs. 

     SFAS 71 provides guidance in preparing financial statements for 
public utilities that meet certain criteria of SFAS 71.  The three 
criteria that we must meet in order to follow the accounting guidance 
under SFAS 71 are:
- 	Our rates for regulated services and products provided to our 
   customers must be established by or be subject to approval by an 
   independent, third-party regulator;
- 	The regulated rates are designed to recover our specific costs of 
   providing the regulated services or products; and
- 	Depending on demand for regulated services and products, and the 
   level of competition, direct and indirect, it is reasonable to 
   assume that our rates are set at levels that will recover our costs 
   and that these rates can be charged to and collected from our 
   customers.  This criterion must also take into account anticipated 
   changes in levels of demand or competition during the recovery 
   period for any capitalized costs.

     We meet these criteria at present and, therefore the provisions of 
SFAS 71 apply to us.  Under SFAS 71 we are required to defer certain 
costs that would typically be expensed under GAAP; these costs are 
referred to as deferred charges or regulatory assets.

Our ability to defer a cost is subject to our ability to provide 
evidence that the following additional criteria are met:
- 	It is probable that the inclusion of the capitalized (deferred) 
   cost in allowed costs for ratemaking purposes will provide future 
   revenue in an amount at least equal to the capitalized (deferred) 
   cost; and
- 	The future revenue will be provided to permit recovery of the 
   previously incurred cost rather than to provide for expected levels 
   of similar future costs. 

     Based on the December 31, 1998 balance sheet, if we were required 
to discontinue the application of SFAS 71,  we would be required to take 
an after-tax charge to earnings of approximately $24.6 million 
attributable to net regulatory assets.  

     On March 20, 1998, we filed with the VPSB a Motion for 
Reconsideration of and to Alter or Amend the VPSB's Order released on 
March 2, 1998.  The principal areas in which we requested that the VPSB 
change its ruling included the following:
- 	A correction to the VPSB's calculation of the $5.48 million Hydro-
   Quebec contract power cost disallowance;
- 	Reversal of the accounting treatment specified by the VPSB for cash 
   payments made by Hydro-Quebec under arrangements that we had 
   previously negotiated in order to avoid rate increases in prior 
   years for customers;
- 	Restoration of $418,000  of costs associated with the construction 
   of the Searsburg wind generation facility;
- 	Restoration of various other compensation and payroll costs;
- 	Reversal of the suspension of amortization of costs associated with 
   the Pine Street Barge Canal site; and
- 	Reconsideration of our request to increase the allowed rate of 
   return from 11.25 percent to 12 percent.

     Immediately following the issuance of the June 8, 1998 VPSB Order 
on our Motion for Reconsideration, which largely reaffirmed the earlier 
Order, Duff & Phelps and Standard & Poor's lowered our securities credit 
ratings.  Moody's also subsequently lowered our securities credit 
ratings. 

     In June 1998, we appealed the VPSB's February 27, 1998 Order and 
the June 8, 1998 Reconsideration Order to the Vermont Supreme Court.  
The briefing of the case by all parties was completed in January 1999.  
A hearing before the Vermont Supreme Court is scheduled for March 16, 
1999.   A number of other Vermont utilities have submitted briefs in 
support of the Company.

     The Company believes that the decisions in the VPSB's February 27, 
1998 Order and June 8, 1998 Reconsideration Order are factually 
inaccurate and legally incorrect.  Specifically, the Company is 
appealing the VPSB's determination that it was imprudent in committing 
to the Hydro-Quebec contract in August, 1991, and the VPSB's ruling that 
because the contract power is priced over-market under current forecasts 
of market prices, it is therefore considered "not used and useful".  The 
Company asserts, among other arguments, that the VPSB's Order deprives 
the Company's shareholders of their property in an unconstitutional 
manner.  The VPSB's decision, if not changed, could have a significant 
negative impact on the Company's reported financial condition, and could 
impact its credit ratings, dividend policy and financial viability.

1998 Retail Rate Case -- On May 8, 1998, the Company filed a request 
with the VPSB to increase its retail rates by 12.93 percent due to the 
following increases in its cost of service:
- 	The higher cost of power; 
- 	The cost of the January 1998 ice storm; and
- 	Investments in new plant and equipment.  

 The VPSB suspended the tariff filings on June 15, 1998.  The 
Company submitted testimony in the case that included analysis of viable 
alternatives to the Hydro-Quebec contract at various times in 1991 and 
1992.  The VPSB had taken the viewpoint in the Company's 1997 rate case 
that the Company would have been able to terminate the Hydro-Quebec 
contract without penalty during that time period, and would have been 
able to access the market for power at that time.  The Company's 
analysis showed that, based on price only, the Hydro-Quebec contract was 
less expensive than virtually all other long term power resources 
available at that time.  The analysis also showed that when other non-
price benefits, like environmental benefits and the reliability of a 
system power resource, are taken into account, the Hydro-Quebec contract 
was still less costly than alternatives.  The Company has testified that 
even today, when costs and benefits for society are accounted for, as 
Vermont regulators and statutes require, the Hydro-Quebec power is not 
more costly than market power.

     In testimony submitted on September 21, 1998, the Department argued 
for the following:
- 	A $22 million disallowance of Hydro-Quebec contract costs; 
- 	A rate decrease of 3.6 percent; 
- 	The elimination of the Company's common stock dividend; and
- 	Various other restrictions.

     Additionally, the Department's recommendation was that 
approximately $12.5 million of the disallowance of Hydro-Quebec contract 
costs be suspended for one year, which would provide the Company with a 
4.5 percent rate increase only for that year, followed by automatic 
reinstatement of the larger power cost disallowance with a resulting 
decrease (in 2000) from its rate levels today, absent further VPSB 
order.   The Department recommended this one year delay in the Hydro-
Quebec contract cost disallowance in order to allow the Company time to 
negotiate lower costs of power under the Hydro-Quebec contract.

     IBM, the Company's largest customer, argued for a rate decrease of 
0.2 percent, a disallowance of Hydro-Quebec power costs in the amount of 
$13 million, and the elimination of the common stock dividend.

     In its rebuttal case, the Company intended to present the VPSB with 
testimony that:

- 	The Department's and IBM's recommendations amount to improper rate 
   making that will have adverse economic and accounting impacts under 
   applicable accounting rules;
- 	The only cogent evidence of alternative portfolios of power 
   resources available in 1991 presented to the VPSB is from the 
   Company's witnesses and the only conclusion that can be drawn from 
   that evidence justifies a determination that there should be no 
   Hydro-Quebec power contract cost disallowance; and
- 	The Company requires substantial rate relief in order to ensure its 
   financial stability, access to capital markets and the continuation 
   of adequate, reliable and safe service to its customers.  

     The Company also intended to present to the VPSB considerable 
evidence that:
- 	It  has made, and continues to make, efforts to achieve a 
   negotiated reformulation of the arrangement with Hydro-Quebec;
- 	Placing it at risk of bankruptcy will not improve the Company's 
   prospects of achieving success in such a negotiation;
- 	Bankruptcy reorganization is not an appropriate public policy 
   solution to high power cost obligations; and  
- 	Its default of obligations to Hydro-Quebec and other creditors 
   would cause substantial risks of default in the same contractual 
   relationships by many other Vermont utilities under "step-up" or 
   similar provisions contained in such arrangements.

     On November 18, 1998, by Memorandum of Understanding (MOU), the 
Company, the Department and IBM agreed to stay, effective November 16, 
1998, rate proceedings in the 1998 rate case until or after September 1, 
1999, or such earlier date as the parties may later agree to or the VPSB 
may order.  The MOU provides for a 5.7 percent temporary retail rate 
increase, to produce $9.19 million in annualized additional revenue, 
effective with service rendered December 15, 1998.  An additional 
surcharge in 1999 will be permitted, without further VPSB order, to 
produce additional revenues necessary to provide the Company with the 
capacity to finance estimated 1999 Pine Street Barge Canal site 
expenditures of $5.8 million.  

     The stay and suspension of this pending rate case and the temporary 
rate levels agreed to in the MOU are designed to allow the Company to 
continue to provide adequate and efficient service to its customers 
while it seeks mitigation of power supply costs.

     Following the stay, which expires on September 1, 1999 or such 
earlier date as agreed to by the parties or ordered by the VPSB, the 
remaining proceedings in the case would commence and, as noted above, a 
final VPSB decision would be issued by December 15, 1999.  In the event 
that the VPSB issues a final order that allows a retail rate increase 
that is less than the temporary rates, all sums collected in excess of 
such final rates would be refunded by adjusting rates on a prospective 
basis, by customer class, to reflect the appropriate refund amounts.

      The MOU does not provide for any specific disallowance of power 
costs under the Company's purchase power contract with Hydro-Quebec.  
Issues respecting recovery of such power costs are preserved for future 
proceedings.

     The Company agreed not to file with the VPSB a petition requesting 
any further increase in retail electric rates prior to September 1, 
1999, except that this MOU does not preclude it from filing a request 
for additional temporary rate increases pursuant to 30 V.S.A. Section
226(a).

     The temporary rates include $1 million that is to be used for 
enhanced right-of-way maintenance and pole testing and treatment.  

     Regulatory asset account balances of $5.3 million, which are 
subject to recovery in this docket, are to be amortized over seven 
years, beginning January 1999.  These balances reflect only the amount 
filed in the May 1998 rate case, and are related to regulatory 
commission expense, tree trimming, storm damage and the costs associated 
with the ice storm of 1998.  This amortization period will be subject to 
review by the VPSB after the expiration of the stay.  

     In the event that the Vermont Supreme Court issues an order 
reversing the VPSB's orders in the Company's 1997 rate case prior to 
issuance of a final order in the 1998 rate case, any resulting 
adjustments in rates will not become effective until the VPSB issues a 
final order in the 1998 rate case.  The MOU provides that nothing in it 
will reduce or limit the Company's entitlement to full recovery of any 
amounts due it if it should prevail on the appeal.  

     The MOU was approved by the VPSB on December 11, 1998.  The 
temporary rates, as adjusted by any surcharge related to the Pine Street 
Barge Canal site described above, will remain in effect until the VPSB 
issues a final order in the rate case docket, expected by December 15, 
1999.
	
     Notwithstanding the interim rate settlement, the Company is unable 
to predict whether the MOU or other future events, singularly or in 
combination, could cause its lending banks to refuse to allow further 
borrowings under its revolving loan agreement, to seek to enter into a 
new credit agreement with the Company and/or to immediately call in all 
outstanding loans.  If the Company is unable to borrow on a short-term 
basis, it will evaluate all potential alternatives available at the 
time, including, but not limited to, the filing of a petition for 
reorganization under the United States Bankruptcy Code.

     6. Corporate Headquarters Lease - As part of the Company's efforts 
to reduce operating costs, it evaluated options to its corporate 
headquarters lease, which runs through June 2009. The Company is in the 
process of negotiating the termination of its operating lease for its 
corporate headquarters and two of its service centers.  

     It is probable that the Company will purchase the lease and sell 
the corporate headquarters in 1999.  The Company has recorded a loss of 
approximately $1.9 million  (pre-tax) in 1998 to reflect the probable 
loss of completing these transactions.  The Company would retain 
ownership of its two service centers. 


    7. Deferred Charges Not Included in Rate Base.  The Company has 
incurred and deferred approximately $7.3 million in costs for tree 
trimming, storm damage and regulatory commission work of which $5.3 
million will be amortized over seven years beginning in January 1999.  
Currently, the Company also amortizes costs based on historical averages 
and does not receive a return on amounts deferred in excess of 
historical averages.  Management expects to seek and receive ratemaking 
treatment for deferred costs in future filings.


     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, 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, 1998, the 
present value of the Company's obligation was $7.7 million.

Projected future minimum payments under the Phase II support agreements 
are as follows:
                     Year ending December 31,
               1999 . . . . . . . . . . . . $ 452,726
               2000 . . . . . . . . . . . .   452,726
               2001   . . . . . . . . . . .   452,726
               2002   . . . . . . . . . . .   452,726
               2003   . . . . . . . . . . .   452,726
               Total for 2004-2020  . . . . 5,432,706
                                           ----------
                                           $7,696,336
                                           ==========

     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 at December 
31, 1998 follows:

                                         Stony           Vermont
                                         Brook           Yankee
                                         -----           -------
                                          (Dollars in thousands)
Plant capacity . . . . . . . . . . . . .352.0 MW         531.0 MW
Company's share of output  . . . . . . .  4.4%              17.7%
Contract period  . . . . . . . . . . . .   (1)                (2)
Company's annual share of:
  Interest . . . . . . . . . . . . . .  $ 207             $ 2,040
  Other debt service . . . . . . . . .    333                 ---
  Other capacity . . . . . . . . . . .    221              29,637
                                        ------            -------
Total annual capacity  . . . . . . . .  $ 761             $31,677
                                        ======            =======
Company's share of long-term
Debt . . . . . . . . . . . . . . . . . $3,931             $16,696
                                       ======             =======

(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 20 years that 
began 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 6.5 to 5.8 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  . . . . . . . . . .  $9,271          $6,825
                                            (1998)          (1998)

                                          $15,151          10,451
                                       (1999-2015)*    (1999-2015)*

Annual Capacity Charge  . . . . . . . . . $17,303          $3,394
                                           (1998)          (1998)

                                          $17,074         $11,593
                                       (1999-2015)*    (1999-2015)*

Average Cost per KWH  . . . . . . . . . .   7.6 cents**    4.0 cents
                                            (1998)***      (1998)***

                                            7.0 cents      6.9 cents
                                       (1999-2015)****(1999-2015)****
    *Estimated average.
   **Higher per kwh rate for Schedule B in 1998, as compared to future 
years, is due to the 1998 ice storm. Schedule B was delivered at a 
capacity factor of 63%; future years are estimated to be at 75% 
capacity factor.
 ***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 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 reduced purchase power expense ratably over the period 
beginning June 1997 and ending May 1998.  The Company received VPSB 
approval of this accounting treatment in an Accounting Order dated 
December 31, 1996.

     Under the 1996 arrangement, the Company is required 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.  During 1998, the 
Company purchased or sold to others 44.2 percent of the minimum purchase 
obligation for that year.  The Company recorded a liability of $0.3 
million for its remaining 1998 minimum purchase obligation.

     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 provided Hydro-Quebec an option 
for the purchase of power.  Commencing April 1, 1998 and effective 
through the 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.  
Hydro-Quebec's option to curtail energy deliveries pursuant to the July 
1994 Agreement can be exercised in addition to this purchase option.  
Over the same period, 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. In 
1998, Hydro-Quebec called on the Company to deliver 51,968 MWh to a 
third party at a net cost to the Company of $232,958 which was due to 
higher energy replacement costs.  


L. 	SUBSEQUENT EVENTS

     1.  Power Purchase and Supply Agreement -- On February 11, 1999, 
the Company entered into a contract with Morgan Stanley Capital Group, 
Inc. (MS) as a result of the Company's power requirements solicitation 
in 1998.  A master power purchase and sales agreement (PPSA) dated 
February 11, 1999 defines the general contract terms under which the 
parties may transact.  The sales under the PPSA commenced on February 
12, 1999, and will terminate after all obligations under each 
transaction entered into by MS and the Company have been fulfilled, 
currently anticipated to be  June 30, 2001.  The PPSA has been noticed 
to the VPSB and filed with the FERC.

     The parties have also agreed to enter into two transactions subject 
to the PPSA.
- 	Sale by the Company to MS. -- On a daily basis, and at MS's 
   discretion, the Company will sell power from all or part of its 
   portfolio of power resources to MS at predefined operating and 
   pricing parameters.  The Company can decide to sell power to MS 
   from any  power resource available to it, provided the sales of 
   power are consistent with the predefined operating and pricing 
   parameters.   The Company retains all rights and obligations 
   related to its power resources, such as dispatch, plant 
   modifications and transfer of ownership.  This transaction does not 
   constitute a sale or lease of any Company resource.
- 	Sale by MS to the Company. - MS will sell to the Company, at a 
   predefined price, power sufficient to serve pre-established load 
   requirements.  MS has the right but not the obligation, upon a 
   request from the Company, to supply additional power at prices 
   negotiated by both parties.  The power sold to the Company may be, 
   but is not required to be, power that MS has purchased from the 
   Company under the transaction described above.

     The parties have agreed to the protocols that will be used to 
schedule power sales and purchases between the parties and to secure 
necessary transmission with respect to the two transactions described 
above.

     The PPSA provides the Company with a means of managing price risks 
associated with changing fossil fuel prices.  The Company remains 
responsibile for balancing supply resources when actual loads vary from 
the pre-established load requirements that MS is obligated to satisfy 
and for resource performance and availability.
     
  
     2.  Green Mountain Resources, Inc. (GMRI) was formed in April 1996 
to explore opportunities in the emerging competitive retail energy 
market.  In 1998, GMRI lost $0.2 million compared to a loss of $2.0 
million in 1997.  GMRI's loss in 1997 was primarily due to development 
costs associated with its investment in Green Mountain Energy Resources 
L.L.C. (GMER).

     On August 6, 1997, GMRI entered into an agreement with Green 
Funding I, L.L.C. (GFI), whereby GMRI and GFI would jointly own GMER, a 
Delaware limited liability company of which GMRI was previously the sole 
owner.  GMER is a company that has created retail brands of electricity 
that are sold to consumers in competitive markets.  GMRI received a 
payment of $4 million from GMER at the closing in 1997 as reimbursement 
for certain development expenses GMRI had incurred.  

     Under the terms of the original agreement through which GFI 
acquired its interest in GMER, GMRI's ownership percentage of GMER would 
be diluted if GFI and/or third parties proposed to contribute additional 
capital to GMER, and GMRI did not make pro rata additional capital 
contributions at such time.  During 1998, GFI made substantial, 
additional investments in GMER and it was anticipated that GFI or other 
parties would make substantial, additional investments in 1999.  GMRI 
elected not to provide additional capital contributions, which reduced 
its ownership percentage in GMER.  In view of the likely need for future 
investment in GMER's business, the Company considered it to be in the 
best interest of its shareholders to sell GMRI's remaining interest in 
GMER.

     In December 1998, GMRI and GFI replaced the 1997 agreement with a 
new agreement, which among other things, provided for the sale of GMRI's 
remaining interest in GMER in return for $1 million to be paid and 
recorded as income in the first quarter of 1999.  The funds were 
received and will be used for the Company's general operating expenses.

     The new agreement provides the Company substantial relief from a 
"non-compete clause" in the 1997 agreement that would have restricted 
its activities in the retail energy business for seven years. 


     3.  Vermont Yankee.  On February 25, 1999, the Board of Directors 
of Vermont Yankee Nuclear Power Corporation granted an exclusive right 
to AmerGen Energy Company to conduct due diligence and negotiate a 
possible agreement to purchase the assets of Vermont Yankee.  Due 
diligence will occur over a 120-day period.

     AmerGen was formed in 1997 as a joint venture by PECO Energy of 
Philadelphia, Pennsylvania and British Energy of Edinburgh, United 
Kingdom to purchase and operate nuclear plants in the United States.

     Regulatory approval by the Nuclear Regulatory Commission, the 
Securities and Exchange Commission and the VPSB and others will be 
needed prior to completion of any final sale transaction.



                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, 19987 and 1997, and the related 
consolidated statements of income and cash flows for each of the three 
years in the period ended December 31, 1998.  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.5, the Company has appealed the Vermont Public 
Service Board's February 27, 1998 rate order to the Vermont Supreme 
Court. In addition, the Company is involved in a rate proceeding 
initiated in 1998 that is anticipated to reach final decision by 
December 15, 1999.  The outcomes of the appeal process and the rate 
proceeding could have a significant adverse impact on the Company's 
reported financial condition and 1999 results of operations and 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, 1998 and 1997, and 
the consolidated results of its operations and its cash flows for each 
of the three years in the period ended December 31, 1998, in conformity 
with generally accepted accounting principles.


/s/ ARTHUR ANDERSEN LLP



Boston, Massachusetts
February 5, 1999
(except with respect to the matters discussed
in Note L as to which the date is February 26, 1999)

<TABLE>
<CAPTION>

Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1998, 1997 and 1996

                                                                  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
  1998.................................    $663,785        $2,735,000       $5,000,000        $500,000      $7,898,785
  1997.................................    $237,892          $427,546      $   --               $1,653        $663,785
  1996.................................    $103,301          $572,000      $   --             $437,409        $237,892


Bad Debt Reserve (2)
  1998.................................    $493,405          $393,949          $83,299 (1)    $575,653        $395,000
  1997.................................    $498,024          $637,010         $173,899 (1)    $815,528        $493,405
  1996.................................    $417,684          $677,272          $72,344 (1)    $669,276        $498,024

(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, Meetings, 
Committees and Other Relationships" "Section 16(a) Beneficial Ownership 
Reporting Compliance," "Executive Compensation and Other Information," 
"Compensation Committee Report on Executive Compensation," "Performance 
Graph," "Pension Plan Information and Other Benefits" 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 20, 1999.  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 1999.


                                    PART IV

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

                                                                   Filed
                                                                 Herewith
                                                                 On Page 

     Item 14(a)(1).  The financial statements and financial          47       
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     Form 10-K 1997
              The Bank of Nova Scotia, State Street Bank and                    (1-8291)
              Trust Company, Fleet National Bank, and Fleet
              National Bank, as Agent

4-b-18     Amendment to Exhibit 4-b-18                               4-b-18a    Form 10-Q Sept. 1998
  (a)                                                                           (1-8291)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

10-b-41    VETCO Capital Funds Support Agreement dated as            10-b-41        33-8164
             of July 15, 1982, between VELCO and participating
             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 Rochester Gas 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.

*10-b-85   Power Purchase and Sale Agreement between                 10-b-85
             Morgan Stanley Capital Group Inc. and the 
             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-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-8     Green Mountain Power Corporation Officers'                10-d-8      Form 10-K 1990
             Supplemental Retirement Plan.                                       (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-21   Severance Agreement with N. R. Brock                      10-d-21

*10-d-22   Severance Agreement with C. L. Dutton                     10-d-22

*10-d-23   Severance Agreement with R. J. Griffin                    10-d-23

*10-d-24   Severance Agreement with J. J. Lampron                    10-d-24

*10-d-25   Severance Agreement with M. H. Lipson                     10-d-25

*10-d-26   Severance Agreement with C. T. Myotte                     10-d-26

*10-d-27   Severance Agreement with W. S. Oakes                      10-d-27

*10-d-28   Severance Agreement with M. G. Powell                     10-d-28

*10-d-29   Severance Agreement with S. C. Terry                      10-d-29

*10-d-30   Severance Agreement with J. H. Winer                      10-d-30

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 January 8, 1999, 
setting forth the conclusions of a report issued December 18, 1998 by 
the Working Group on Vermont's Electricity Future, and the financial 
implications of the sale by the Company's wholly owned subsidiary, Green 
Mountain Resources Inc., of its remaining interest in Green Mountain 
Energy.


                              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 25, 1999

     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 25, 1999
     Christopher L. Dutton    (Principal Executive Officer)

 /s/ Nancy R. Brock           Vice President, Treasurer and       March 25, 1999
     Nancy R. Brock           Chief Financial Officer (Principal 
                              Financial Officer)

 /s/ Robert J. Griffin        Controller                          March 25, 1999
     Robert J. Griffin        (Principal Accounting Officer)

     *Thomas P. Salmon        Chairman of the Board 

     *Nordahl L. Brue         )

    *William H. Bruett        )

  *Lorraine E. Chickering     )

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

    *Martin L. Johnson        )

      *Ruth W. Page           )

*By: /s/ Christopher L. Dutton_                                  March 25, 1999
     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 5, 1999.  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 47 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
March 25, 1999               /s/  Arthur Andersen LLP