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 FISCAL YEAR ENDED DECEMBER 31, 1999

                         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)

    163  ACORN  LANE
    COLCHESTER,  VT                                           05446
(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 21, 2000, WAS APPROXIMATELY $44,492,259 BASED ON THE
CLOSING  PRICE OF $8.1875 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 21, 2000, WAS
5,434,169.
                       DOCUMENTS INCORPORATED BY REFERENCE
     THE  COMPANY'S DEFINITIVE PROXY STATEMENT RELATING TO ITS ANNUAL MEETING OF
STOCKHOLDERS  TO  BE  HELD  ON  MAY  18,  2000,  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.
                                        1
<PAGE>

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  84,000  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, 1999 WERE AS
FOLLOWS:
*     26.7%  FROM  RESIDENTIAL  CUSTOMERS;
*     27.1%  FROM  SMALL  COMMERCIAL  AND  INDUSTRIAL  CUSTOMERS;
*     17.3%  FROM  LARGE  COMMERCIAL  AND  INDUSTRIAL  CUSTOMERS;
*     27.2%  FROM  SALES  TO  OTHER  UTILITIES;  AND
*     1.7%  FROM  OTHER  SOURCES.

     DURING  1999,  OUR  ENERGY  RESOURCES  FOR  RETAIL  AND  WHOLESALE SALES OF
ELECTRICITY  WERE  OBTAINED  AS  FOLLOWS:
*     43.0%  FROM HYDROELECTRIC SOURCES (4.8% COMPANY-OWNED, 0.1% NEW YORK POWER
AUTHORITY  (NYPA),  35.7%  HYDRO-QUEBEC  AND  2.4%  SMALL  POWER  PRODUCERS);
*     30.3%  FROM  A NUCLEAR GENERATING SOURCE (THE VERMONT YANKEE NUCLEAR PLANT
DESCRIBED  BELOW);
*     3.2%  FROM  WOOD;
*     3.6%  FROM  NATURAL  GAS;
*     2.1%  FROM  OIL;  AND
*     0.6%  FROM  WIND.
THE  REMAINING  17.2%  WAS  PURCHASED ON A SHORT-TERM BASIS FROM OTHER UTILITIES
THROUGH  THE  INDEPENDENT SYSTEM OPERATOR OF NEW ENGLAND (ISO), FORMERLY THE NEW
ENGLAND  POWER  POOL  (NEPOOL).

     IN  1999,  WE  PURCHASED 87.7% 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  MEGAWATT  (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.
     THE COMPANY PARTICIPATES  IN  NEPOOL, A REGIONAL BULK  POWER  TRANSMISSION
ORGANIZATION  ESTABLISHED  TO ASSURE RELIABLE AND ECONOMICAL POWER SUPPLY IN THE
NORTHEAST.  AN  INDEPENDENT  SYSTEM  OPERATOR  IN  NEW  ENGLAND  (THE "ISO") WAS
CREATED  TO  MANAGE  THE  OPERATIONS  OF  NEPOOL  IN  1999.  THE  ISO WORKS AS A
CLEARINGHOUSE  FOR  PURCHASERS AND SELLERS OF ELECTRICITY IN THE NEW DEREGULATED
MARKETS.  SELLERS PLACE BIDS FOR THE SALE OF THEIR GENERATION OR PURCHASED POWER
RESOURCES  AND IF DEMAND IS HIGH ENOUGH THE OUTPUT FROM THOSE RESOURCES IS SOLD.
WE  MUST  PURCHASE ADDITIONAL ELECTRICITY TO MEET CUSTOMER DEMAND DURING PERIODS
OF  HIGH  USAGE  AND  TO  REPLACE  ENERGY  REPURCHASED  BY HYDRO-QUEBEC UNDER AN
ARRANGEMENT  NEGOTIATED  IN  1997.  OUR  COSTS TO SERVE DEMAND DURING PERIODS OF
WARMER  THAN  NORMAL  TEMPERATURES  IN  SUMMER MONTHS AND TO REPLACE SUCH ENERGY
REPURCHASES  BY  HYDRO-QUEBEC  ROSE  SUBSTANTIALLY  AFTER  THE  MARKET OPENED TO
COMPETITIVE  BIDDING ON MAY 1, 1999.  THE COST OF SECURING FUTURE POWER SUPPLIES
HAS  ALSO  RISEN  IN  TANDEM  WITH  HIGHER  SUMMER  SUPPLY  COSTS.



     THE  COMPANY'S  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.

                                        2
<PAGE>

     MAJOR  BUSINESS  ACTIVITIES  IN OUR SERVICE AREAS INCLUDE COMPUTER ASSEMBLY
AND  COMPONENTS  MANUFACTURING  (AND  OTHER ELECTRONICS MANUFACTURING), SOFTWARE
DEVELOPMENT,  GRANITE  FABRICATION,  SERVICE  ENTERPRISES  SUCH  AS  GOVERNMENT,
INSURANCE,  REGIONAL  RETAIL  SHOPPING  AND  TOURISM  (PARTICULARLY  WINTER
RECREATION),  AND  DAIRY  AND  GENERAL  FARMING.

SEGMENT  INFORMATION

     THE  COMPANY HAS DECIDED TO SELL OR DISPOSE OF THE OPERATIONS AND ASSETS OF
MOUNTAIN  ENERGY,  INC.  (MEI).  INDUSTRY  SEGMENT  INFORMATION  REQUIRED  TO BE
DISCLOSED  IS  PRESENTED  IN  NOTE  L  OF  THE  NOTES  TO CONSOLIDATED FINANCIAL
STATEMENTS,  ANNUAL  REPORT  TO  STOCKHOLDERS,  1999.

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 1999, 317.9 MW, OCCURRED ON DECEMBER
28,  1999.
      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
KILOWATT-HOUR  DURING  FOUR PEAK SEASON MONTHS (DECEMBER THROUGH MARCH) THAT ARE
APPROXIMATELY  30% HIGHER THAN DURING THE EIGHT OFF-SEASON MONTHS (APRIL THROUGH
NOVEMBER).  SEE  ENERGY  EFFICIENCY  AND  RATE  DESIGN.

SINGLE  CUSTOMER  DEPENDENCE

     OUR  LARGEST  CUSTOMER  IS INTERNATIONAL BUSINESS MACHINES (IBM).  ELECTRIC
ENERGY  SALES  TO  IBM  FOR  THE  YEARS  ENDED DECEMBER 31, 1999, 1998 AND 1997,
ACCOUNTED FOR 11.8%, 14.7% AND 14.0%, RESPECTIVELY, OF OUR OPERATING REVENUES IN
THOSE  YEARS.  THE  PERCENTAGE DECREASE FROM 1998 TO 1999 REFLECTS THE IMPACT OF
MS  AGREEMENT  TRANSACTIONS.  REVENUES  FROM IBM ACTUALLY INCREASED IN 1999.  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.  SEE  NOTES  A  AND  K  OF  THE NOTES TO
CONSOLIDATED  FINANCIAL  STATEMENTS,  ANNUAL  REPORT  TO  STOCKHOLDERS,  1999.

     OPERATING STATISTICS FOR THE PAST FIVE YEARS ARE PRESENTED ON THE FOLLOWING
TABLE.
                                        3
<PAGE>

<TABLE>
<CAPTION>

GREEN  MOUNTAIN  POWER  CORPORATION
                             Operating Statistics     For the years ended December 31,


                                                      1999         1998         1997         1996         1995
                                                   -----------  -----------  -----------  -----------  -----------
<S>                                                <C>          <C>          <C>          <C>          <C>
Total capability (MW) . . . . . . . . . . . . . .       393.2        396.9        416.9        425.8        396.1
Net system peak . . . . . . . . . . . . . . . . .       317.9        312.5        311.5        313.0        297.1
                                                   -----------  -----------  -----------  -----------  -----------
Reserve (MW). . . . . . . . . . . . . . . . . . .        75.3         84.4        105.4        112.8         99.0
                                                   ===========  ===========  ===========  ===========  ===========
Reserve % of peak . . . . . . . . . . . . . . . .        23.7%        27.0%        33.8%        36.0%        33.3%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . .   1,095,738      972,723    1,073,246    1,192,881    1,043,617
Wind. . . . . . . . . . . . . . . . . . . . . . .       7,956            -            -            -            -
Nuclear . . . . . . . . . . . . . . . . . . . . .     731,431      607,708      772,030      680,613      682,814
Conventional steam. . . . . . . . . . . . . . . .   2,328,267      750,602      560,504      705,331      673,982
Internal combustion . . . . . . . . . . . . . . .      12,312       40,148        4,827        2,674        6,646
Combined cycle. . . . . . . . . . . . . . . . . .      99,962      118,322      104,836       51,162       92,723
                                                   -----------  -----------  -----------  -----------  -----------
                    Total production. . . . . . .   4,275,666    2,489,503    2,515,443    2,632,662    2,499,782
Less non-firm sales to other utilities. . . . . .   2,152,781      499,409      524,192      663,175      582,942
                                                   -----------  -----------  -----------  -----------  -----------
Production for firm sales . . . . . . . . . . . .   2,122,885    1,990,094    1,991,251    1,969,487    1,916,840
Less firm sales and  lease transmissions. . . . .   1,920,257    1,883,959    1,870,914    1,814,371    1,760,830
                                                   -----------  -----------  -----------  -----------  -----------
Losses and company use (MWH). . . . . . . . . . .     202,628      106,134      120,337      155,115      156,010
                                                   ===========  ===========  ===========  ===========  ===========
Losses as a % of total production . . . . . . . .        4.74%        4.26%        4.78%        5.89%        6.24%
System load factor (***). . . . . . . . . . . . .        80.3%        71.8%        71.6%        69.7%        71.2%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . .        25.6%        39.1%        42.7%        45.3%        41.7%
NYPA lease transmissions (Hydro). . . . . . . . .         0.2%         0.0%         0.0%         0.0%         0.0%
Nuclear . . . . . . . . . . . . . . . . . . . . .        17.1%        24.4%        30.6%        25.9%        27.3%
Conventional steam. . . . . . . . . . . . . . . .        54.5%        30.2%        22.3%        26.8%        27.0%
Internal combustion . . . . . . . . . . . . . . .         0.3%         1.6%         0.2%         0.1%         0.3%
Combined cycle. . . . . . . . . . . . . . . . . .         2.3%         4.8%         4.2%         1.9%         3.7%
                                                   -----------  -----------  -----------  -----------  -----------
                  Total . . . . . . . . . . . . .       100.0%       100.0%       100.0%       100.0%       100.0%
                                                   ===========  ===========  ===========  ===========  ===========

Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . .     544,447      533,904      549,259      557,726      549,296
Commercial & industrial - small . . . . . . . . .     688,493      665,707      645,331      630,838      608,688
Commercial & industrial - large . . . . . . . . .     664,110      636,436      608,051      584,249      556,278
Other . . . . . . . . . . . . . . . . . . . . . .       3,138        3,476        3,939        2,898        8,855
                                                   -----------  -----------  -----------  -----------  -----------
Total retail sales and lease transmissions. . . .   1,900,188    1,839,522    1,806,581    1,775,712    1,723,117
Sales to Municipals & Cooperatives (Rate W) . . .      20,069       44,437       64,333       38,660       37,713
                                                   -----------  -----------  -----------  -----------  -----------
Total Requirements Sales. . . . . . . . . . . . .   1,920,257    1,883,959    1,870,914    1,814,371    1,760,830
Other Sales for Resale. . . . . . . . . . . . . .   2,152,781      499,409      524,192      663,175      582,942
                                                   -----------  -----------  -----------  -----------  -----------
Total sales and  lease transmissions(MWH) . . . .   4,073,038    2,383,368    2,395,106    2,477,546    2,343,772
                                                   ===========  ===========  ===========  ===========  ===========

Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . .      71,515       71,301       70,671       70,198       69,659
Commercial and industrial small . . . . . . . . .      12,438       12,170       11,989       11,828       11,712
Commercial and industrial large . . . . . . . . .          23           23           23           25           24
Other . . . . . . . . . . . . . . . . . . . . . .          66           70           75           75           76
                                                   -----------  -----------  -----------  -----------  -----------
             Total. . . . . . . . . . . . . . . .      84,042       83,564       82,758       82,126       81,471
                                                   ===========  ===========  ===========  ===========  ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . .       12.32        11.56        11.18        10.87        10.09
Lease charges . . . . . . . . . . . . . . . . . .        0.00         0.00         0.00         0.00         0.00
                                                   -----------  -----------  -----------  -----------  -----------
Residential including NYPA lease revenues . . . .       12.32        11.56        11.18        10.87        10.09
Commercial & industrial - small . . . . . . . . .        9.88         9.29         9.10         8.96         8.42
Commercial & industrial - large . . . . . . . . .        6.55         6.32         6.22         6.28         5.86
                                                   -----------  -----------  -----------  -----------  -----------
Total retail including lease. . . . . . . . . . .        9.47         8.96         8.79         8.72         8.08
                                                   ===========  ===========  ===========  ===========  ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . .       7,617        7,488        7,772        7,945        7,885
Revenues including lease revenues . . . . . . . .  $      938   $      865   $      869   $      863   $      796
</TABLE>

 (*)  MW  -  Megawatt  is  one  thousand  kilowatts.
(**)  MWH  -  Megawatt  hour  is  one  thousand  kilowatt  hours.
(***)  Load  factor  is  based  on  net system peak and firm MWH production less
off-system  losses.


                                        4
<PAGE>

EMPLOYEES

     AS  OF  DECEMBER  31,  1999,  THE  COMPANY  HAD 196 EMPLOYEES, EXCLUSIVE OF
TEMPORARY  EMPLOYEES,  AND  OUR  SUBSIDIARY,  MOUNTAIN  ENERGY  INC.,  HAD  FIVE
EMPLOYEES.  THE  COMPANY CONSIDERS ITS RELATIONS WITH EMPLOYEES TO BE EXCELLENT.






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  LESS  THAN  1%  OF  OPERATING  REVENUES  FOR  1999.
     LATE  IN  1989,  WE  BEGAN SERVING A MUNICIPAL UTILITY, NORTHFIELD ELECTRIC
DEPARTMENT, UNDER OUR WHOLESALE TARIFF.  THIS CUSTOMER INCREASED OUR ELECTRICITY
SALES IN 1999 BY APPROXIMATELY 17,540 MWH AND PEAK REQUIREMENTS BY APPROXIMATELY
5.5  MW.  REVENUES  IN  1999  FROM  NORTHFIELD WERE $1,274,666.  THE CONTRACT TO
PURCHASE  AND  PROVIDE  ENERGY, AND MAINTAIN RELATED PRODUCTION ASSETS, ENDED IN
SEPTEMBER  1999.
     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  1999.
     ON  APRIL  24, 1996, THE FEDERAL ENERGY REGULATORY COMMISSION (FERC) ISSUED
ORDERS 888 AND 889 WHICH, AMONG OTHER THINGS, REQUIRED THE FILING OF OPEN ACCESS
TRANSMISSION  TARIFFS  BY  ELECTRIC  UTILITIES, AND THE FUNCTIONAL SEPARATION BY
UTILITIES  OF  THEIR  TRANSMISSION  OPERATIONS  FROM POWER MARKETING OPERATIONS.
ORDER 888 ALSO SUPPORTS THE FULL RECOVERY OF LEGITIMATE AND VERIFIABLE WHOLESALE
POWER  COSTS  PREVIOUSLY  INCURRED  UNDER  FEDERAL  OR  STATE  REGULATION.
     ON  JULY  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
DO  NOT  ANTICIPATE  ANY MATERIAL ADVERSE EFFECTS OR LOSS OF WHOLESALE CUSTOMERS
DUE TO THE FERC ORDERS MENTIONED ABOVE.  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.
     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:

                                        5
<PAGE>

<TABLE>
<CAPTION>


                  Issue Date   Licensed Period
                -------------  ---------------
<S>            <C>              <C>
Project Site:
Bolton. . . .  February 5,1982  February 5,1982 - February 4, 2022
Essex . . . .  March 30, 1995   March 1, 1995 - March 1, 2025
Vergennes . .  June 29, 1999    June 1, 1999 - May 31, 2029
Waterbury . .  July 20, 1954    September 1, 1951 - August 31, 2001
</TABLE>

     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 WATERBURY WAS FILED IN AUGUST 1999.  THE
COMPANY  EXPECTS  THE  PROJECT  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.   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 WAS 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:
*     IMPLEMENT 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 $5.84
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.

     ON  SEPTEMBER  7  AND DECEMBER 17, 1999, (VPSB) ISSUED ORDERS APPROVING TWO
AMENDMENTS  TO  THE  MOU  THAT  THE  COMPANY  HAD  ENTERED INTO WITH THE VERMONT
DEPARTMENT  OF  PUBLIC  SERVICE  (THE  DEPARTMENT  OR  DPS)  AND  IBM.  THE  TWO
AMENDMENTS  CONTINUED  THE  STAY  OF PROCEEDINGS UNTIL SEPTEMBER 1, 2000, WITH A
FINAL  DECISION  EXPECTED  BY  DECEMBER 31, 2000.  THE AMENDMENTS MAINTAINED THE
OTHER  FEATURES  OF  THE  ORIGINAL  MOU, AND THE SECOND AMENDMENT PROVIDES FOR A
TEMPORARY  RATE INCREASE OF 3 PERCENT, IN ADDITION TO THE CURRENT TEMPORARY RATE
LEVEL, TO BECOME EFFECTIVE AS OF JANUARY 1, 2000.  THE TEMPORARY RATES ARE STILL
SUBJECT  TO  REFUND  IN THE FINAL RATE CASE DECISION, IF THE FINAL RATES SET ARE
LOWER  THAN  THE  TEMPORARY  RATES.  ONE  PARTY  TO  THE RATE CASE, THE AMERICAN
ASSOCIATION  OF  RETIRED  PERSONS,  (AARP),  HAS  FILED AN APPEAL TO THE VERMONT
SUPREME  COURT  OF  THE VPSB'S ORDER OF DECEMBER 17, 1999, ARGUING THAT THE VPSB
SHOULD  HAVE ORDERED THE COMPANY TO POST A BOND OR ESCROW FOR THE TEMPORARY RATE
INCREASE.  THE COMPANY HAS MOVED TO DISMISS THE APPEAL.  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,  RATES,  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.

                                        6
<PAGE>

     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.
          IN  CERTAIN  STATES  ACROSS  THE  COUNTRY,  INCLUDING  THE NEW ENGLAND
STATES,  LEGISLATION  HAS BEEN ENACTED TO ALLOW RETAIL CUSTOMERS TO CHOOSE THEIR
ELECTRICITY  SUPPLIERS,  WITH  INCUMBENT  UTILITIES  REQUIRED  TO  DELIVER  THAT
ELECTRICITY  OVER  THEIR  TRANSMISSION  AND  DISTRIBUTION  SYSTEMS.  INCREASED
COMPETITIVE PRESSURE IN THE ELECTRIC UTILITY INDUSTRY MAY RESTRICT THE COMPANY'S
ABILITY  TO  CHARGE  ENERGY PRICES SUFFICIENT 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 SOME
STATES,  INCLUDING  VERMONT  WHERE  LEGISLATION  HAS  NOT  BEEN  ENACTED,  ARE
CONSIDERING  HOW  TO  FACILITATE COMPETITION FOR ELECTRICITY SALES.  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 RENEWED A CONTRACT WITH MORGAN STANLEY CAPITAL GROUP, INC.
AS  THE  RESULT OF OUR ALL POWER REQUIREMENTS SOLICITATION IN 1999.  SEE NOTES I
AND  M  OF  NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS.
     THE COMPANY GENERATED, PURCHASED OR TRANSMITTED 2,388,361 MWH OF ENERGY FOR
RETAIL AND REQUIREMENTS WHOLESALE CUSTOMERS FOR THE TWELVE MONTHS ENDED DECEMBER
31,  1999.  THE  CORRESPONDING  MAXIMUM  ONE-HOUR  INTEGRATED DEMAND DURING THAT
PERIOD WAS 317.9 MW ON DECEMBER 28, 1999.  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.
                                        7
<PAGE>


<TABLE>
<CAPTION>

Net  Electricity  Generated  and  Purchased

                                     During year      At time of
                                   Ended 12/31/99   of annual peak
                                           MWH            percent        KW     percent
                                   ---------------  ---------------  -------  --------
<S>                                <C>              <C>              <C>      <C>
Wholly-owned plants:
Hydro . . . . . . . . . . . . . .         115,794              4.8%   35,300      9.0%
Diesel and Gas Turbine. . . . . .          11,564              0.5%   46,200     11.7%
Wind. . . . . . . . . . . . . . .          13,605              0.6%      850      0.2%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . . .          20,426              0.8%    7,100      1.8%
Stony Brook I . . . . . . . . . .          33,987              1.4%   31,000      7.9%
McNeil. . . . . . . . . . . . . .          24,890              1.0%    6,600      1.7%
Owned in association with Others:
Vermont Yankee Nuclear. . . . . .         731,431             30.3%   95,680     24.3%
Long Term Purchases:
Hydro-Qubec . . . . . . . . . . .         861,657             35.7%  119,420     30.4%
Stony Brook I . . . . . . . . . .          65,975              2.7%   14,150      3.6%
Other:
NYPA. . . . . . . . . . . . . . .           1,838              0.1%      250      0.1%
Small Power Producers . . . . . .         115,906              4.8%   24,650      6.3%
Short-term purchases. . . . . . .         417,208             17.3%   12,020      3.1%
                                   ---------------  ---------------  -------  --------
Total . . . . . . . . . . . . . .       2,414,281          393,220
Less system sales energy. . . . .         (25,920)               -
                                   ---------------  ---------------
Net Own Load. . . . . . . . . . .       2,388,361           100.00%  393,220   100.00%
                                   ===============  ===============  =======  ========
</TABLE>
VERMONT  YANKEE. ON OCTOBER 15, 1999, THE OWNERS OF VERMONT YANKEE NUCLEAR POWER
CORPORATION  ACCEPTED  A  BID FROM AMERGEN ENERGY COMPANY FOR THE VERMONT YANKEE
GENERATING  PLANT.  THE  ASSET  SALE WILL REQUIRE NUMEROUS REGULATORY APPROVALS,
INCLUDING  THE  FEDERAL  ENERGY  REGULATORY  COMMISSION,  THE NUCLEAR REGULATORY
COMMISSION,  THE  SECURITIES  AND EXCHANGE COMMISSION AND THE VPSB.   ASSUMING A
FINAL CLOSING DATE FOR THE TRANSACTION OF JULY 1, 2000, AMERGEN WILL PAY VERMONT
YANKEE  APPROXIMATELY  $23.5  MILLION  FOR  THE  PLANT  AND  PROPERTY.
     AS  A  CONDITION  OF  THE SALE, VERMONT YANKEE'S CURRENT OWNERS WILL MAKE A
ONE-TIME  AND  FINAL  PAYMENT  OF  $54.3  MILLION  TO  PRE-PAY  THE  PLANT'S
DECOMMISSIONING FUND. IN RETURN, AMERGEN WILL ASSUME FULL RESPONSIBILITY FOR ALL
FUTURE  OPERATING  COSTS AND THE OBLIGATION TO DECOMMISSION THE PLANT AT THE END
OF  ITS  LIFE.  THE  COMPANY  HAS AGREED TO BUY POWER FROM THE PLANT FOR PERIODS
THAT  MAY  EXTEND  UP TO TWELVE YEARS.  THE COMPANY AND THE OTHER CURRENT OWNERS
ARE  ALSO RESPONSIBLE TO VERMONT YANKEE FOR THEIR SHARE OF THE UNRECOVERED PLANT
AND  OTHER  COSTS  RESULTING  FROM  THE  SALE.
     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  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 ITS 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.
                                        8
<PAGE>

     IN  DECEMBER 1996, AUGUST 1997 AND JULY 1998, DECISIONS WERE MADE TO RETIRE
THREE  NEW ENGLAND NUCLEAR UNITS, CONNECTICUT YANKEE, MAINE YANKEE AND MILLSTONE
1  EFFECTIVE  IMMEDIATELY,  WITH  SEVERAL  YEARS REMAINING ON EACH LICENSE.  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  POWER  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
THE  ISO 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.
THE 2000 REFUELING OUTAGE IS TENTATIVELY SCHEDULED TO BEGIN JUNE 2001, THOUGH IT
MAY  OCCUR  EARLIER.  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 COSTS TO DECOMMISSION THE PLANT, AS
APPROVED  BY FERC, IS APPROXIMATELY $430 MILLION, OF WHICH $247 MILLION HAS BEEN
FUNDED.  AT  DECEMBER  31, 1999, OUR PORTION OF THE NET NON-FUNDED LIABILITY WAS
$33  MILLION,  WHICH  WE  EXPECT  WILL  BE  RECOVERED THROUGH RATES OVER VERMONT
YANKEE'S  REMAINING  OPERATING LIFE.  VERMONT YANKEE'S CURRENT OPERATING LICENSE
EXPIRES  MARCH  2012.
     DURING  THE  YEAR  ENDED  DECEMBER 31, 1999, WE USED 731,431 MWH OF VERMONT
YANKEE  ENERGY  TO  MEET 30.3% OF OUR RETAIL AND REQUIREMENTS WHOLESALE (RATE W)
SALES.  THE  AVERAGE  COST  OF VERMONT YANKEE ELECTRICITY IN 1999 WAS $0.051 PER
KWH.  VERMONT  YANKEE'S  ANNUAL  CAPACITY FACTOR FOR 1999 WAS 90.9%, COMPARED TO
73.6% IN 1998 AND 93.5% IN 1997.  THE 1999 CAPACITY FACTOR WAS THE BEST EVER FOR
VERMONT  YANKEE  IN  A  YEAR  THAT  INCLUDED  A  REFUELING  OUTAGE.
     SEE NOTE B OF THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, ANNUAL REPORT
TO  STOCKHOLDERS,  1999.
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 WHICH PROVIDED 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
*     A  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.
                                        9
<PAGE>


     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 EXPANDED 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, 1999, THE PRESENT
VALUE  OF  THE COMPANY'S OBLIGATION WAS APPROXIMATELY $7,038,000.  THE COMPANY'S
PROJECTED  FUTURE  MINIMUM  PAYMENTS  UNDER  THE PHASE II SUPPORT AGREEMENTS ARE
APPROXIMATELY  $440,000  FOR  EACH  OF  THE  YEARS 2000-2004 AND AN AGGREGATE OF
$4,838,000  FOR  THE  YEARS  2005-2020.
     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, 1999, THE CAPITAL STRUCTURE OF SUCH CORPORATIONS WAS
APPROXIMATELY  39%  COMMON  EQUITY AND 61% LONG-TERM DEBT.  SEE NOTES B AND 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 96-01 AND THE 96-02 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 OPTIONS.  THE
EXERCISE  OF THESE OPTIONS IN 1999 RESULTED IN AN INCREASE OF APPROXIMATELY $5.4
MILLION  TO  POWER  SUPPLY  EXPENSE  TO  MEET  CONTRACTUAL OBLIGATIONS UNDER THE
COMPANY'S  SELL-BACK  AGREEMENT  OF  DECEMBER 1997 WITH HYDRO-QUEBEC SEE ITEM 7.
MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF  FINANCIAL  CONDITION AND RESULTS OF
OPERATIONS  -  POWER  SUPPLY  EXPENSES,  AND  NOTES  I,  J  AND  K  OF  NOTES TO
CONSOLIDATED  FINANCIAL  STATEMENTS.
     IN  1999,  WE USED 447,281 MWH UNDER SCHEDULE B, 310,094 MWH UNDER SCHEDULE
C3,  AND  104,282  MWH  UNDER  HQ  9601 AND 9602 TO MEET 35.7% OF OUR RETAIL AND
REQUIREMENTS  WHOLESALE  SALES.  THE AVERAGE COST OF HYDRO-QUEBEC ELECTRICITY IN
1999  WAS  $0.055  PER  KWH.

     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  1999, WE USED 99,962 MWH FROM THIS PLANT TO MEET 4.1% OF OUR RETAIL
AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.042 PER KWH.  SEE NOTE
I  AND  K  OF  NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS.

                                       10
<PAGE>

     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  1999,  WE USED 20,426 MWH FROM THIS UNIT TO MEET 0.8% OF OUR RETAIL
AND  REQUIREMENTS  WHOLESALE  SALES  AT AN AVERAGE COST OF $0.034 PER KWH, BASED
ONLY ON OPERATION, MAINTENANCE, AND FUEL COSTS INCURRED DURING 1999.  SEE NOTE I
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  1999,  WE USED 24,890 MWH FROM THIS UNIT TO MEET 1.0% OF OUR RETAIL
AND  REQUIREMENTS  WHOLESALE  SALES  AT AN AVERAGE COST OF $0.041 PER KWH, BASED
ONLY ON OPERATION, MAINTENANCE, AND FUEL COSTS INCURRED DURING 1999.  SEE NOTE I
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 1999 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  1999, THROUGH BOTH OUR DIRECT CONTRACTS AND VEPPI, WE PURCHASED 115,906
MWH  OF  QUALIFYING  FACILITIES  PRODUCTION  TO  MEET  4.8%  OF  OUR  RETAIL AND
REQUIREMENTS  WHOLESALE  SALES  AT  AN  AVERAGE  COST  OF  $0.113  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  1999,  WE  PURCHASED  417,208  MWH, MEETING 17.3% OF OUR RETAIL AND
REQUIREMENTS  WHOLESALE  SALES,  AT  AN  AVERAGE  COST  OF  $0.049  PER  KWH.

     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 1999, THESE PLANTS PROVIDED 115,794 MWH OF LOW-COST ENERGY, MEETING 4.8%
OF  OUR RETAIL AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.048 PER
KWH  BASED  ON  TOTAL  EMBEDDED  COSTS  AND  MAINTENANCE.  SEE STATE AND FEDERAL
REGULATION  -  LICENSING.


                                       11
<PAGE>

     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.


     FUEL.  DURING  1999,  OUR  RETAIL  AND  REQUIREMENTS  WHOLESALE  SALES WERE
PROVIDED  BY  THE  FOLLOWING  FUEL  SOURCES:
*     43.0%  FROM  HYDRO  (4.8% COMPANY-OWNED, 0.1% NYPA, 35.7% HYDRO-QUEBEC AND
2.4%  FROM  SMALL  POWER  PRODUCERS);
*     30.3%  FROM  NUCLEAR;
*     3.2%  FROM  WOOD;
*     3.6%  FROM  NATURAL  GAS;
*     2.1%  FROM  OIL;
*     0.6%  FROM  WIND;  AND
*     17.2%  PURCHASED  ON  A  SHORT-TERM BASIS FROM OTHER UTILITIES AND THROUGH
           NEPOOL  AND  ISO.

     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, OFTEN
FOCUSING  ON  ONE  OF  THE  FOUR  COMPONENTS  AT  A TIME.   THE 1999 RELOAD COST
APPROXIMATELY  $20.8  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 1999 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  1999  VERMONT  YANKEE  ACCUMULATED
APPROXIMATELY  $102.2 MILLION IN AN IRREVOCABLE TRUST TO BE USED EXCLUSIVELY FOR
SETTLING 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 PEAK GENERATING STATIONS (80 MW).  WE DID NOT EXPERIENCE
DIFFICULTY  IN  OBTAINING  OIL  FOR  OUR  OWN  UNITS  DURING 1999, AND, WHILE NO
ASSURANCE  CAN  BE  GIVEN, WE DO NOT ANTICIPATE ANY SUCH DIFFICULTY DURING 2000.
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.
     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 291,002 TONS OF
WOOD CHIPS AND MILL RESIDUE AND 220.9 MILLION CUBIC FEET OF NATURAL GAS IN 1999.
THE  MCNEIL  PLANT,  ASSUMING  ANY  NEEDED REGULATORY APPROVALS ARE OBTAINED, IS
FORECASTING  YEAR  2000 CONSUMPTION OF WOOD CHIPS TO BE 300,000 TONS AND NATURAL
GAS  CONSUMPTION  OF  600  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.


                                       12
<PAGE>

     WIND  PROJECT.  THE COMPANY WAS SELECTED BY THE UNITED STATES DEPARTMENT OF
ENERGY  (DOE)  AND  THE  ELECTRIC  POWER  RESEARCH  INSTITUTE  (EPRI) TO BUILD A
COMMERCIAL  SCALE  WIND-POWERED  FACILITY.  THE  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  1999,  THE  PLANT  PROVIDED  13,605  MWH, MEETING 0.6% OF THE COMPANY'S
RETAIL  AND  REQUIREMENTS  WHOLESALE  SALES AT AN AVERAGE COST OF $0.07 PER KWH.

ENERGY  EFFICIENCY

     IN  1999, GMP CONTINUED TO FOCUS ITS 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  DROP  OUR
COST-PER-LIFETIME-KILOWATT-HOUR  SAVED TO 1.4 CENTS, WHICH IS A 70% REDUCTION IN
COSTS  SINCE  1992.  IN 1999, OUR ENERGY EFFICIENCY PROGRAMS SAVED APPROXIMATELY
9,400  MEGAWATTHOURS,  13% ABOVE TARGETED SAVINGS FOR THE YEAR.  DURING THE PAST
EIGHT YEARS OUR EFFICIENCY PROGRAMS HAVE ACHIEVED A CUMULATIVE ANNUAL SAVINGS OF
88,600  MEGAWATTHOURS,  SAVING  APPROXIMATELY  $7.85  MILLION  PER  YEAR FOR OUR
CUSTOMERS.  IN  1999,  WE  SPENT APPROXIMATELY $1.7 MILLION ON ENERGY EFFICIENCY
PROGRAMS,  APPROXIMATELY  .7%  OF  OUR  OPERATING  REVENUE  IN  1999.

          A STATEWIDE ENERGY EFFICIENCY UTILITY (EEU) WAS CREATED BY THE VPSB IN
1999  TO  MANAGE  ENERGY  EFFICIENCY PROGRAMS FOR ALL UTILITIES IN VERMONT.  THE
COMPANY'S  CUSTOMERS ARE NOW BILLED A SEPARATE EEU CHARGE THAT WE REMIT DIRECTLY
TO  THE  EEU.
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 2,160 OF THE COMPANY'S RESIDENTIAL CUSTOMERS CONTINUE TO BE BILLED
ON  THE  ORIGINAL  1976  TIME-OF-USE RATE BASIS.   IN 1987, THE COMPANY RECEIVED
REGULATORY  APPROVAL  FOR  A  RATE DESIGN THAT PERMITTED IT TO CHARGE PRICES FOR
ELECTRIC  SERVICE  THAT  REFLECTED  AS  ACCURATELY  AS  POSSIBLE THE COST BURDEN
IMPOSED  BY  EACH  CUSTOMER  CLASS.  THE COMPANY'S RATE DESIGN OBJECTIVES ARE TO
PROVIDE  A  STABLE  PRICING  STRUCTURE  AND  TO  ACCURATELY  REFLECT THE COST OF
PROVIDING  ELECTRIC SERVICES.  THIS RATE STRUCTURE HELPS TO ACHIEVE THESE GOALS.
SINCE  INEFFICIENT  USE  OF  ELECTRICITY  INCREASES  ITS COST, CUSTOMERS WHO ARE
CHARGED  PRICES  THAT REFLECT THE COST OF PROVIDING ELECTRICAL SERVICE HAVE REAL
INCENTIVES  TO FOLLOW THE MOST EFFICIENT USAGE PATTERNS.  INCLUDED IN THE VPSB'S
ORDER  APPROVING  THIS  RATE DESIGN WAS A REQUIREMENT THAT THE COMPANY'S LARGEST
CUSTOMERS  BE  CHARGED  TIME-OF-USE  RATES  ON  A  PHASED-IN  BASIS BY 1994.  AT
DECEMBER  31,  1999,  APPROXIMATELY  1,365  OF  THE COMPANY'S LARGEST CUSTOMERS,
COMPRISING  52%  OF  RETAIL  REVENUES,  CONTINUE TO RECEIVE SERVICE ON MANDATORY
TIME-OF-USE  RATES.
     IN  MAY 1994, THE COMPANY FILED ITS CURRENT RATE DESIGN WITH THE VPSB.  THE
PARTIES,  INCLUDING THE DEPARTMENT, IBM AND A LOW-INCOME ADVOCACY GROUP, ENTERED
INTO  A SETTLEMENT THAT WAS APPROVED BY THE VPSB ON DECEMBER 2, 1994.  UNDER THE
SETTLEMENT,  THE  REVENUE  ALLOCATION TO EACH RATE CLASS WAS ADJUSTED TO REFLECT
CLASS-BY-CLASS  COST CHANGES SINCE 1987, THE DIFFERENTIAL BETWEEN THE WINTER AND
SUMMER  RATES  WAS  REDUCED, THE CUSTOMER CHARGE WAS INCREASED FOR MOST CLASSES,
AND  USAGE  CHARGES WERE ADJUSTED TO BE CLOSER TO THE ASSOCIATED MARGINAL COSTS.

     NO  MODIFICATIONS  TO  BASE  RATE  REDESIGN HAVE TAKEN PLACE SINCE THE VPSB
ORDER  ISSUED  ON  DECEMBER  2,  1994.

DISPATCHABLE  AND  INTERRUPTIBLE  SERVICE  CONTRACTS

     IN  1999,  WE HAD INTERRUPTIBLE/DISPATCHABLE POWER CONTRACTS WITH TWO MAJOR
SKI  AREAS  AND  DISPATCHABLE-ONLY  CONTRACTS  WITH  AN  ADDITIONAL  TWENTY-SIX
CUSTOMERS.  THE  INTERRUPTIBLE  PORTION  OF  THE CONTRACTS ALLOWS THE COMPANY TO
CONTROL  POWER  SUPPLY  CAPACITY  CHARGES BY REDUCING OUR CAPACITY REQUIREMENTS.
DURING 1999, 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.

                                       13
<PAGE>

CONSTRUCTION  AND  CAPITAL  REQUIREMENTS

     OUR  CAPITAL EXPENDITURES FOR 1997 THROUGH 1999 AND PROJECTION FOR 2000 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  1997-1999,  INTERNALLY  GENERATED FUNDS, AFTER PAYMENT OF
DIVIDENDS,  PROVIDED  APPROXIMATELY 80 PERCENT OF TOTAL CAPITAL REQUIREMENTS FOR
CONSTRUCTION,  SINKING  FUND  OBLIGATIONS  AND  OTHER  REQUIREMENTS.  INTERNALLY
GENERATED  FUNDS  PROVIDED  87  PERCENT  OF  SUCH  REQUIREMENTS  FOR  1999.  WE
ANTICIPATE  THAT FOR 2000, INTERNALLY GENERATED FUNDS WILL PROVIDE APPROXIMATELY
90 PERCENT OF TOTAL CAPITAL REQUIREMENTS FOR REGULATED OPERATIONS, THE REMAINDER
TO  BE  DERIVED  FROM  BANK  LOANS.
     IN  CONNECTION  WITH THE FOREGOING, SEE ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS  OF  FINANCIAL  CONDITION  AND  RESULTS  OF  OPERATIONS - LIQUIDITY AND
CAPITAL  RESOURCES.

ENVIRONMENTAL  MATTERS

     WE  HAD  BEEN NOTIFIED BY THE ENVIRONMENTAL PROTECTION AGENCY (EPA) THAT WE
WERE  ONE  OF  SEVERAL  POTENTIALLY RESPONSIBLE PARTIES FOR CLEAN UP AT THE PINE
STREET  BARGE  CANAL  SITE  IN  BURLINGTON,  VERMONT.  IN  SEPTEMBER  1999,  WE
NEGOTIATED  A FINAL SETTLEMENT WITH THE UNITED STATES, THE STATE OF VERMONT, AND
OTHER  PARTIES  OVER  TERMS  OF A CONSENT DECREE THAT COVERS CLAIMS ADDRESSED IN
EARLIER  NEGOTIATIONS  AND  IMPLEMENTATION  OF  THE SELECTED REMEDY.  IN OCTOBER
1999,  THE  FEDERAL  DISTRICT  COURT  APPROVED THE CONSENT DECREE THAT ADDRESSES
CLAIMS  BY THE EPA FOR PAST PINE STREET BARGE CANAL SITE COSTS, NATURAL RESOURCE
DAMAGE  CLAIMS  AND  CLAIMS  FOR  PAST  AND FUTURE OVERSIGHT COSTS.  THE CONSENT
DECREE  ALSO  PROVIDES  FOR THE DESIGN AND IMPLEMENTATION OF RESPONSE ACTIONS AT
THE  SITE.  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  OF  NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS.

UNREGULATED  BUSINESSES

     IN  1998, WE SOLD THE ASSETS OF OUR WHOLLY OWNED SUBSIDIARY, GREEN MOUNTAIN
PROPANE GAS COMPANY.  IN 1999, GREEN MOUNTAIN RESOURCES, INC. SOLD ITS REMAINING
INTEREST IN GREEN MOUNTAIN ENERGY RESOURCES TO GREEN FUNDING I.  FOR INFORMATION
REGARDING  OUR  REMAINING  UNREGULATED  BUSINESSES,  SEE  ITEM  7.  MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS- FUTURE
OUTLOOK  -  UNREGULATED  BUSINESSES.

                                       14
<PAGE>

EXECUTIVE  OFFICERS

THE EXECUTIVE OFFICERS NAMES, AGES, AND POSITIONS OF THE COMPANY AS OF MARCH 15,
2000  ARE:


NANCY  ROWDEN  BROCK      44
     VICE  PRESIDENT, CHIEF FINANCIAL OFFICER AND TREASURER SINCE DECEMBER 1998,
AND  SECRETARY  SINCE  AUGUST  1999.  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    51
     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       43
      CONTROLLER SINCE OCTOBER 1996.  MANAGER OF GENERAL ACCOUNTING FROM 1990 TO
1996.

WALTER  S.  OAKES         53
     VICE  PRESIDENT-FIELD  OPERATIONS  SINCE  AUGUST  1999.  ASSISTANT  VICE
PRESIDENT-CUSTOMER  OPERATIONS  FROM  JUNE  1994 TO AUGUST 1999.  ASSISTANT VICE
PRESIDENT,  HUMAN  RESOURCES  FROM  AUGUST  1993  TO  JUNE 1994.  ASSISTANT VICE
PRESIDENT-CORPORATE  SERVICES  FROM  1988  TO  1993.

MARY  G.  POWELL          39
     SENIOR  VICE  PRESIDENT-CUSTOMER  AND  ORGANIZATIONAL  DEVELOPMENT  SINCE
DECEMBER 1999. VICE PRESIDENT-ADMINISTRATION FROM FEBRUARY 1999 THROUGH DECEMBER
1999.  VICE PRESIDENT, HUMAN RESOURCES AND ORGANIZATIONAL DEVELOPMENT FROM MARCH
1998  TO  FEBRUARY  1999.  PRIOR  TO  JOINING  THE COMPANY, SHE WAS PRESIDENT OF
HRWORKS,  A  HUMAN  RESOURCES  MANAGEMENT FIRM, FROM JANUARY 1997 TO MARCH 1998.
FROM  1992  TO  JANUARY 1997 SHE WORKED FOR KEYCORP IN VERMONT, MOST RECENTLY AS
SENIOR  VICE  PRESIDENT  COMMUNITY  BANKING.  AT KEYCORP SHE ALSO SERVED AS VICE
PRESIDENT  ADMINISTRATION  AND  VICE  PRESIDENT  OF  HUMAN  RESOURCES.

STEPHEN  C.  TERRY       57
     SENIOR  VICE  PRESIDENT-GOVERNMENT  AND  LEGAL RELATIONS SINCE AUGUST 1999.
SENIOR  VICE  PRESIDENT,  CORPORATE DEVELOPMENT FROM AUGUST 1997 TO AUGUST 1999.
VICE  PRESIDENT  AND  GENERAL MANAGER, RETAIL ENERGY SERVICES FROM 1995 TO 1997.
VICE  PRESIDENT-EXTERNAL  AFFAIRS  FROM  1991  TO  JANUARY  1995.

JONATHAN  H.  WINER         48   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, AND ARE ENTITLED TO 17.662% (93.8
MW  OF  A  TOTAL  531  MW)  OF  THE  CAPACITY,  OF  VERMONT  YANKEE,
*     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.
                                       15
<PAGE>


TRANSMISSION  AND  DISTRIBUTION

     THE  COMPANY  HAD,  AT DECEMBER 31, 1999, 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
APPROXIMATELY  ABOUT  2,430  MILES  OF  OVERHEAD LINES OF 2.4 KV TO 34.5 KV, AND
ABOUT  461  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,  569,750  KVA  OF  SUBSTATION TRANSFORMER CAPACITY IN
DISTRIBUTION  SUBSTATIONS  AND  1,085,000 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  USED  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.
          THE  COMPANY  HAS  ALSO  PROVIDED A SECOND MORTGAGE, LIEN AND SECURITY
INTEREST  IN  THE  COLLATERAL PLEDGED UNDER THE FIRST MORTGAGE BOND INDENTURE TO
THE  TWO  BANKS  PARTICIPATING  IN  THE  REVOLVING  CREDIT  AGREEMENT.




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."
                                       16
<PAGE>

<TABLE>
<CAPTION>


                                                                      Winter
                                                                    Capability
                            LOCATION           NAME          FUEL     MW(1)
                         ---------------  ---------------  --------  -------
<S>                      <C>              <C>              <C>       <C>
Wholly Owned
Hydro . . . . . . . . .  Middlesex, VT    Middlesex #2     Hydro        3.3
Hydro . . . . . . . . .  Marshfield, VT   Marshfield #6    Hydro        4.9
Hydro . . . . . . . . .  Vergennes, VT    Vergennes #9     Hydro        2.1
Hydro . . . . . . . . .  W. Danville, VT  W. Danville #15  Hydro        1.1
Hydro . . . . . . . . .  Colchester, VT   Gorge #18        Hydro        3.3
Hydro . . . . . . . . .  Essex Jct., VT   Essex #19        Hydro        7.8
Hydro . . . . . . . . .  Waterbury, VT    Waterbury #22    Hydro        5.0
Hydro . . . . . . . . .  Bolton, VT       DeForge #1       Hydro        7.8
Diesel. . . . . . . . .  Vergennes, VT    Vergennes #9     Oil          4.2
Diesel. . . . . . . . .  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)
Steam . . . . . . . . .  Yarmouth, ME     Wyman #4         Oil          7.1
Steam . . . . . . . . .  Burlington, VT   McNeil           Wood/Gas   6.6(3)
Combined. . . . . . . .  Ludlow, MA       Stony Brook #1   Oil/Gas   31.0(2)
Total Winter Capability                                       256.3
                                                           ========
</TABLE>

(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  TERMINATED  AN OPERATING LEASE FOR ITS CORPORATE HEADQUARTERS
BUILDING  AND  TWO OF ITS SERVICE CENTER BUILDINGS IN THE FIRST QUARTER OF 1999.
DURING  1998,  THE  COMPANY RECORDED A LOSS OF APPROXIMATELY $1.9 MILLION BEFORE
APPLICABLE  INCOME  TAXES  TO  REFLECT  THE  PROBABLE  LOSS  RESULTING FROM THIS
TRANSACTION.  THE  COMPANY SOLD ITS CORPORATE HEADQUARTERS BUILDING IN 1999, BUT
RETAINED  OWNERSHIP  OF  THE  TWO  SERVICE  CENTERS.


ITEM  3.  LEGAL  PROCEEDINGS
     THE  COMPANY IS INVOLVED IN SEVERAL LEGAL PROCEEDINGS, THE OUTCOME OF WHICH
WILL  SIGNIFICANTLY  AFFECT  THE VIABILITY AND OR POTENTIAL PROFITABILITY OF THE
COMPANY.  THE  MOST  SIGNIFICANT  LEGAL PROCEEDINGS ARE OUR 1997 AND 1998 RETAIL
RATE  REQUESTS,  AND ARBITRATION ABOUT HYDRO-QUEBEC'S NON-DELIVERY OF POWER AS A
RESULT  OF  THE  JANUARY  1998  ICE  STORM  IN  EASTERN  NORTH AMERICA.  SEE THE
DISCUSSION  UNDER  ITEM  7.  MANAGEMENT'S  DISCUSSION  AND ANALYSIS OF FINANCIAL
CONDITION  AND  RESULTS  OF  OPERATIONS  -  "ENVIRONMENTAL  MATTERS"
RATE  MATTERS  AND  NOTE I OF THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR
MORE  DETAILED  INFORMATION.

                                       17
<PAGE>


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  1998  AND  1999:

<TABLE>
<CAPTION>



                  HIGH      LOW
                --------  --------
<S>             <C>       <C>
                    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
                    1999
First Quarter.  11  3/16     9 3/4
Second Quarter  11  5/16   8 11/16
Third Quarter.        14    10 1/4
Fourth Quarter    10 1/4     7 1/8
</TABLE>
  THE  NUMBER  OF COMMON STOCKHOLDERS OF RECORD AS OF MARCH 21, 2000 WAS 65,012.

QUARTERLY  CASH  DIVIDENDS  WERE  PAID  AS  FOLLOWS  DURING  THE PAST TWO YEARS:

<TABLE>
<CAPTION>


       First     Second    Third     Fourth
      Quarter   Quarter   Quarter   Quarter
      --------  --------  --------  --------
<S>   <C>       <C>       <C>       <C>
1998  $ 0.2750  $ 0.2750  $ 0.2750  $ 0.1375
1999  $ 0.1375  $ 0.1375  $ 0.1375  $ 0.1375
</TABLE>

 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, RATES-1998 RETAIL RATE CASE.

     THE  CURRENT ENVIRONMENT PROMPTED US TO REASSESS THE APPROPRIATENESS OF OUR
TRADITIONAL DIVIDEND POLICY.   HISTORICALLY, WE BASED OUR DIVIDEND POLICY ON THE
CONTINUED VALIDITY OF THREE ASSUMPTIONS: THE ABILITY TO ACHIEVE EARNINGS GROWTH,
THE  RECEIPT  OF  AN ALLOWED RATE OF RETURN THAT ACCURATELY REFLECTS OUR COST OF
CAPITAL,  AND  THE RETENTION OF OUR EXCLUSIVE FRANCHISE.  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  THE COMPANY'S 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, FOR A
DISCUSSION  OF  DIVIDEND  RESTRICTIONS.

                                       18
<PAGE>

ITEM  6.   SELECTED  FINANCIAL  DATA
<TABLE>
<CAPTION>

RESULTS  OF  OPERATIONS  FOR  THE  YEARS  ENDED  DECEMBER  31,
--------------------------------------------------------------


                                                1999       1998       1997       1996       1995
                                              ---------  ---------  ---------  ---------  ---------
<S>                                           <C>        <C>        <C>        <C>        <C>
       In thousands, except per share data
Operating Revenues . . . . . . . . . . . . .  $251,048   $184,304   $179,323   $179,009   $161,544
Operating Expenses . . . . . . . . . . . . .   243,102    178,832    163,808    162,882    146,249
                                              ---------  ---------  ---------  ---------  ---------
    Operating Income . . . . . . . . . . . .     7,946      5,472     15,515     16,127     15,295
                                              ---------  ---------  ---------  ---------  ---------

Other Income
  AFUDC - equity . . . . . . . . . . . . . .       134        104        357        175         27
  Other. . . . . . . . . . . . . . . . . . .     3,319      1,509      1,074      1,739      2,225
                                              ---------  ---------  ---------  ---------  ---------
    Total other income . . . . . . . . . . .     3,453      1,613      1,431      1,914      2,252
                                              ---------  ---------  ---------  ---------  ---------

Interest Charges
  AFUDC - borrowed . . . . . . . . . . . . .       (91)      (131)      (315)      (468)      (547)
  Other. . . . . . . . . . . . . . . . . . .     7,274      8,007      7,965      7,866      7,973
                                              ---------  ---------  ---------  ---------  ---------
    Total interest charges . . . . . . . . .     7,183      7,876      7,650      7,398      7,426
                                              ---------  ---------  ---------  ---------  ---------
Net Income (Loss) from continuing. . . . . .     4,216       (791)     9,296     10,643     10,121
  operations before preferred dividends
Net Income (Loss) from discontinued
  operations, including provisions
  for loss on disposal . . . . . . . . . . .    (7,279)    (2,086)       142      1,316      1,382
Dividends on Preferred Stock . . . . . . . .     1,155      1,296      1,433      1,010        771
                                              ---------  ---------  ---------  ---------  ---------
Net Income (Loss)Applicable
  to Common Stock. . . . . . . . . . . . . .  $ (4,218)  $ (4,173)  $  8,005   $ 10,949   $ 10,732
                                              =========  =========  =========  =========  =========

Common Stock Data
  Earnings per share-continuing operations .  $   0.57   $  (0.40)  $   1.54   $   1.95   $   1.97
  Earnings per share-discontinued operations  $  (1.36)  $  (0.40)  $   0.03   $   0.27   $   0.29
  Earnings per share-basic and diluted . . .  $  (0.79)  $  (0.80)  $   1.57   $   2.22   $   2.26
  Cash dividends declared per share. . . . .  $   0.55   $   0.96   $   1.61   $   2.12   $   2.12
  Weighted average shares outstanding. . . .     5,361      5,243      5,112      4,933      4,747
</TABLE>


<TABLE>
<CAPTION>

FINANCIAL  CONDITION  AS  OF  DECEMBER  31
------------------------------------------


                                             1999      1998      1997      1996      1995
                                           --------  --------  --------  --------  --------
<S>                                        <C>       <C>       <C>       <C>       <C>
ASSETS
  Utility Plant, Net. . . . . . . . . . .  $192,896  $195,556  $196,720  $189,853  $181,999
  Other Investments . . . . . . . . . . .    20,665    20,678    21,997    20,634    20,248
  Current Assets. . . . . . . . . . . . .    33,238    35,700    29,125    30,901    30,216
  Deferred Charges. . . . . . . . . . . .    41,853    35,576    35,831    43,224    42,951
  Non-Utility Assets. . . . . . . . . . .    11,099    27,314    42,060    39,927    37,868
                                           --------  --------  --------  --------  --------
    Total Assets. . . . . . . . . . . . .  $299,751  $314,824  $325,733  $324,539  $313,282
                                           ========  ========  ========  ========  ========

CAPITALIZATION AND LIABILITIES
  Common Stock Equity . . . . . . . . . .  $100,645  $106,755  $114,377  $111,554  $106,408
  Redeemable Cumulative Preferred Stock .    14,435    16,085    17,735    19,310     8,930
  Long-Term Debt, Less Current Maturities    88,500    88,500    93,200    94,900    91,134
  Capital Lease Obligation. . . . . . . .     7,038     7,696     8,342     9,006     9,778
  Current Liabilities . . . . . . . . . .    30,008    28,825    25,286    21,037    32,629
  Deferred Credits and Other. . . . . . .    59,125    59,889    53,723    54,968    52,041
  Non-Utility Liabilities . . . . . . . .         -     7,074    13,070    13,764    12,362
                                           --------  --------  --------  --------  --------
    Total Capitalization and Liabilities.  $299,751  $314,824  $325,733  $324,539  $313,282
                                           ========  ========  ========  ========  ========
</TABLE>

                                       19
<PAGE>

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.  This  explanation  includes:
*     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  that  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 discussed under "Future Outlook", "Transmission
Issues",  "Environmental Matters", "Rates" and "Liquidity and Capital Resources"
in  this  section,  and  include:
*     regulatory  and  judicial  decisions  or  legislation;
*     weather;
*     energy  supply  and  demand  and  pricing;
*     contractual  commitments;
*     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
only  as  of  the  date  of  this  report.

EARNINGS  SUMMARY

     The  Company lost $0.79 per average share of common stock in 1999, compared
to  a  loss  per share of $0.80 in 1998 and earnings per share of $1.57 in 1997.
The  1999  loss  represents  a  negative  return on average common equity of 4.0
percent.  The  return  on average common equity was negative 3.8 percent in 1998
and  positive  7.1  percent  in  1997.  Earnings from continuing operations were
$0.57 per share in 1999, compared to a loss of  $0.40 per share in 1998. Certain
subsidiary  operations, classified as discontinued in 1999, lost $1.36 per share
in  1999,  compared  to  a  loss  of  $0.40  per  share  in  1998.
     The  1999  loss  was  primarily  due  to  a  charge of $6.7 million for the
discontinuation  of  operations  of Mountain Energy, Inc. (MEI), a subsidiary of
the  Company  that  operates  wastewater,  energy  efficiency  and  generation
businesses.  The  Company  anticipates that it will sell these operations during
2000.

     The 1999 improvement in results from continuing operations is primarily due
to  three  factors:
*     retail  operating  revenues  increased  by $15.1 million, reflecting a 5.5
percent  temporary rate increase that went into effect on December 15, 1998, and
a  3.9 percent increase in sales to commercial and industrial customers in 1999;
*     operating  costs  were  $3.7  million  lower  in 1999 due to the Company's
termination  of  its corporate headquarters lease, reduced costs associated with
the  Company's  headquarters  facilities  and  lower  payroll expense reflecting
mid-year  reductions  in  the  number  of  employees;
*     results  for  1998  reflected pretax charges of $9.8 million in disallowed
Hydro-Quebec  power  costs  for both 1998 and 1999, compared to disallowed power
costs  of $7.5 million for 2000 recorded in 1999. The ultimate rate treatment of
the  Hydro-Quebec  power  costs  is  expected  to be determined in the Company's
pending  rate  case.

                                       20
<PAGE>


     The  1999  earnings  improvements  were  partially  offset  by:
*     a  $4.3 million increase in the capacity costs in 1999 associated with our
long-term  Hydro-Quebec  power  supply  contract;
*     an increase in the costs of short-term power following the deregulation of
energy  markets  in  New  England, as well as an increase in  our costs to serve
increased  local  loads  and an increase of approximately $5.4 million to supply
power to meet contractual obligations under the Company's sell-back agreement of
December  1997  with  Hydro-Quebec;  and
*     a  $1.9  million  increase  in  Vermont  Yankee  capacity  costs.


     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 assumed 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 offset by a $1.7 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.


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.

                                       21
<PAGE>

     In  certain  states  across  the country, including the New England states,
legislation  has  been  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 sufficient
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 some
states,  including  Vermont  where  legislation  has  not  been  enacted,  are
considering how to facilitate competition for electricity sales at the wholesale
and  retail  levels.  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  franchise,  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
imperil  the  Company's  financial  integrity,  we  will  evaluate all potential
alternatives  available  to  us  at  that  time,  including, but not limited to,
eliminating  common  stock  dividends,  or  the  filing  of  a  petition  for
reorganization  under  the  United  States  Bankruptcy  Code.

ITEM  7A.  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.  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 $300 million and $450
million.  We  intend  to  aggressively  pursue  mitigation  efforts  in order to
maximize  the  recovery  of  these  costs.
     If retail competition is implemented in Vermont, it cannot now be predicted
what  the  impact  would  be  on  the Company's revenues from electricity sales.
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  apply  only  to  regulated  businesses.  Statement of Financial
Accounting Standards Number 71, (SFAS 71), Accounting for the Effects of Certain
Types of Regulation, 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.  See "Liquidity and Capital Resources" and "Rates" for additional
information  related  to  SFAS  71.
     The  Company  currently  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 would be material.  Factors that could give rise to
the  discontinuance  of  SFAS  71  include:
*     deregulation;
*     a  change  in  the  regulator's  approach to setting rates from cost-based
regulation  to  another  form  of  regulation;

                                       22
<PAGE>

*     increasing competition that limits our ability to sell utility services or
products  at  rates  that  will  recover  costs;
*     regulatory  actions  that  limit  rate  relief  to a level insufficient to
recover  costs.
     Under  Statement  of  Financial  Accounting  Standards  Number  5 (SFAS 5),
Accounting  for  Contingencies,  the  enactment  of restructuring legislation or
issuance  of  a regulatory order containing provisions that do not allow for the
recovery  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.  In  addition,  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.
     Statement  of  Financial  Accounting  Standards  Number  121  (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, 1999, based
upon the regulatory environment within which we currently operate, no impairment
loss was recorded.  Competitive influences or regulatory developments, including
issues  pending  in  the  Company's  currently stayed rate case, 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 filings,
see  "Liquidity  and  Capital  Resources"  and  "Rates".

UNREGULATED  BUSINESSES
     In 1999, we continued to significantly reduce our investment in unregulated
businesses.  In June 1999, we decided to sell or otherwise dispose of the assets
of  MEI,  and  report  its  results  as  income  (loss)  from  operations  of  a
discontinued  segment.  MEI,  which  has  invested  in energy generation, energy
efficiency  and  waste  water  treatment  projects,  lost  $7.3 million in 1999,
compared  to  a  loss  of $2.6 million in 1998.  The 1999 loss results primarily
from  provisions  to  recognize  our estimate of future losses from the expected
sale  of  MEI's  businesses,  including  anticipated  operating  losses.
     The  1998  decrease  in  earnings  was due primarily to additional start-up
operating  losses  incurred  by Micronair, LLC and a write-off related to a wind
facility  in  California.
     Green  Mountain  Resources, Inc. (GMRI) was formed in April 1996 to explore
opportunities  in  the emerging competitive retail energy market.  In 1999, GMRI
earned $583,000 compared to a loss of $247,000 in 1998.  GMRI's earnings in 1999
was primarily due to the sale of its remaining interest in Green Mountain Energy
Resources  (GMER)  to  Green  Funding  I,  LLC.
     The  Company's  unregulated rental water heater business earned $500,000 in
1999, an increase from 1998's net income of $416,000.  The 1999 and 1998 results
contributed  9  cents  and  8  cents of earnings, respectively, per share to the
Company's  consolidated  results.

                                       23
<PAGE>

RESULTS  OF  OPERATIONS
OPERATING REVENUES AND MWH SALES-Operating revenues and megawatthour (MWh) sales
for  the  years  ended  1999,  1998  and  1997  consisted  of:

<TABLE>
<CAPTION>


                           Years ended December 31,
                                     1999                1998        1997
                           -------------------------  ----------  ----------
<S>                        <C>                        <C>         <C>
                                             (dollars in thousands)
Operating revenues
    Retail. . . . . . . .  $                 179,997  $  164,855  $  158,790
    Sales for Resale. . .                     68,305      16,529      17,847
    Other . . . . . . . .                      2,746       2,920       2,686
                           -------------------------  ----------  ----------
Total Operating Revenues.  $                 251,048  $  184,304  $  179,323
                           =========================  ==========  ==========

MWH Sales-Retail. . . . .                  1,900,188   1,839,522   1,806,580
MWH Sales for Resale. . .                  2,172,849     543,846     588,525
                           -------------------------  ----------  ----------
Total MWH Sales . . . . .                  4,073,037   2,383,368   2,395,105
                           =========================  ==========  ==========
</TABLE>


<TABLE>
<CAPTION>

Average  Number  of  Customers

                              Years ended December 31,
                                        1999             1998    1999
                              ------------------------  ------  ------
<S>                           <C>                       <C>     <C>
   Residential . . . . . . .                    71,476  71,301  70,671
   Commercial and Industrial                    12,458  12,193  12,012
   Other . . . . . . . . . .                        66      70      75
                              ------------------------  ------  ------
Total Number of Customers. .                    84,000  83,564  82,758
                              ========================  ======  ======
</TABLE>
Differences  in  operating  revenues  were  due  to  changes  in  the following:

<TABLE>
<CAPTION>

Change  in  Operating  Revenues

                                            1998 TO 1999  1997 TO 1998
                                            ------------  -------------
<S>                              <C>           <C>            <C>
  (In thousands)
Retail Rates                                   $       9,395  $ 3,114
Retail Sales Volume                                    5,747    2,952
Resales and Other Revenues                            51,602   (1,085)
                                               -------------  --------
Increase in Operating Revenues                 $      66,744  $ 4,981
                                               =============  ========
</TABLE>

In 1999, total electricity sales increased 70.9 percent due principally to sales
for  resale executed pursuant to the Morgan Stanley (MS) agreement, described in
more  detail  below  under  the heading "Power Supply Expense".  Total operating
revenues  increased  $66.7  million or 36.2 percent in 1999 for the same reason.
Total  retail  revenues increased $15.1 million or 9.2 percent in 1999 primarily
due  to:
*     a  5.5  percent  retail  rate  increase  for  service rendered on or after
December  15,  1998;
*     a  3.9  percent  increase  in  sales  of electricity to our commercial and
industrial  customers  resulting  from  customer growth and increased use of air
conditioning  during  the  spring  and  summer  months;  and
*     a 3.3 percent increase in sales of electricity to residential customers, a
result  of  customer  growth  and  a  warmer  than  normal  summer.

                                       24
<PAGE>

     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 on or after 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.

     International  Business  Machines  (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
11.8,  14.7,  and 14.0 percent of the Company's operating revenues in 1999, 1998
and  1997,  respectively.  No  other retail customer accounted for more than one
percent of the Company's revenue in any such year.  The percentage decrease from
1998  to  1999  reflects  MS  agreement transactions; Revenues from IBM actually
increased  in  1999.
     Since  1995,  the  Company  has  had  agreements  with  IBM with respect to
electricity  sales  above  agreed-upon  base-load  levels.  In  August 1999, the
agreement was renewed for the year 2000.  The agreement's price of power for the
renewal period continues to be above our marginal costs of providing incremental
service  to  IBM.  We  have  agreed  to  negotiate  with IBM for a new agreement
covering  a  three-year period beginning January 2001, with terms and conditions
similar to those existing.  Any new agreement will be subject to approval by the
VPSB.

POWER  SUPPLY  EXPENSES-Power  supply  expenses constituted 75.4, 67.7, and 61.3
percent  of  total  operating  expenses  for  the  years  1999,  1998, and 1997,
respectively.  Power  supply expenses increased by $62.2 million or 51.4 percent
in  1999  and  $20.7  million  or  20.6  percent  in  1998.
     The  increase  in power supply expenses from 1998 to 1999 resulted from the
following:
*     a $57.0 million increase reflecting the power purchase and supply contract
discussed  below,  whereby  we  buy  power  from  MS that is sufficient to serve
pre-established  load  requirements  at  a  pre-defined  price;
*     a  $4.3 million increase in the capacity costs in 1999 associated with our
long-term  Hydro-Quebec  power  supply  contract;
*     an increase in the costs of short-term power following the deregulation of
energy  markets  in  New  England,  as well as an increase in our costs to serve
increased  local loads and to supply power to meet contractual obligations under
the  Company's sell-back agreement of December 1997 with Hydro-Quebec  (net cost
approximately  $5.4  million);  and
*     a  $1.9  million  increase  in  Vermont  Yankee  capacity  costs.

     These  amounts  were  partially  offset  by  a reduction of $2.3 million in
losses  accrued  for the Hydro-Quebec power cost disallowance.  Results for 1998
reflected  pretax charges of $9.8 million in disallowed Hydro-Quebec power costs
for  both  1998 and 1999, compared to disallowed power costs of $7.5 million for
2000  recorded in 1999. Ultimate disposition of the disallowance associated with
Hydro-  Quebec power costs is expected to be determined in the Company's pending
rate  case.
     The  power  supply costs of Company-owned generation decreased 13.0 percent
in  1999  due  to the severe 1998 ice storm in New England that caused increased
usage  of  peak  generation resources to replace power that was unavailable from
Hydro-Quebec.

     Total  power  supply  expenses  increased  20.6  percent  from 1997 to 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.

                                       25
<PAGE>

     Company-owned  generation  costs  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  Qu  bec  in  January  1998.
     An  Independent  System  Operator  in  New  England  (ISO) replaced the New
England  Power  Pool  (NEPOOL)  effective  May  1,  1999.  The  ISO  works  as a
clearinghouse  for  purchasers and sellers of electricity in the new deregulated
markets.  Sellers place bids for the sale of their generation or purchased power
resources  and if demand is high enough the output from those resources is sold.
     We must purchase electricity to meet customer demand during periods of high
usage  and  to  replace  energy repurchased by Hydro-Quebec under an arrangement
negotiated  in  1997.  Our  costs  to serve demand during periods of warmer than
normal  temperatures  in summer months and to replace such energy repurchases by
Hydro-Quebec  rose  substantially after the ISO replaced NEPOOL as the governing
power  supply.  The  cost  of  securing  future  power  supplies  has also risen
substantially  in  tandem  with  higher  summer supply costs. The Company cannot
predict the duration or the extent to which future prices will continue to trade
above  historical  levels of cost. If the new markets continue to experience the
volatility  evident  in  the second and third quarters of 1999, our earnings and
cash  flow  could  be  adversely  impacted  by  a  material  amount.

POWER  CONTRACT  COMMITMENTS-     During 1994, we negotiated an arrangement with
Hydro-Quebec  that  reduced  the  cost under the 1987 Contract over the November
1995  through  October  1999  period  (the  July  1994  Agreement).
     As  part  of  the  July  1994 Agreement, we were obligated to purchase $4.0
million  (in  1994  dollars)  worth  of  research  and  development  work  from
Hydro-Quebec  over a four-year period, and made a $6.5 million (in 1994 dollars)
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  Qu  bec.
     Under  an  arrangement  executed in January 1996, we received payments from
Hydro-Quebec  of  $3.0  million  in  1996  and  $1.1 million in 1997.   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 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 benefit of approximately $3.0 million on a
net  present  value  basis.
     Under  a separate agreement executed on December 5, 1997, Hydro-Quebec paid
$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 may purchase up to
52,500  MWh  on an annual basis, at energy prices established in accordance with
the  1987  Contract.  The cumulative amount of energy that may be 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 these purchase options.  Over the same
period,  Hydro-Quebec  may  exercise  an option on an annual basis to purchase a
total  of  600,000  MWh  at  the  1987  Contract  energy price. Hydro-Quebec may
purchase  no  more  than  200,000  MWh  in any given year. In 1999, Hydro-Quebec
called  for  deliveries  to  third  parties  at a net cost of approximately $5.4
million.  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).
                                       26
<PAGE>

     In  1999,  the  Company  and  the  other  Vermont Joint Owners (VJO) of the
Hydro-Quebec contract initiated an arbitration against Hydro-Quebec, pursuant to
the  1987  contract  terms, to determine whether the suspension of deliveries of
power to Vermont during and after the January 1998 ice storm evidenced a default
by  Hydro-Quebec  under the terms of the contract.   Hydro-Quebec maintains that
the  "force  majeure" (superior or irreversible force) provision in the contract
applies, which could excuse its non-delivery of power under these circumstances.
Arbitration  of the dispute may lead to remedies having a material impact on our
contractual  obligation, including the possibility that the contract be declared
terminated  or  void.
     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 has
been fulfilled, currently anticipated to be January 31, 2002.  The PPSA has been
noticed  to  the  VPSB  and  filed with the Federal Energy Regulatory Commission
(FERC).

*     The  PPSA provides us with a means of managing price risks associated with
changing  fossil fuel prices.  On a daily basis, and at MS's discretion, we sell
power  to  MS from either (i) all or part of our portfolio of power resources at
predefined  operating  and  pricing  parameters  or  (ii)  any  power  resources
available  to  us,  provided  that  sales  of  power  from  sources  other  than
Company-owned  generation  comply  with  the  predefined  operating  and pricing
parameters.
*     MS  then  sells  to  us,  at a predefined price, power sufficient to serve
pre-established  load requirements.  MS is also responsible for balancing supply
resources when actual loads vary from the pre-established load requirements.  We
remain  responsible  for  resource  performance  and  availability,  however  MS
provides  coverage  against  major  unscheduled  outages,  up  to  $5.5  million
annually,  contingent  upon  both the price and availability of power resources.
     The  parties  have  agreed to the protocols that are used to schedule power
sales  and  purchases  between  the parties and to secure necessary transmission
with  respect  to  the  two  transactions  described  above.

OTHER OPERATING EXPENSES-     Other operating expenses decreased $3.7 million or
17.4  percent  in  1999.  The  decrease  results  from:
*     a $1.9 million estimated loss in 1998 to recognize the cost of terminating
the  corporate  headquarters operating lease.  The facilities were sold in April
1999;
*     a $1.4 million reduction in administrative and general salaries related to
a  workforce  reduction  plan;
*     the elimination in 1999 a regulatory liability of $1.2 million relating to
former  corporate  headquarters;
*     reductions in lease expense and facility carrying costs resulting from the
disposal  of  the  former  headquarters;  and
*     these  savings  were  partially offset by increased costs of approximately
$1.8  million  associated  with  our  reorganization.

TRANSMISSION  EXPENSES-Transmission  expenses  increased  $1.4  million  or 15.0
percent  in  1999  due  to  costs associated with the creation of the ISO as the
clearing  house  for power trades in New England and due to refunds in 1998 from
Central  Vermont  Public  Service  Corp.  (CVPS)  and New England Power Company.
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.
                                       27
<PAGE>

MAINTENANCE EXPENSES-Maintenance expenses increased $1.5 million or 29.6 percent
in 1999, reflecting increased expenditures on right-of-way maintenance programs.
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.
DEPRECIATION  AND  AMORTIZATION-     In 1999, depreciation and amortization were
nearly  identical  to  that  of  1998.  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.

INCOME TAXES-     The total effective federal and state income tax rates for the
years  1999,  1998 and 1997 were (68.2) percent, 32.2 percent, and 43.2 percent,
respectively.  Income  taxes  decreased  for  1999  due to a decrease in taxable
income.  Income  taxes  decreased  in  1998 due to a decrease in taxable income.

OTHER  INCOME-     Other  income increased $1.9 million in 1999, due to the 1999
gain  on  sale  of  the  remaining  interest  in GMER discussed previously under
"Unregulated business", and a $0.9 million write-off in 1998 of disallowed costs
of  our  Searsburg  wind  project.
     Other  income decreased $2 million in 1998, primarily due to a $2.1 million
loss  experienced  by  Mountain  Energy,  Inc. resulting from a $1.3 million net
write-off of a wind power investment in California and start up operating losses
incurred  by  Micronair LLC, and a $0.9 million disallowance in costs associated
with  the  Vermont  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 $1.7 million reduction in
losses  experienced  by  GMRI due to the absence of start-up expenses in 1998 as
compared  to  1997.
INTEREST CHARGES-Interest expense decreased $0.7 million or 8.7 percent in 1999,
consistent  with reductions in average long-term and short-term debt outstanding
during the year.  Interest charges increased $0.2 million or 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.  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.

DIVIDENDS  ON  PREFERRED  STOCK-     Dividends  on  preferred  stock  decreased
$141,000,  or  10.9  percent  in 1999 due to repurchases of preferred stock.  In
1998,  the  dividends  on preferred stock also decreased $137,000 or 9.6 percent
for  the  same  reason.

TRANSMISSION  ISSUES
FEDERAL  OPEN  ACCESS  TARIFF  ORDERS-On  April  24,  1996,  the  Federal Energy
Regulatory  Commission  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.

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<PAGE>

     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
do  not  anticipate  any material adverse effects or loss of wholesale customers
due  to  the  FERC  orders  mentioned  above.
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 programs to ensure that we are in compliance with environmental
regulations.  These  programs  include  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
previously  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.
     In September 1999, we negotiated a final settlement with the United States,
the  State of Vermont (State), and other parties to a Consent Decree that covers
claims  with respect to the site and implementation of the selected site cleanup
remedy.  In  November 1999, the Consent Decree was filed in the federal district
court.  The  Consent  Decree  addresses  claims  by the EPA for past Pine Street
Barge  Canal  site costs, natural resource damage claims and claims for past and
future  oversight  costs.  The  Consent  Decree also provides for the design and
implementation  of  response  actions  at  the  site.
     As  of December 31, 1999, our total expenditures related to the Pine Street
Barge  Canal  site  since  1982 were approximately $22.2 million.  This includes
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 a more expensive remedy
at  the  site, litigation and related costs necessary to obtain settlements with
insurers  and  other  PRP's  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  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.
     We  estimate  that  we  have recovered or secured, or will recover, through
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 recently
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, and to resolve monetary claims
of  the  EPA and the State, together with our remediation costs, are more likely
to  be  in the range of $8.7 to $12.5 million, rather than the previous estimate
of  $5.0  to  $9.0  million.  In  1998, we recorded a liability of $5 million to
recognize  the  low  end  of  the initial range of costs. In 1999 we recorded an

                                       29
<PAGE>

additional  liability  of  $3.7  million  to  reflect  revised estimates of site
monitoring costs to be incurred over the next 33 years.  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 that 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.    While  reserving  the  right  to  argue  in the future about the
appropriateness of full rate recovery of the site related costs, the Company and
the  Vermont  Department of Public Service, (the Department), and as applicable,
other  parties,  reached  agreements  in these cases that the full amount of the
site-related  costs  reflected in those rate cases should be recovered in rates.
     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  PRP's,  should  be  shared between customers and shareholders of the
Company.  In  response  to  our  Motion for Reconsideration, the VPSB on June 8,
1998  stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
See  "Rates-1997  Retail  Rate  Case"  below.

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.

RATES
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:
                                       30
<PAGE>

*     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  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, discussed below.
     In  its February 27, 1998 Order, the VPSB talked about 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  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 recognize a charge to income of approximately $154 million
before  income  taxes.   The  $154  million estimate represents primarily the 20
percent  disallowance  for  Hydro-Quebec  power  costs  that the VPSB considered
imprudent  in  its  1997  order.  We  are  unable  to  estimate  the  loss (from
disallowance)  to  be  recorded  for power purchased after December 31, 2000, if
any,  until  the  pending  1998  rate  case  is  completed.

     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  that  accounting  guidance  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  presently,  and under SFAS 71 we are required to
defer  certain  costs  that  would  typically  be accounted for as expense in an
unregulated  entity;  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 rate making 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.

     If  the  VPSB  does not modify 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  SFAS  71  and  eliminate all regulatory assets and
liabilities  that  arose from prior actions of the VPSB.  The write-off of these
                                       31
<PAGE>

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.
     Based  on  the  December  31,  1999  balance  sheet, if we were required to
discontinue  the  application  of  SFAS 71, we would be required to recognize an
after-tax  charge to earnings of approximately $27.0 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 certain aspects of the VPSB's Order released on March 2,
1998.  Immediately  following the issuance of the June 8, 1998 VPSB order on our
Motion  for  Reconsideration,  which mainly 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 number of other Vermont
utilities  submitted  briefs  in  support  of  the Company.  Oral arguments were
presented  to  the  Vermont  Supreme  Court  on  March  16,  1999.
     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 its
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.   If not
changed,  the  VPSB's  decision  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 higher power costs, 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 Department argued for 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.  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.
     On  November  18,  1998, by Memorandum of Understanding (MOU), the Company,
the  Department  and  IBM  agreed to stay 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 agreement to suspend our 1998 rate case
delayed 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 continued disallowance of Hydro-Quebec costs
through  December  15,  1999.  The MOU provided for a 5.5% temporary retail rate
increase,  to  produce  $8.9 million in annualized additional revenue, effective
with  service  rendered  December 15, 1998.  In the event that the VPSB issues a
final  order  that allows a retail rate increase that is less than the temporary
                                       32
<PAGE>

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.  At  December  31, 1999, total revenues subject to
refund  are  approximately $9.2 million.  An additional surcharge was permitted,
without further VPSB order, in order to produce additional revenues necessary to
provide  the  Company  with the capacity to finance 1999 Pine Street Barge Canal
site  expenditures.  The  MOU was approved by the VPSB on December 11, 1998. The
MOU  did  not  provide  for  any  specific disallowance of power costs under our
purchase  power  contract with Hydro-Quebec.  Issues respecting recovery of such
power  costs were preserved for future proceedings. The temporary rates included
$1.0  million  that is to be used for enhanced right of way maintenance and pole
testing and treatment.  Also, 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  stay  and  suspension of this pending rate case and the temporary rate
levels  agreed  to  in  the MOU were designed to allow us to continue to provide
adequate  and  efficient  service  to  our customers while we seek mitigation of
power  supply  costs.
      On September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments  to the MOU that the Company had entered into with the Department and
IBM.  The  two  amendments  continued the stay of proceedings until September 1,
2000,  with  a  final  decision  expected  by December 31, 2000.  The amendments
maintained  the  other  features  of  the original MOU, and the second amendment
provides  for a temporary rate increase of 3 percent, in addition to the current
temporary  rate level, to become effective as of January 1, 2000.  The temporary
rates  are still subject to refund in the final rate case decision, if the final
rates  set  are lower than the temporary rates.  One party to the rate case, the
American  Association  of  Retired  Persons  (AARP),  has filed an appeal to the
Vermont Supreme Court of the VPSB's order of December 17, 1999, arguing that the
VPSB  should have ordered the Company to post a bond or escrow for the temporary
rate  increase.  The  Company  has  moved  to  dismiss  the  appeal.
     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 reduction or elimination of common
stock  dividends or the filing of a petition for reorganization under the United
States  Bankruptcy  Code.

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 2000
are  as  follows:
                                       33
<PAGE>



<TABLE>
<CAPTION>


           Generation   Transmission   Distribution   Conservation   Other    Total
           -----------  -------------  -------------  -------------  ------  -------
(Dollars  in  thousands,  net  of  AFUDC and customer advances for construction)
Actual:
---------
<S>        <C>          <C>            <C>            <C>            <C>     <C>
1997* . .  $     3,462  $         986  $       9,680  $       2,094  $3,291  $19,513
1998. . .          543            751          6,063          1,244   4,568   13,169
1999**. .          210            144          7,283          1,943   9,039   18,619
Forecast:
---------
2000. . .        1,941          1,335          8,155            ***   3,043   14,474
</TABLE>

*    includes  $2.7  million  for  Searsburg  wind  farm
**  includes  $6.1  million  for  Pine  Street  Barge  Canal  site
***A  statewide  Energy  Efficiency Utility (EEU) has been set up by the VPSB to
manage all energy efficiency programs.  The Company's customers are now billed a
separate  EEU  charge  that  we  remit  directly  to  the  EEU


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 annual dividend rate was $0.55
per  share  at  December  31,  1999.
     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, 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
traditional dividend policy.  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-Internally generated funds provided approximately
80  percent  of  requirements  for  1999,  1998  and  1997 combined.  Internally
generated  funds,  after  payment of dividends, provide capital requirements for
construction,  sinking  funds  and  other requirements.   We anticipate that for
2000,  internally generated funds will provide approximately 90 percent of total
capital  requirements  for  regulated  operations.
     At  December  31, 1999, our capitalization consisted of 49.4 percent common
equity,  43.5  percent  long-term  debt  and  7.1  percent  preferred  equity.
     On  June  23, 1999, we renewed a revolving credit agreement with two banks.
The agreement is for a period of 364 days and will expire on June 21, 2000.  The
commitment of $15 million represents a reduction from the previous commitment of
$45  million.  We  believe the amounts available under the new agreement will be
sufficient  to  meet  our  forecasted  borrowing requirements during the 364-day
period.
     The terms continue the requirement that loans made under the agreement will
be  secured  by granting the banks a second priority mortgage, lien and security
interest  in  the  collateral  pledged  under  the Company's first mortgage bond
indenture.  We  also  have  an  uncommitted  line  of  credit  in  the amount of
$500,000,  under  which  no  amounts  were  outstanding  at  December  31, 1999.
     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.  Our agreement
allows  us  to  continue  to  borrow  until  such  time  that:
                                       34
<PAGE>

*     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.

     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.
     On  November  19, 1999, while negotiations for an additional temporary rate
increase  with  Department  and  IBM  were  ongoing but before any agreement was
reached,  the  banks  requested  that  the total amount available to the Company
under  the  existing  revolving  credit agreement be reduced from $15 million to
$8.5  million.  In  order  to have access to borrowed funds needed at that time,
the Company agreed to the banks' request.  Subsequent to the VPSB approval of an
additional  3  percent  rate  increase  in  December  1999,  the banks agreed to
maintain  the total amount available at $15 million.  The total amount available
will  be reduced by the net proceeds from certain sales of the Company's assets,
such  as  the  assets  of  MEI.
     If  we  are  unable  to  borrow on a short-term basis, we will evaluate all
potential  alternatives  available to us at the time, including, but not limited
to,  the  filing  of  a  petition  for  reorganization  under  the United States
Bankruptcy  Code.

     The  credit  ratings  of  the  Company's  securities  are:
<TABLE>
<CAPTION>



                            DUFF AND PHELPS  MOODY'S  STANDARD & POOR'S
                            ---------------  -------  -----------------
<S>                         <C>              <C>      <C>                <C>
First mortgage bonds . . .  BBB              Baa3     BBB
Unsecured medium term debt  BBB-                                     --  --
Preferred stock. . . . . .  BB+              ba2      BB
</TABLE>
On  August  25,  1999,  Moody's  Investor  Service  downgraded the rating of the
Company's  outstanding  preferred  stock  to  "ba2" from "ba1".  Duff & Phelps',
Moody's  and  Standard  & Poor's credit ratings for the Company remain on Rating
watch-down,  Review  for  possible further downgrade, 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.
See Note F of the Notes to Consolidated Financial Statements for a discussion of
the  bank  credit  facilities  available  to  the  Company.

YEAR  2000 COMPUTER COMPLIANCE-We experienced no interruption in the delivery of
electricity due to the transition from December 31, 1999 to January 1, 2000.  We
also  have  not  experienced  any  significant  events  related to the year 2000
transition  on  any  of our software applications or embedded systems. Potential
problems  with future dates continue to pose risk to the Company. 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.
     The  contingency  planning  process  implemented by the Company during 1999
remains  in  place.  The  phases  of  our  contingency  planning process include
business  impact  analysis  and  contingency  planning  and testing, and include
testing  of  year 2000 dates that pose continual risk.  Business impact analysis
                                       35
<PAGE>

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  were  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 stimulate major outages and
restart  capability.
          The  total  cost  of  upgrading software that would not otherwise have
been  replaced  in accordance with our business plans is approximately $310,000.
Approximately  $260,000  has  been expended as of December 31, 1999 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.  Such  replacement  projects were not accelerated because of Year 2000
issues.
     We  believe that our planning was adequate to secure Year 2000 readiness of
our  critical  systems.  Nevertheless, maintaining Year 2000 security 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  form  our  current  expectations  as  to  our  Year  2000 readiness.
However,  if  we,  or  third  parties  with  whom  we  have significant business
relationships,  fail  to  maintain  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.

NUCLEAR  DECOMMISSIONING-The  staff  of  the  SEC has questioned certain current
accounting practices of the electric utility industry regarding the recognition,
measurement  and  classification of decommissioning costs for nuclear generating
units  in  financial  statements.  In response to these questions, the Financial
Accounting  Standards  Board had agreed to review the accounting for closure and
removal  costs,  including  decommissioning.  We  do not believe that changes in
such  accounting,  if  required,  would have an adverse effect on the results of
operations  due  to  our  current  and future ability to recover decommissioning
costs  through  rates.

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.
                                       36
<PAGE>




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                                         38
    FOR  THE  YEARS  ENDED  DECEMBER  31,  1999,  1998,  AND  1997

CONSOLIDATED  STATEMENTS  OF  CASH  FLOWS FOR THE                             39
    YEARS  ENDED  DECEMBER  31,  1999,  1998  AND  1997

CONSOLIDATED  BALANCE  SHEETS  AS  OF                                         40
    DECEMBER  31,  1999  AND  1998

CONSOLIDATED  CAPITALIZATION  DATA  AS  OF                                    42
    DECEMBER  31,  1999  AND  1998

NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS                                43

QUARTERLY  FINANCIAL  INFORMATION                                             63

REPORT  OF  INDEPENDENT  PUBLIC  ACCOUNTANTS                                  64

SCHEDULES

FOR  THE  YEARS  ENDED  DECEMBER  31,  1999,  1998  AND  1997:

    II  VALUATION  AND  QUALIFYING  ACCOUNTS  AND RESERVES                    65

             ALL  OTHER  SCHEDULES  ARE  OMITTED  AS  THEY  ARE  EITHER
             NOT  REQUIRED,  NOT  APPLICABLE  OR  THE  INFORMATION  IS
             OTHERWISE  PROVIDED.

CONSENT  AND  REPORT  OF  INDEPENDENT  PUBLIC  ACCOUNTANTS

             ARTHUR  ANDERSEN  LLP                                            66
                                       37
<PAGE>

<TABLE>
<CAPTION>


GREEN  MOUNTAIN  POWER  CORPORATION
CONSOLIDATED  COMPARATIVE  INCOME  STATEMENTS


                                                                     FOR THE YEARS ENDED
                                                                        DECEMBER 31,
                                                                    ---------------------
                                                                            1999             1998       1997
                                                                    ---------------------  ---------  ---------
<S>                                                                 <C>                    <C>        <C>
              (In thousands, except per share data)
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . .  $            251,048   $184,304   $179,323
                                                                    ---------------------  ---------  ---------
OPERATING EXPENSES
  Power Supply
    Vermont Yankee Nuclear Power Corporation . . . . . . . . . . .                34,987     32,910     32,817
    Company-owned generation . . . . . . . . . . . . . . . . . . .                 5,582      6,412      5,327
    Purchases from others. . . . . . . . . . . . . . . . . . . . .               142,699     81,706     62,222
  Other operating. . . . . . . . . . . . . . . . . . . . . . . . .                17,582     21,291     16,780
  Transmission . . . . . . . . . . . . . . . . . . . . . . . . . .                10,800      9,389     11,122
  Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . .                 6,728      5,190      4,785
  Depreciation and amortization. . . . . . . . . . . . . . . . . .                16,187     16,059     16,359
  Taxes other than income. . . . . . . . . . . . . . . . . . . . .                 7,295      7,242      7,205
  Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . .                 1,242     (1,367)     7,191
                                                                    ---------------------  ---------  ---------
    Total operating expenses . . . . . . . . . . . . . . . . . . .               243,102    178,832    163,808
                                                                    ---------------------  ---------  ---------
      OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . .                 7,946      5,472     15,515
                                                                    ---------------------  ---------  ---------

OTHER INCOME
  Equity in earnings of affiliates and non-utility operations. . .                 2,919      2,058        285
  Allowance for equity funds used during construction. . . . . . .                   134        104        357
  Other income (deductions), net . . . . . . . . . . . . . . . . .                   400       (549)       789
                                                                    ---------------------  ---------  ---------
    Total other income (deductions). . . . . . . . . . . . . . . .                 3,453      1,613      1,431
                                                                    ---------------------  ---------  ---------
      INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . .                11,399      7,085     16,946
                                                                    ---------------------  ---------  ---------
INTEREST CHARGES
  Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . .                 6,716      6,991      7,274
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .                   558      1,016        691
  Allowance for borrowed funds used during construction. . . . . .                   (91)      (131)      (315)
                                                                    ---------------------  ---------  ---------
    Total interest charges . . . . . . . . . . . . . . . . . . . .                 7,183      7,876      7,650
                                                                    ---------------------  ---------  ---------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND
  DISCONTINUED OPERATIONS. . . . . . . . . . . . . . . . . . . . .                 4,216       (791)     9,296
Dividends on preferred stock . . . . . . . . . . . . . . . . . . .                 1,155      1,296      1,433
                                                                    ---------------------  ---------  ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS . . . . . . . . . . . . .                 3,061     (2,087)     7,863
Net income(loss) from discontinued segment
  operations . . . . . . . . . . . . . . . . . . . . . . . . . . .                  (603)    (2,086)       142
Loss on disposal, including provisions for
    operating losses during phaseout period. . . . . . . . . . . .                (6,676)         -          -
                                                                    ---------------------  ---------  ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . . . .  $             (4,218)  $ (4,173)  $  8,005
                                                                    =====================  =========  =========
COMMON STOCK DATA
Basic and diluted earnings per share from discontinued operations.  $              (1.36)  $  (0.40)  $   0.03
Basic and diluted earnings per share from continuing operations. .                  0.57      (0.40)      1.54
Basic and diluted earnings per share . . . . . . . . . . . . . . .                 (0.79)     (0.80)      1.57
Cash dividends declared per share. . . . . . . . . . . . . . . . .                  0.55       0.96       1.61
Weighted average shares outstanding. . . . . . . . . . . . . . . .                 5,361      5,243      5,112
</TABLE>


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

                                       38
<PAGE>

<TABLE>
<CAPTION>

                  CONSOLIDATED  STATEMENTS  OF  CASH  FLOWS
                    GREEN  MOUNTAIN  POWER  CORPORATION


                                                                For the Years Ended December 31,
                                                                                           1999        1998       1997
                                                               ----------------------------------  ---------  ---------
<S>                                                            <C>                                 <C>        <C>
                                                                                                  (In thousands)
  OPERATING ACTIVITIES:
  Net Income (Loss) . . . . . . . . . . . . . . . . . . . . .  $                          (4,218)  $ (4,173)  $  8,005
  Adjustments to reconcile net income to net cash
    provided by operating activities:
      Depreciation and amortization . . . . . . . . . . . . .                             16,187     16,059     16,359
      Dividends from associated companies less equity income.                                169        812        (90)
      Allowance for funds used during construction. . . . . .                               (224)      (235)      (672)
      Amortization of purchased power costs . . . . . . . . .                              5,725      6,405      5,212
      Deferred income taxes . . . . . . . . . . . . . . . . .                              1,812       (112)    (2,715)
      Provision for loss on segment disposal. . . . . . . . .                              6,676          -          -
      Deferred purchased power costs. . . . . . . . . . . . .                             (6,590)    (7,830)      (331)
      Deferred arbitration costs. . . . . . . . . . . . . . .                             (1,684)         -          -
      Amortization of investment tax credits. . . . . . . . .                               (282)      (282)      (282)
      Environmental proceedings costs . . . . . . . . . . . .                             (6,105)     3,010     (2,123)
      Conservation expenditures . . . . . . . . . . . . . . .                             (1,943)    (1,833)    (2,411)
      Changes in:
        Accounts receivable . . . . . . . . . . . . . . . . .                                474     (1,611)       368
        Accrued utility revenues. . . . . . . . . . . . . . .                               (358)      (105)       156
        Fuel, materials and supplies. . . . . . . . . . . . .                               (150)       122        359
        Prepayments and other current assets. . . . . . . . .                              4,009       (983)    (6,749)
        Accounts payable. . . . . . . . . . . . . . . . . . .                                665     (1,893)     1,728
        Taxes accrued . . . . . . . . . . . . . . . . . . . .                             (1,611)    (2,473)     1,856
        Interest accrued. . . . . . . . . . . . . . . . . . .                                (34)      (108)       (71)
        Other current liabilities . . . . . . . . . . . . . .                              1,722      3,229       (164)
      Other . . . . . . . . . . . . . . . . . . . . . . . . .                                865      1,940      7,663
                                                               ----------------------------------  ---------  ---------
    Net cash provided by continuing operations. . . . . . . .                             15,105      9,939     26,098
    Net cash provided (used) by discontinued segment. . . . .                               (138)         -          -
                                                               ----------------------------------  ---------  ---------
    Net cash provided by operating activities . . . . . . . .                             14,967      9,939     26,098

  INVESTING ACTIVITIES:
  Construction expenditures . . . . . . . . . . . . . . . . .                             (9,174)   (10,900)   (16,409)
  Investment in nonutility property . . . . . . . . . . . . .                               (190)    (1,442)       218
  Proceeds from sale of propane subsidiary. . . . . . . . . .                                  -     11,500          -
                                                               ----------------------------------  ---------  ---------
    Net cash provided by (used in) investing activities . . .                             (9,364)      (842)   (16,191)
                                                               ----------------------------------  ---------  ---------

  FINANCING ACTIVITIES:
  Issuance of common stock. . . . . . . . . . . . . . . . . .                              1,054      1,587      3,428
  Short-term debt, net. . . . . . . . . . . . . . . . . . . .                                900      4,384      1,600
  Cash dividends. . . . . . . . . . . . . . . . . . . . . . .                             (4,101)    (6,332)    (9,637)
  Reduction in preferred stock. . . . . . . . . . . . . . . .                             (1,650)    (1,650)    (1,575)
  Reduction in long-term debt . . . . . . . . . . . . . . . .                             (1,700)    (6,767)    (4,201)
                                                               ----------------------------------  ---------  ---------

    Net cash provided by (used in) financing activities . . .                             (5,497)    (8,778)   (10,385)
                                                               ----------------------------------  ---------  ---------
  Net increase in cash and cash equivalents . . . . . . . . .                                106        319       (478)

  Cash and cash equivalents at beginning of period. . . . . .                                590        271        749
                                                               ----------------------------------  ---------  ---------

  Cash and cash equivalents at end of period. . . . . . . . .  $                             696   $    590   $    271
                                                               ==================================  =========  =========

  SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
  Cash paid year-to-date for:
    Interest (net of amounts capitalized) . . . . . . . . . .  $                           7,034   $  7,857   $  7,800
    Income taxes, net . . . . . . . . . . . . . . . . . . . .                                997      2,285      5,853
</TABLE>



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

                                       39
<PAGE>

<TABLE>
<CAPTION>

CONSOLIDATED  BALANCE  SHEETS
GREEN  MOUNTAIN  POWER  CORPORATION


                                                   DECEMBER 31
                                                   ------------
                                                       1999        1998
                                                   ------------  --------
<S>                                                <C>           <C>
            (In thousands)
ASSETS
UTILITY PLANT
  Utility plant, at original cost . . . . . . . .  $    283,917  $276,853
  Less accumulated depreciation . . . . . . . . .       102,854    94,604
                                                   ------------  --------
    Net utility plant . . . . . . . . . . . . . .       181,063   182,249
  Property under capital lease. . . . . . . . . .         7,038     7,696
  Construction work in progress . . . . . . . . .         4,795     5,611
                                                   ------------  --------
      Total utility plant, net. . . . . . . . . .       192,896   195,556
                                                   ------------  --------
OTHER INVESTMENTS
  Associated companies, at equity . . . . . . . .        14,545    15,048
  Other investments . . . . . . . . . . . . . . .         6,120     5,630
                                                   ------------  --------
      Total other investments . . . . . . . . . .        20,665    20,678
                                                   ------------  --------
CURRENT ASSETS
  Cash and cash equivalents . . . . . . . . . . .           656       439
  Accounts receivable, customers and others,
    less allowance for doubtful accounts
    of $398 and $449. . . . . . . . . . . . . . .        18,503    18,977
  Accrued utility revenues. . . . . . . . . . . .         6,969     6,611
  Fuel, materials and supplies, at average cost .         3,290     3,139
  Prepayments . . . . . . . . . . . . . . . . . .         3,438     6,091
  Other . . . . . . . . . . . . . . . . . . . . .           382       443
                                                   ------------  --------
      Total current assets. . . . . . . . . . . .        33,238    35,700
                                                   ------------  --------
DEFERRED CHARGES
  Demand side management programs . . . . . . . .         7,640    10,590
  Purchased power costs . . . . . . . . . . . . .         7,435     5,708
  Pine Street Barge Canal . . . . . . . . . . . .         8,700     5,000
  Other . . . . . . . . . . . . . . . . . . . . .        18,078    14,278
                                                   ------------  --------
      Total deferred charges. . . . . . . . . . .        41,853    35,576
                                                   ------------  --------

NON-UTILITY
  Cash and cash equivalents . . . . . . . . . . .            40       151
  Other current assets. . . . . . . . . . . . . .             8     3,409
  Property and equipment. . . . . . . . . . . . .           253     1,213
  Intangible assets . . . . . . . . . . . . . . .             -     1,658
  Equity investment in energy related businesses.             -    12,357
  Business segment held for disposal. . . . . . .         9,477         -
  Other assets. . . . . . . . . . . . . . . . . .         1,321     8,526
                                                   ------------  --------
      Total non-utility assets. . . . . . . . . .        11,099    27,314
                                                   ------------  --------

TOTAL ASSETS. . . . . . . . . . . . . . . . . . .  $    299,751  $314,824
                                                   ============  ========
</TABLE>

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

                                       40
<PAGE>


<TABLE>
<CAPTION>

CONSOLIDATED  BALANCE  SHEETS
GREEN  MOUNTAIN  POWER  CORPORATION


                                                     DECEMBER 31
                                                        1999         1998
                                                    -------------  ---------
<S>                                                 <C>            <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
  Common stock equity
    Common stock, $3.33 1/3 par value,
      authorized 10,000,000 shares (issued
      5,425,571 and 5,313,296) . . . . . . . . . .  $     18,085   $ 17,711
    Additional paid-in capital . . . . . . . . . .        72,594     71,914
    Retained earnings. . . . . . . . . . . . . . .        10,344     17,508
    Treasury stock, at cost (15,856 shares). . . .          (378)      (378)
                                                    -------------  ---------
      Total common stock equity. . . . . . . . . .       100,645    106,755
  Redeemable cumulative preferred stock. . . . . .        12,795     14,435
  Long-term debt, less current maturities. . . . .        81,800     88,500
                                                    -------------  ---------
      Total capitalization . . . . . . . . . . . .       195,240    209,690
                                                    -------------  ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . .         7,038      7,696
                                                    -------------  ---------
CURRENT LIABILITIES
  Current maturities of preferred stock. . . . . .         1,640      1,650
  Current maturities of long-term debt . . . . . .         6,700      1,700
  Short-term debt. . . . . . . . . . . . . . . . .         7,900      7,000
  Accounts payable, trade and accrued liabilities.         6,684      5,453
  Accounts payable to associated companies . . . .         6,577      7,143
  Dividends declared . . . . . . . . . . . . . . .           285        362
  Customer deposits. . . . . . . . . . . . . . . .           361        336
  Taxes accrued. . . . . . . . . . . . . . . . . .             -        370
  Interest accrued . . . . . . . . . . . . . . . .         1,169      1,203
  Other. . . . . . . . . . . . . . . . . . . . . .         7,032      5,258
                                                    -------------  ---------
      Total current liabilities. . . . . . . . . .        38,348     30,475
                                                    -------------  ---------
DEFERRED CREDITS
  Accumulated deferred income taxes. . . . . . . .        25,201     23,389
  Unamortized investment tax credits . . . . . . .         3,978      4,260
  Pine Street Barge Canal site cleanup . . . . . .         8,815     11,220
  Other. . . . . . . . . . . . . . . . . . . . . .        21,132     21,020
                                                    -------------  ---------
      Total deferred credits . . . . . . . . . . .        59,126     59,889
                                                    -------------  ---------
COMMITMENTS AND CONTINGENCIES

NON-UTILITY
  Current liabilities. . . . . . . . . . . . . . .             -        720
  Other liabilities. . . . . . . . . . . . . . . .             -      6,354
                                                    -------------  ---------
      Total non-utility liabilities. . . . . . . .             -      7,074
                                                    -------------  ---------

TOTAL CAPITALIZATION AND LIABILITIES . . . . . . .  $    299,752   $314,824
                                                    =============  =========
</TABLE>

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

                                       41
<PAGE>

<TABLE>
<CAPTION>

CONSOLIDATED  CAPITALIZATION  DATA
GREEN  MOUNTAIN  POWER  CORPORATION  At  December  31,

                                                            ISSUED
                                                       AND OUTSTANDING
                                         AUTHORIZED     1999     1998       1999      1998
---------------------------------  ----------------  ---------  ---------  -------
<S>                                <C>               <C>        <C>        <C>      <C>
CAPITAL STOCK . . . . . . . . . .                                          (In thousands)
Common Stock, $3.33 1/3 par value        10,000,000  5,425,571  5,313,296  $18,085  $17,711
                                                                           =======  =======
</TABLE>
<TABLE>
<CAPTION>


                                                            SHARES
                                                          -----------
                                                                                                OUTSTANDING
                                                    AUTHORIZED    ISSUED     1999     1998     1999     1998
                                                   -----------  --------  --------  -------  -------  -------
<S>                                                       <C>       <C>       <C>      <C>      <C>      <C>
                                                                                              (In thousands)
REDEEMABLE CUMULATIVE PREFERRED STOCK,
  $100 PAR VALUE
    4.75%, Class B, redeemable at
      $101 per share                                    15,000    15,000    1,800    2,250  $   180  $   225
    7%, Class C, redeemable at
      $101 per share                                    15,000    15,000    3,750    4,200      375      420
    9.375%, Class D, Series 1,
      redeemable at $101 per share                      40,000    40,000    4,800    6,400      480      640
    8.625%, Class D, Series 3,
      redeemable at $100916 per share                   70,000    70,000   14,000   28,000    1,400    2,800
    7.32%, Class E, Series 1                           200,000   120,000  120,000  120,000   12,000   12,000
                                                                                            -------  -------
TOTAL PREFERRED STOCK                                                                      $ 14,435  $ 16,085
                                                                                            ========  ========
</TABLE>
<TABLE>
<CAPTION>



                                                                        1999         1998
                                                                   ---------------  -------
<S>                                                                <C>              <C>
LONG-TERM DEBT. . . . . . . . . . . . . . . . . . . . . . . . . .   (In thousands)
FIRST MORTGAGE BONDS
  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.            8,500   10,200
  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. . . . . . . . . . . . . . . . .           88,500   90,200
  Less Current Maturities (due within one year) . . . . . . . . .            6,700    1,700
                                                                   ---------------  -------
TOTAL LONG-TERM DEBT, NET . . . . . . . . . . . . . . . . . . . .  $        81,800  $88,500
                                                                   ===============  =======
</TABLE>


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

                                       42
<PAGE>

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 VERMONT'S POPULATION.  THE MOST SIGNIFICANT PORTION
OF  THE  COMPANY'S  NET  INCOME IS GENERATED FROM ITS REGULATED ELECTRIC UTILITY
OPERATION,  WHICH  PURCHASES  AND GENERATES ELECTRIC POWER AND DISTRIBUTES IT TO
APPROXIMATELY  84,000 RETAIL AND WHOLESALE CUSTOMERS.  AT DECEMBER 31, 1999, THE
COMPANY'S  PRIMARY  SUBSIDIARY  INVESTMENT WAS MOUNTAIN ENERGY INC. (MEI), WHICH
HAS  INVESTED  IN  ENERGY GENERATION, ENERGY EFFICIENCY AND WASTEWATER TREATMENT
PROJECTS  ACROSS  THE  UNITED  STATES.  ON JUNE 30, 1999, THE COMPANY DECIDED TO
SELL  OR  DISPOSE  OF THE ASSETS OF MEI, AND REPORT ITS RESULTS AS INCOME (LOSS)
FROM  OPERATIONS  OF A DISCONTINUED SEGMENT. IN 1998 THE COMPANY SOLD THE ASSETS
OF  ITS WHOLLY OWNED SUBSIDIARY, GREEN MOUNTAIN PROPANE GAS COMPANY (GMPG).  THE
COMPANY'S  REMAINING  WHOLLY-OWNED  SUBSIDIARIES (WHICH ARE NOT REGULATED BY THE
VERMONT PUBLIC SERVICE BOARD (VPSB)), ARE GREEN MOUNTAIN RESOURCES, INC. (GMRI),
WHICH  WAS  CREATED TO PARTICIPATE IN THE EMERGING RETAIL ENERGY MARKET, AND GMP
REAL ESTATE CORPORATION AND LEASE-ELEC, INC.  THE RESULTS OF THESE SUBSIDIARIES,
EXCLUDING  MEI,  AND  THE  COMPANY'S UNREGULATED RENTAL WATER HEATER PROGRAM ARE
INCLUDED  IN  EARNINGS  OF  AFFILIATES  AND  NON-UTILITY OPERATIONS IN THE OTHER
INCOME  SECTION  OF THE CONSOLIDATED STATEMENTS OF INCOME.  SUMMARIZED FINANCIAL
INFORMATION  FOR  THESE  SUBSIDIARIES  IS  AS  FOLLOWS:

<TABLE>
<CAPTION>


                                    For the years ended December 31,
                                               1999    1998    1997
                  ---------------------------------  ------  ------
<S>                                           <C>    <C>     <C>
                                                   (In thousands)
Revenue. . . . .  $                           1,286  $2,876  $7,497
Expense. . . . .                                184   2,857   6,849
                  ---------------------------------  ------  ------
Net Income . . .  $                           1,102  $   19  $  648
                  =================================  ======  ======
</TABLE>

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  USING  THE  EQUITY  METHOD  OF
ACCOUNTING.  THE  COMPANY'S  SHARE  OF  THE  NET  EARNINGS  OR  LOSSES  OF THESE
COMPANIES  IS  ALSO  INCLUDED  IN  THE  OTHER INCOME SECTION OF THE CONSOLIDATED
STATEMENTS  OF  INCOME.  SEE  NOTE  B  AND  NOTE  L  FOR ADDITIONAL INFORMATION.

     2.  BASIS  OF  PRESENTATION.  THE  COMPANY'S  UTILITY OPERATIONS, INCLUDING
ACCOUNTING  RECORDS,  RATES,  OPERATIONS  AND  CERTAIN  OTHER  PRACTICES  OF ITS
ELECTRIC  UTILITY  BUSINESS,  ARE  SUBJECT  TO  THE  REGULATORY AUTHORITY OF THE
FEDERAL  ENERGY  REGULATORY  COMMISSION  (FERC)  AND  THE  VPSB.
          THE  ACCOMPANYING  CONSOLIDATED  FINANCIAL  STATEMENTS  CONFORM  TO
GENERALLY  ACCEPTED  ACCOUNTING  PRINCIPLES  APPLICABLE  TO  RATE-REGULATED
ENTERPRISES  IN  ACCORDANCE  WITH  STATEMENT  OF  FINANCIAL ACCOUNTING STANDARDS
NUMBER  71,  (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 SPECIFIC COSTS, AND (2) A CHANGE IN THE MANNER IN WHICH RATES ARE SET
BY  REGULATORS FROM COST-BASED REGULATION TO ANOTHER FORM OF REGULATION.  IN THE
EVENT  THAT  THE COMPANY NO LONGER MEETS THE CRITERIA UNDER SFAS 71, THE COMPANY
WOULD  BE  REQUIRED TO WRITE OFF RELATED REGULATORY ASSETS AND LIABILITIES.  THE
COMPANY  CONTINUES  TO  BELIEVE, BASED ON CURRENT REGULATORY CIRCUMSTANCES, THAT
THE  USE OF REGULATORY ACCOUNTING UNDER SFAS 71 REMAINS APPROPRIATE AND THAT ITS
REGULATORY  ASSETS  ARE  PROBABLE  OF  RECOVERY.
          THE  COMPANY  IS  REQUIRED  TO  EVALUATE  LONG-LIVED ASSETS, INCLUDING
REGULATORY ASSETS, FOR POTENTIAL IMPAIRMENT.  ASSETS THAT ARE NO LONGER PROBABLE
OF  RECOVERY  THROUGH  FUTURE  REVENUES WOULD BE REVALUED BASED UPON FUTURE CASH
FLOWS.  REGULATORY ASSETS ARE CHARGED TO EXPENSE IN THE PERIOD IN WHICH THEY ARE
NO  LONGER PROBABLE OF FUTURE RECOVERY.  AS OF DECEMBER 31, 1999, BASED UPON THE
REGULATORY  ENVIRONMENT WITHIN WHICH THE COMPANY CURRENTLY OPERATES, THE COMPANY
DOES  NOT  BELIEVE  THAT  AN  IMPAIRMENT  LOSS  NEED  BE  RECORDED.  COMPETITIVE
INFLUENCES  OR  REGULATORY  DEVELOPMENTS  MAY  IMPACT THIS STATUS IN THE FUTURE.
                                       43
<PAGE>

          IN  JUNE  1998,  THE  FINANCIAL  ACCOUNTING  STANDARDS  BOARD  ISSUED
STATEMENT  OF  FINANCIAL  ACCOUNTING STANDARDS NUMBER 133 (SFAS 133), ACCOUNTING
FOR  DERIVATIVE  INSTRUMENTS  AND  HEDGING  ACTIVITIES.  SFAS  133  ESTABLISHES
ACCOUNTING  AND  REPORTING  STANDARDS  REQUIRING  THAT  DERIVATIVE  INSTRUMENTS
(INCLUDING  CERTAIN  DERIVATIVE  INSTRUMENTS  EMBEDDED  IN  OTHER  CONTRACTS) BE
RECORDED  IN THE BALANCE SHEET AS EITHER AN ASSET OR A LIABILITY AND 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  FORMALLY  DOCUMENT,  DESIGNATE,  AND ASSESS THE
EFFECTIVENESS  OF  TRANSACTIONS  THAT  RECEIVE  HEDGE  ACCOUNTING.   SFAS 133 IS
EFFECTIVE  FOR  THE  COMPANY  BEGINNING  THE  FIRST  QUARTER OF 2001 AND MUST BE
APPLIED  TO  DERIVATIVE  INSTRUMENTS  AND EMBEDDED DERIVATIVES THAT WERE ISSUED,
ACQUIRED,  OR  SUBSTANTIVELY  MODIFIED ON OR AFTER JANUARY 1, 1998 OR JANUARY 1,
1999  (AS  ELECTED  BY  THE  COMPANY).
          THE COMPANY HAS A CONTRACT WITH MORGAN STANLEY TO HEDGE THE FAIR VALUE
OF  FOSSIL  FUEL  PRICES.  WE  ALSO  SOMETIMES  USE  FUTURE  CONTRACTS  TO HEDGE
FORECASTED  WHOLESALE  SALES  OF  ELECTRIC  POWER,  INCLUDING  MATERIAL  SALES
COMMITMENTS  AS  DISCUSSED  UNDER  NOTE  K.  UNDER  SFAS  133, THE COMPANY WOULD
RECOGNIZE  IN EARNINGS THE VALUE OF THESE HEDGING INSTRUMENTS TO THE EXTENT THAT
THEY  ARE  INEFFECTIVE  IN  HEDGING  EXPOSURES  RELATED  TO  THESE  CONTRACTS.
          THE COMPANY HAS NOT YET QUANTIFIED THE IMPACTS OF ADOPTING SFAS 133 ON
ITS  FINANCIAL  STATEMENTS AND HAS NOT DETERMINED THE TIMING OF OR THE METHOD OF
ADOPTION  OF  SFAS  133.  HOWEVER,  IT  IS POSSIBLE THAT SFAS 133 COULD INCREASE
VOLATILITY  IN  EARNINGS  AND  OTHER  COMPREHENSIVE  INCOME.

     3.  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 IMPROVEMENTS 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  OVER  THE  ESTIMATED  SERVICE  LIFE  OF  THE  UNITS.

     4.  DEPRECIATION.  THE  COMPANY  PROVIDES  FOR  DEPRECIATION  USING  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 3.3 PERCENT OF
TOTAL  DEPRECIABLE  PROPERTY  AT  THE  BEGINNING OF 1999, AND 3.4 PERCENT AT THE
BEGINNING  OF  1998  AND  3.2  PERCENT  AT  THE  BEGINNING  OF  1997.

     5. CASH AND CASH EQUIVALENTS.  CASH AND CASH EQUIVALENTS INCLUDE SHORT-TERM
INVESTMENTS  WITH  MATURITIES  LESS  THAN  NINETY  DAYS.

     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 ALSO DEFERS AND
AMORTIZES  COSTS  ASSOCIATED  WITH  ITS INVESTMENT IN THE DEMAND SIDE MANAGEMENT
PROGRAM.
          AT  DECEMBER  31,  1999, OTHER DEFERRED CHARGES TOTALED $18.1 MILLION,
CONSISTING  OF  REGULATORY  PROCEEDINGS  EXPENSES, REGULATORY DEFERRALS OF STORM
DAMAGES,  RIGHTS-OF-WAY MAINTENANCE, OTHER EMPLOYEE BENEFITS, PRELIMINARY SURVEY
AND  INVESTIGATION  CHARGES,  TRANSMISSION  INTERCONNECTION  CHARGES AND VARIOUS
OTHER  PROJECTS  AND  DEFERRALS.
                                       44
<PAGE>


     8.  EARNINGS  PER  SHARE.  EARNINGS  PER  SHARE  ARE  BASED ON THE WEIGHTED
AVERAGE  NUMBER  OF  SHARES OF COMMON STOCK OUTSTANDING DURING EACH YEAR.  SINCE
THE  COMPANY  HAS  NOT  ISSUED  ANY  POTENTIALLY  DILUTIVE SECURITIES, BASIC AND
DILUTED  EARNINGS  PER  SHARE  ARE  THE  SAME.

     9.  MAJOR  CUSTOMERS.  THE  COMPANY  HAD  ONE  MAJOR  RETAIL CUSTOMER, IBM,
METERED  AT  TWO  LOCATIONS,  THAT ACCOUNTED FOR 11.8 PERCENT, 14.7 PERCENT, AND
14.0  PERCENT OF OPERATING REVENUES IN 1999, 1998 AND 1997, RESPECTIVELY.  IBM'S
PERCENT  OF  REVENUES  IN  1999  DECREASED DUE TO AN INCREASE IN TOTAL OPERATING
REVENUES  CAUSED  BY  SALES FOR RESALE PURSUANT TO THE MORGAN STANLEY AGREEMENT.
SEE  NOTE  K  FOR  FURTHER  INFORMATION  REGARDING THE MORGAN STANLEY AGREEMENT.


     10.  FAIR  VALUE OF FINANCIAL INSTRUMENTS.   THE PRESENT VALUE OF THE FIRST
MORTGAGE  BONDS  AND PREFERRED STOCK OUTSTANDING, IF REFINANCED USING PREVAILING
MARKET  RATES  OF  INTEREST,  WOULD  DECREASE  FROM  THE BALANCES OUTSTANDING AT
DECEMBER  31,  1999  BY  APPROXIMATELY  5.0  PERCENT.  IN  THE  EVENT  OF SUCH A
REFINANCING,  THERE  WOULD  BE  NO  GAIN  OR  LOSS,  BECAUSE  UNDER  ESTABLISHED
REGULATORY  PRECEDENT,  ANY SUCH DIFFERENCE WOULD BE REFLECTED IN RATES AND HAVE
NO  EFFECT  UPON  INCOME.

     11. DEFERRED CREDITS.  AT DECEMBER 31, 1999, THE COMPANY HAD OTHER DEFERRED
CREDITS  AND  LONG-TERM LIABILITIES OF $30.4 MILLION, CONSISTING OF RESERVES FOR
DAMAGE CLAIMS AND ENVIRONMENTAL LIABILITIES, AND ACCRUALS FOR EMPLOYEE BENEFITS.

     12.  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.

     13.  RECLASSIFICATION.  CERTAIN  ITEMS  ON  THE  PRIOR  YEAR'S CONSOLIDATED
FINANCIAL  STATEMENTS  HAVE  BEEN RECLASSIFIED TO BE CONSISTENT WITH THE CURRENT
YEAR  PRESENTATION.

B.  INVESTMENTS  IN  ASSOCIATED  COMPANIES
THE  COMPANY  ACCOUNTS  FOR INVESTMENTS IN THE FOLLOWING COMPANIES BY THE EQUITY
METHOD:

<TABLE>
<CAPTION>


                                                PERCENT        INVESTMENT IN EQUITY
                                              OWNERSHIP AT          DECEMBER 31
                                            DECEMBER 31,1999           1999            1998
                                           ------------------  ---------------------  ------
<S>                                        <C>                 <C>                    <C>
                                                                           (In thousands)
VELCO-common. . . . . . . . . . . . . . .              29.50%  $               1,839  $1,828
VELCO-preferred . . . . . . . . . . . . .              30.00%                    690     829
                                                               ---------------------  ------
Total VELCO . . . . . . . . . . . . . . .                                      2,529   2,657

Vermont Yankee- Common. . . . . . . . . .              17.90%                  9,641   9,759
New England Hydro Transmission-Common . .               3.18%                    911   1,016
New England Hydro Transmission Electric-
    Common. . . . . . . . . . . . . . . .               3.18%                  1,464   1,616
                                                               ---------------------  ------
Total investment in associated companies.                          $          14,545 $15,048
                                                                   =========================
</TABLE>
     UNDISTRIBUTED EARNINGS IN ASSOCIATED COMPANIES TOTALED $530,000 AT DECEMBER
31,  1999.

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, VELCO BILLS ALL COSTS, INCLUDING INTEREST ON DEBT AND A FIXED RETURN
ON  EQUITY,  TO  THE  STATE  AND  OTHERS USING VELCO'S TRANSMISSION SYSTEM.  THE
COMPANY'S PURCHASES OF TRANSMISSION SERVICES FROM VELCO WERE $7.9 MILLION,  $7.1
MILLION,  AND  $7.6  MILLION  FOR  THE  YEARS 1999, 1998 AND 1997, RESPECTIVELY.

                                       45
<PAGE>

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.

<TABLE>
<CAPTION>

Summarized  financial  information  for  VELCO  is  as  follows:

                                 AT AND FOR THE YEARS ENDED
                                        DECEMBER 31,
                                            1999               1998     1997
                                 ---------------------------  -------  -------
<S>                              <C>                          <C>      <C>
                                                            (In thousands)
Company's equity in net income.  $                       357  $   338  $   354
                                 ===========================  =======  =======
Total assets. . . . . . . . . .                       67,294   67,658   70,566
Less:
Liabilities and long-term debt.                       58,731   58,690   61,162
                                 ---------------------------  -------  -------
Net assets. . . . . . . . . . .                        8,563    8,968    9,404
                                 ===========================  =======  =======

Company's equity in net assets.  $                     2,529  $ 2,657  $ 2,794
                                 ===========================  =======  =======
</TABLE>
 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  $430
MILLION,  OF  WHICH  $247  MILLION  HAS  BEEN FUNDED.  AT DECEMBER 31, 1999, THE
COMPANY'S  PORTION  OF  THE  NET  UNFUNDED  LIABILITY  WAS $33 MILLION, WHICH IT
EXPECTS  WILL  BE  RECOVERED  THROUGH  RATES  OVER  VERMONT  YANKEE'S  REMAINING
OPERATING  LIFE.  AS  A SPONSOR OF VERMONT YANKEE, THE COMPANY ALSO IS OBLIGATED
TO  PROVIDE  20 PERCENT OF CAPITAL REQUIREMENTS NOT OBTAINED BY OUTSIDE SOURCES.
DURING  1999,  THE  COMPANY  INCURRED  $33.6  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, 1999 WAS
$17.4  MILLION.
          ON  OCTOBER  15,  1999,  THE  OWNERS  OF  VERMONT YANKEE NUCLEAR POWER
CORPORATION  ACCEPTED  A  BID FROM AMERGEN ENERGY COMPANY FOR THE VERMONT YANKEE
GENERATING  PLANT.  THE  ASSET  SALE WILL REQUIRE NUMEROUS REGULATORY APPROVALS,
INCLUDING  THE  FEDERAL  ENERGY  REGULATORY  COMMISSION,  THE NUCLEAR REGULATORY
COMMISSION,  THE  SECURITIES  AND EXCHANGE COMMISSION AND THE VPSB.   ASSUMING A
FINAL CLOSING DATE FOR THE TRANSACTION OF JULY 1, 2000, AMERGEN WILL PAY VERMONT
YANKEE  APPROXIMATELY  $23.5  MILLION  FOR  THE  PLANT  AND  PROPERTY.
          AS  A CONDITION OF THE SALE, VERMONT YANKEE'S CURRENT OWNERS WILL MAKE
A  ONE-TIME  AND  FINAL  PAYMENT  OF  $54.3  MILLION  TO  PRE-PAY  THE  PLANT'S
DECOMMISSIONING FUND. IN RETURN, AMERGEN WILL ASSUME FULL RESPONSIBILITY FOR ALL
FUTURE  OPERATING  COSTS AND THE OBLIGATION TO DECOMMISSION THE PLANT AT THE END
OF  ITS  LIFE.  THE  COMPANY  HAS AGREED TO BUY POWER FROM THE PLANT FOR PERIODS
THAT  MAY  EXTEND  UP TO TWELVE YEARS.  THE COMPANY AND THE OTHER CURRENT OWNERS
ARE  ALSO RESPONSIBLE TO VERMONT YANKEE FOR THEIR SHARE OF THE UNRECOVERED PLANT
AND  OTHER  COSTS  RESULTING  FROM  THE  SALE.
          THE  PRICE-ANDERSON  ACT CURRENTLY SETS PUBLIC LIABILITY FROM A SINGLE
INCIDENT  AT  A  NUCLEAR  POWER  PLANT TO $9.5 BILLION.  ANY DAMAGES BEYOND $9.5
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
$9.3  BILLION  PER  INCIDENT BY ASSESSING EACH OF THE 106 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 COVERS ALL WORKERS EMPLOYED AT NUCLEAR FACILITIES
FOR  BODILY  INJURY  CLAIMS.  VERMONT  YANKEE RETAINS A POTENTIAL OBLIGATION FOR
RETROSPECTIVE  ADJUSTMENTS  DUE TO PAST OPERATIONS OF SEVERAL SMALLER FACILITIES
THAT  DID  NOT  JOIN THE ABOVE INSURANCE PROGRAM.  THESE EXPOSURES WILL CEASE TO
EXIST  NO  LATER THAN DECEMBER 31, 2007.  VERMONT YANKEE'S MAXIMUM RETROSPECTIVE
OBLIGATION  REMAINS  AT  $3.1  MILLION.     INSURANCE  HAS  BEEN  PURCHASED FROM
NUCLEAR ELECTRIC INSURANCE LIMITED (NEIL) TO COVER THE COSTS OF PROPERTY DAMAGE,
                                       46
<PAGE>

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 $10.7 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.

<TABLE>
<CAPTION>

Summarized  financial  information  for  Vermont  Yankee  is  as  follows:

                                                           At and for the years ended
                                                                  December 31,
                                                     1999                1998      1997
                                          ---------------------------  --------  --------
<S>                                       <C>                          <C>       <C>
                                                                     (In thousands)
Earnings:
  Operating revenues . . . . . . . . . .  $                   208,812  $195,249  $173,106
  Net income applicable to common stock.                        6,471     7,125     6,834
  Company's equity in net income . . . .  $                     1,165  $  1,267  $  1,244
                                          ===========================  ========  ========
Total assets . . . . . . . . . . . . . .  $                   685,292  $635,874  $610,024
Less:
  Liabilities and long-term debt . . . .                      631,365   581,231   555,735
                                          ---------------------------  --------  --------
Net Assets . . . . . . . . . . . . . . .  $                    53,927  $ 54,643  $ 54,289
                                          ===========================  ========  ========
Company's equity in net assets . . . . .  $                     9,641  $  9,759  $  9,701
                                          ===========================  ========  ========
</TABLE>

C.  COMMON  STOCK  EQUITY

          THE  COMPANY MAINTAINS A DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN
(DRIP)  UNDER  WHICH  232,979  SHARES WERE RESERVED AND UNISSUED AT DECEMBER 31,
1999.  THE  COMPANY  ALSO  FUNDS AN EMPLOYEE SAVINGS AND INVESTMENT PLAN (ESIP).
AT  DECEMBER  31, 1999, THERE WERE 38,530 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  PERSONNEL  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 1999, 3,527 SHARES WERE
RETURNED  TO THE COMPANY RESULTING FROM THE TERMINATION OF EMPLOYMENT OF SEVERAL
PARTICIPANTS.  AT  DECEMBER  31,  1999,  THERE  WERE  30,141 SHARES RESERVED AND
UNISSUED  UNDER  THE  COMPENSATION  PROGRAM.

                                       47
<PAGE>

<TABLE>
<CAPTION>

 Changes  in  common  stock  equity  for  the  years  ended  December  31,  1997,  1998  and  1999  are  as  follows:

                                    COMMON STOCK              PAID-IN    RETAINED   TREASURY STOCK              STOCK
                                       SHARES       AMOUNT    CAPITAL    EARNINGS       SHARES       AMOUNT    EQUITY
                                    -------------  --------  ---------  ----------  --------------  --------  ---------
(Dollars in thousands)
<S>                                 <C>            <C>       <C>        <C>         <C>             <C>       <C>
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
Common Stock                                                               (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)
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                                                                                                       -
Common Stock                                                               (5,036)                              (5,036)
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                                                              (878)                                (878)
                                                                        ----------                            ---------
BALANCE, DECEMBER 31, 1998 . . . .     5,313,296    17,711     71,914      17,508           15,856     (378)   106,755
                                    -------------  --------  ---------  ----------  --------------  --------  ---------
Common Stock Issuance:
DRIP . . . . . . . . . . . . . . .        67,525       225        418                                              643
ESIP . . . . . . . . . . . . . . .        48,277       161        345                                              506
Compensation Program:
   Restricted Shares . . . . . . .        (3,527)      (12)       (83)                                             (95)
Net Loss                                                                   (3,063)                              (3,063)
Cash Dividends
Common Stock                                                               (2,946)                              (2,946)
Preferred Stock:$4.75 per share                                               (10)                                 (10)
 7.00 per share                                                               (29)                                 (29)
 9.375 per share                                                              (57)                                 (57)
 8.625 per share                                                             (181)                                (181)
 7.32 per share                                                              (878)                                (878)
                                                                        ----------                            ---------
BALANCE, DECEMBER 31, 1999 . . . .     5,425,571   $18,085   $ 72,594   $  10,344           15,856  $  (378)  $100,645
                                    =============  ========  =========  ==========  ==============  ========  =========
</TABLE>
 DIVIDEND  RESTRICTIONS.  CERTAIN  RESTRICTIONS ON THE PAYMENT OF CASH DIVIDENDS
ON  COMMON STOCK ARE CONTAINED IN THE COMPANY'S INDENTURES RELATING TO LONG-TERM
DEBT AND IN THE RESTATED ARTICLES OF ASSOCIATION.  UNDER THE MOST RESTRICTIVE OF
SUCH  PROVISIONS,  APPROXIMATELY $10.3 MILLION OF RETAINED EARNINGS WERE FREE OF
RESTRICTIONS  AT  DECEMBER  31,  1999.
          THE  PROPERTIES  OF THE COMPANY INCLUDE SEVERAL HYDROELECTRIC PROJECTS
LICENSED UNDER THE FEDERAL POWER ACT, WITH LICENSE EXPIRATION DATES RANGING FROM
2001  TO  2025.  AT  DECEMBER  31,  1999,  $34,000 OF RETAINED EARNINGS HAD BEEN
                                       48
<PAGE>

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  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 THE
YEAR  2000  FOR  CERTAIN  CLASSES  OF  PREFERRED  STOCK  ARE  AS  FOLLOWS:

<TABLE>
<CAPTION>
                              Purchase and Sinking Fund

                                      Shares to
          Class              Due dates   Retire
<C>     <S>                <C>        <C>
8.625%  Class D, Series 3      1-Sep     14,000
4.750%  Class B . . . . .      1-Dec        350
7.000%  Class C . . . . .      1-Dec        450
9.375%  Class D, Series 1      1-Dec      1,600
</TABLE>
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 $1,640,000 FOR 2000, $235,000 EACH FOR
2001  AND  2002,  $75,000  EACH  FOR  2003  AND  2004,  AND $175,000 THEREAFTER.
          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.

E.  LONG-TERM  DEBT

          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  WEIGHTED  AVERAGE RATE ON LONG TERM BORROWINGS OUTSTANDING WAS 7.5
PERCENT  AT  BOTH  DECEMBER  31,  1999  AND  1998.  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:

<TABLE>
<CAPTION>


          Sinking
           FUND        MATURITIES   TOTAL
      ---------------  -----------  ------
<S>   <C>              <C>          <C>
       (In thousands)
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
2004            1,700                1,700
</TABLE>

                                       49
<PAGE>

F.  SHORT-TERM  DEBT

          THE  COMPANY  HAS  A  REVOLVING  CREDIT AGREEMENT IN THE AMOUNT OF $15
MILLION  WITH  TWO  BANKS,  WITH BORROWINGS OUTSTANDING OF $7.9 MILLION AND $7.0
MILLION  AT  DECEMBER  31, 1999, AND 1998 RESPECTIVELY.  THE COMPANY ALSO HAS AN
UNCOMMITTED  LINE  OF  CREDIT  IN THE AMOUNT OF $500,000, UNDER WHICH NO AMOUNTS
WERE  OUTSTANDING AT DECEMBER 31, 1999 OR 1998.    THE WEIGHTED AVERAGE INTEREST
RATE  ON SHORT-TERM BORROWINGS OUTSTANDING AT DECEMBER 31, 1999 AND DECEMBER 31,
1998  WAS  9.0  PERCENT AND 6.2 PERCENT, RESPECTIVELY.  THERE WAS NO NON-UTILITY
SHORT-TERM  DEBT  OUTSTANDING  AT  DECEMBER  31,  1999.
          THE  REVOLVING  CREDIT  AGREEMENT REQUIRES THE COMPANY TO CERTIFY ON A
QUARTERLY  BASIS  THAT  IT  HAS  NOT  SUFFERED  A  "MATERIAL  ADVERSE  CHANGE".
SIMILARLY,  AS  A CONDITION TO FURTHER BORROWINGS, WE MUST CERTIFY THAT NO EVENT
HAS  OCCURRED OR FAILED TO OCCUR THAT HAS HAD OR WOULD REASONABLY BE EXPECTED TO
HAVE  A  MATERIALLY  ADVERSE  EFFECT  ON THE COMPANY SINCE THE DATE THAT WE LAST
BORROWED  UNDER  THIS  AGREEMENT.   THE  CURRENT AGREEMENT ALLOWS THE COMPANY TO
CONTINUE  TO  BORROW  UNTIL  SUCH  TIME  THAT:
*     A  "MATERIAL  ADVERSE  EFFECT"  HAS  OCCURRED;
*     IT  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.

     TERMS  ALSO  CALL  IN  PART  FOR  THE  FOLLOWING:

*     A  SECOND  PRIORITY MORTGAGE, LIEN AND SECURITY INTEREST IN THE COLLATERAL
PLEDGED  UNDER  THE  FIRST  MORTGAGE  BOND  INDENTURE  GRANTED TO THE BANKS; AND
*     THE  TOTAL  AMOUNT  AVAILABLE  WILL  BE  REDUCED  BY THE NET PROCEEDS FROM
CERTAIN  SALES,  SUCH  AS  THE  SALE  OF ASSETS OF THE DISCONTINUED SEGMENT MEI.

     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 A RATE CASE THAT TRIGGERS A "MATERIAL ADVERSE
CHANGE"  FOR  THE  COMPANY;  OR
*     HYDRO-QUEBEC  IS  UNWILLING  TO MAKE NEW ARRANGEMENT REGARDING THE COST OF
OUR  CONTRACT  WITH  THEM.

     IF  WE  ARE  UNABLE  TO  BORROW ON A SHORT-TERM BASIS, WE WILL EVALUATE ALL
POTENTIAL  ALTERNATIVES  AVAILABLE TO US AT THE TIME, INCLUDING, BUT NOT LIMITED
TO,  ELIMINATING  COMMON  STOCK  DIVIDENDS  AND  THE  FILING  OF  A PETITION FOR
REORGANIZATION  UNDER  THE  UNITED  STATES  BANKRUPTCY  CODE.


G.  INCOME  TAXES

     UTILITY.  THE COMPANY ACCOUNTS FOR INCOME TAXES USING THE LIABILITY METHOD.
THIS  METHOD  ACCOUNTS  FOR DEFERRED INCOME TAXES BY APPLYING STATUTORY RATES TO
THE  DIFFERENCES  BETWEEN  THE  BOOK  AND  TAX  BASES OF ASSETS AND LIABILITIES.

          THE REGULATORY TAX ASSETS AND LIABILITIES REPRESENT TAXES THAT WILL BE
COLLECTED  FROM OR RETURNED TO CUSTOMERS THROUGH RATES IN FUTURE PERIODS.  AS OF
DECEMBER  31,  1999  AND  1998,  THE  NET  REGULATORY ASSETS WERE $1,805,000 AND
$2,214,000 RESPECTIVELY, AND INCLUDED IN OTHER DEFERRED CHARGES ON THE COMPANY'S
CONSOLIDATED  BALANCE  SHEETS.

          THE  TEMPORARY  DIFFERENCES  WHICH  GAVE  RISE TO THE NET DEFERRED TAX
LIABILITY  AT  DECEMBER  31,  1999  AND  DECEMBER  31,  1998,  WERE  AS FOLLOWS:

                                       50
<PAGE>

<TABLE>
<CAPTION>


                                                                                       AT DECEMBER 31,
                                                                                            1999           1998
                                                                                      -----------------  --------
<S>                                   <C>                              <C>            <C>                <C>
DEFERRED TAX ASSETS                                                                      (In thousands)
Contributions in aid of construction                                                  $          9,056   $ 8,551
Deferred compensation and                                                                        3,372     4,455
     postretirement benefits
Alternative minimum tax credit                                                                       -       (56)
Self insurance and other reserves                                                                3,664     2,009
Pine Street reserve                                                                                (25)    2,469
Other                                                                                            1,183       995
                                                                                      -----------------  --------
                                                                                      $         17,250   $18,423
                                                                                      -----------------  --------

DEFERRED TAX LIABILITIES
Property related                                                                      $         37,921   $34,806
Demand side management                                                                           2,328     3,557
Deferred purch power costs                                                                       2,202     3,449
                                                                                      -----------------  --------
                                                                                      $         42,451   $41,812
                                                                                      -----------------  --------
                                      Net accumulated deferred income
                                                                       tax liability  $         25,201   $23,389
                                                                                      =================  ========
</TABLE>
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:

<TABLE>
<CAPTION>


                                                                                        YEARS ENDED DECEMBER 31,
                                                                                     1999              1998     1997
                                                                          --------------------------  ------  --------
<S>                                    <C>                                <C>                         <C>     <C>
                                                                                                  (In thousands)
Net change in deferred income tax                                         $                    1,812  $(112)  $(3,225)
                                       liability
Change in income tax related
                                       regulatory assets and liabilities                         176    510       509
Change in alternative minimum
                                       tax credit                                                  -    (70)      567
                                                                          --------------------------  ------  --------
Deferred income tax expense (benefit)                                     $                    1,988  $ 328   $(2,149)
                                                                          ==========================  ======  ========
</TABLE>
THE  COMPONENTS  OF  THE  PROVISION  FOR  INCOME  TAXES  ARE  AS  FOLLOWS:
<TABLE>
<CAPTION>


                                                   YEARS ENDED DECEMBER 31,
                                             1999               1998      1997
                                --------------------------  --------  --------
<S>                             <C>                         <C>       <C>
                                                          (In thousands)
Current federal income taxes .  $                    (339)  $(1,047)  $ 7,355
Current state income taxes . .                       (125)     (366)    2,267
                                --------------------------  --------  --------
Total current income taxes . .                       (464)   (1,413)    9,622
Deferred federal income taxes.                      1,479       219    (1,623)
Deferred state income taxes. .                        509       109      (526)
                                --------------------------  --------  --------
Total deferred income taxes. .                      1,988       328    (2,149)
Investment tax credits-net . .                       (282)     (282)     (282)
                                --------------------------  --------  --------
Income tax provision (benefit)  $                   1,242   $(1,367)  $ 7,191
                                ==========================  ========  ========
</TABLE>
                                       51
<PAGE>

     TOTAL INCOME TAXES DIFFER FROM THE AMOUNTS COMPUTED BY APPLYING THE FEDERAL
STATUTORY  TAX RATE TO INCOME BEFORE TAXES.  THE REASONS FOR THE DIFFERENCES ARE
AS  FOLLOWS:
<TABLE>
<CAPTION>


                                                                       YEARS ENDED DECEMBER 31,
                                                                  1999               1998      1997
                                                       --------------------------  --------  --------
                                                                               (In thousands)
<S>                                                    <C>                         <C>       <C>
Income (loss) before income taxes and . . . . . . . .  $                  (1,821)  $(4,244)  $16,629
  preferred dividends
Federal statutory rate. . . . . . . . . . . . . . . .                       34.0%     34.0%     34.5%
Computed "expected" federal income
  taxes . . . . . . . . . . . . . . . . . . . . . . .                       (619)   (1,443)    5,730
Increase (decrease) in taxes resulting from:
Tax versus book depreciation. . . . . . . . . . . . .                         92       153       349
Dividends received and paid credit. . . . . . . . . .                       (485)     (480)     (575)
AFUDC-equity funds. . . . . . . . . . . . . . . . . .                         (5)      (36)     (123)
Amortization of ITC . . . . . . . . . . . . . . . . .                       (282)     (282)     (282)
State tax (benefit) . . . . . . . . . . . . . . . . .                        383      (256)    1,741
Excess deferred taxes . . . . . . . . . . . . . . . .                        (60)      (60)      (60)
Tax attributable to subsidiaries. . . . . . . . . . .                      2,271       845       682
Other . . . . . . . . . . . . . . . . . . . . . . . .                        (53)      192      (271)
                                                       --------------------------  --------  --------
Total federal and state income taxes. . . . . . . . .  $                   1,242   $(1,367)  $ 7,191
                                                       ==========================  ========  ========
Effective combined federal and state income tax rate.                      -68.2%     32.2%     43.2%
</TABLE>
 NON-UTILITY.  THE  COMPANY'S  NON-UTILITY  SUBSIDIARIES,  EXCLUDING  MEI,  HAD
ACCUMULATED  DEFERRED  INCOME  TAXES  OF  APPROXIMATELY $40,000 ON THEIR BALANCE
SHEETS  AT  DECEMBER  31,  1999,  LARGELY  ATTRIBUTABLE  TO  PROPERTY-RELATED
TRANSACTIONS.
          THE  COMPONENTS  OF THE PROVISION FOR THE INCOME TAX EXPENSE (BENEFIT)
FOR  THE  NON-UTILITY  OPERATIONS  ARE:
<TABLE>
<CAPTION>


                                                     YEARS ENDED DECEMBER 31,
                                                    1999    1998      1997
                              --------------------------  ------  --------
<S>                           <C>                         <C>     <C>
                                                        (In thousands)
State income taxes . . . . .  $                       99  $(281)  $   (20)
Federal income taxes . . . .                         310   (202)   (1,122)
                              --------------------------  ------  --------
Income tax expense (benefit)  $                      409  $(483)  $(1,142)
                              ==========================  ======  ========
</TABLE>
     THE  EFFECTIVE  COMBINED  FEDERAL  AND  STATE  INCOME  TAX  RATES  FOR  THE
CONTINUING  NON-UTILITY  OPERATIONS  WERE  34.0  PERCENT, 32.6 PERCENT, AND 37.0
PERCENT,  FOR  THE  YEARS  ENDED DECEMBER 31, 1999, 1998 AND 1997, RESPECTIVELY.
SEE  NOTE  L  FOR  INCOME  TAX  INFORMATION  ON  DISCONTINUED  OPERATIONS  OF
SUBSIDIARIES.

H.  PENSION  AND  RETIREMENT  PLANS.

     THE  COMPANY  HAS A DEFINED BENEFIT PENSION PLAN COVERING SUBSTANTIALLY ALL
OF  ITS EMPLOYEES.  THE RETIREMENT BENEFITS ARE BASED ON THE EMPLOYEES' LEVEL OF
COMPENSATION AND LENGTH OF SERVICE.  THE COMPANY'S POLICY IS TO FUND ALL ACCRUED
PENSION  COSTS.  THE COMPANY RECORDS ANNUAL EXPENSE AND ACCOUNTS FOR ITS PENSION
PLAN  IN  ACCORDANCE WITH STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NUMBER 87,
EMPLOYERS'  ACCOUNTING  FOR  PENSIONS.  THE COMPANY PROVIDES CERTAIN HEALTH CARE
BENEFITS  FOR RETIRED EMPLOYEES AND THEIR DEPENDENTS.  EMPLOYEES BECOME ELIGIBLE
FOR  THESE  BENEFITS  IF  THEY REACH NORMAL RETIREMENT AGE WHILE WORKING FOR THE
COMPANY.  THE COMPANY ACCRUES THE COST OF THESE BENEFITS DURING THE SERVICE LIFE
OF  COVERED  EMPLOYEES.

          ACCRUED  POSTRETIREMENT HEALTH CARE EXPENSES ARE RECOVERED IN RATES IF
THOSE  EXPENSES  ARE  FUNDED.  IN  ORDER  TO  MAXIMIZE  THE  TAX-DEDUCTIBLE
CONTRIBUTIONS  THAT  ARE  ALLOWED UNDER IRS REGULATIONS, THE COMPANY AMENDED ITS
PENSION  PLAN  TO ESTABLISH A 401-H SUB-ACCOUNT AND SEPARATE VEBA TRUSTS FOR ITS
                                       52
<PAGE>

UNION  AND  NON-UNION EMPLOYEES.  THE VEBA PLAN ASSETS CONSIST PRIMARILY OF CASH
EQUIVALENT  FUNDS, FIXED INCOME SECURITIES AND EQUITY SECURITIES.  THE FOLLOWING
PROVIDES A RECONCILIATION OF BENEFIT OBLIGATIONS, PLAN ASSETS, AND FUNDED STATUS
OF  THE  PLANS  AS  OF  DECEMBER  31,  1999  AND  1998.

<TABLE>
<CAPTION>


                                                                                            Other
                                                     Pension Benefits              Postretirement Benefits
                                                    ------------------            -------------------------
                                                           1999           1998              1999               1998
                                                    ------------------  --------  -------------------------  --------
                                                                           (In thousands)
<S>                                                 <C>                 <C>       <C>                        <C>
Change in projected benefit obligation:
Projected benefit obligation as of prior year end.  $          30,860   $28,630   $                 12,552   $11,046
Service cost . . . . . . . . . . . . . . . . . . .                620       787                        240       282
Interest cost. . . . . . . . . . . . . . . . . . .              1,780     2,043                        855       799
Special termination benefit. . . . . . . . . . . .              5,385     2,026                      1,446        44
Change in actuarial assumptions. . . . . . . . . .                  -         -                     (1,372)      897
Settlements. . . . . . . . . . . . . . . . . . . .             (9,527)        -                          -         -
Actuarial (gain) loss. . . . . . . . . . . . . . .             (2,080)      438                        (70)        -
Benefits paid. . . . . . . . . . . . . . . . . . .             (4,312)   (3,064)                      (864)     (558)
Curtailment. . . . . . . . . . . . . . . . . . . .               (282)        -                       (832)       42
                                                    ------------------  --------  -------------------------  --------
Projected benefit obligation as of year end. . . .  $          22,444   $30,860   $                 11,955   $12,552
                                                    ==================  ========  =========================  ========

Change in plan assets:
Fair value of plan assets as of prior year end . .  $          38,030   $35,773   $                  9,735   $ 7,893
Contribution . . . . . . . . . . . . . . . . . . .                  -         -                          -        76
Actual return on plan assets . . . . . . . . . . .              7,286     5,321                      1,327     1,766
Benefits paid. . . . . . . . . . . . . . . . . . .            (13,689)   (3,064)                         -         -
                                                    ------------------  --------  -------------------------  --------
Fair value of plan assets as of year end . . . . .  $          31,627   $38,030   $                 11,062   $ 9,735
                                                    ==================  ========  =========================  ========

Funded status as of year end . . . . . . . . . . .  $           9,032   $ 7,170   $                   (893)  $(2,817)
Unrecognized transition obligation (asset) . . . .               (571)   (1,021)                     4,264     4,926
Unrecognized prior service cost. . . . . . . . . .                887     1,113                       (635)     (743)
Unrecognized net actuarial gain. . . . . . . . . .            (12,193)   (7,569)                    (3,589)   (1,471)
                                                    ------------------  --------  -------------------------  --------
Accrued benefits at year end . . . . . . . . . . .  $          (2,845)  $  (307)  $                   (853)  $  (105)
                                                    ==================  ========  =========================  ========
</TABLE>

THE PENSION 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,  1999,  1998  AND  1997  WERE $556,000, $397,000 AND $456,000, RESPECTIVELY,
UNDER  THIS  PLAN.  THIS  PLAN  IS  FUNDED  IN PART THROUGH INSURANCE CONTRACTS.
          NET  PERIODIC  PENSION  EXPENSE AND OTHER POSTRETIREMENT BENEFIT COSTS
INCLUDE  THE  FOLLOWING  COMPONENTS:
                                       53
<PAGE>

<TABLE>
<CAPTION>

                                                       For  the  years  ended  December  31,
                                 Pension  Benefits                          Other  Postretirement
Benefits

                                                  1999      1998      1997     1999    1998    1997
                                                --------  --------  --------  ------  ------  ------
                                                                     (In thousands)
<S>                                             <C>       <C>       <C>       <C>     <C>     <C>
Service cost . . . . . . . . . . . . . . . . .  $   620   $   787   $   720   $ 240   $ 282   $ 228
interest cost. . . . . . . . . . . . . . . . .    1,780     2,043     2,069     855     799     763
Expected return on on plan assets. . . . . . .   (2,721)   (3,081)   (2,739)   (834)   (671)   (539)
Amortization of transition asset . . . . . . .     (196)     (228)     (228)      -       -       -
Amortization of net gain from earlier periods.        -         -         -       -       -     (28)
Amortization of prior service cost . . . . . .      128       134       143     (60)    (61)    (61)
Amortization of the transition obligation. . .        -         -         -     340     351     351
Recognized net actuarial gain. . . . . . . . .     (196)     (195)      (83)    (19)      -       -
Special termination benefit. . . . . . . . . .    3,122     2,026         -     888      27       -
Regulatory deferral. . . . . . . . . . . . . .   (3,122)   (2,026)             (888)    (27)
Adjustments due to actions of regulator. . . .        -         -       126       -       -       -
                                                --------  --------  --------  ------  ------  ------
            Net periodic benefit cost. . . . .  $  (585)  $  (540)  $     8   $ 522   $ 700   $ 714
                                                ========  ========  ========  ======  ======  ======
</TABLE>
     ASSUMPTIONS  USED TO DETERMINE POSTRETIREMENT BENEFIT COSTS AND THE RELATED
BENEFIT  OBLIGATION  WERE:
<TABLE>
<CAPTION>


                                                                                          Other
                                                     Pension benefits          Postretirement benefits
                                              -----------------         ------------------------
                                                          1999   1998                      1999   1998
                                              -----------------  -----  ------------------------  -----
<S>                                           <C>                <C>    <C>                       <C>
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . .              7.50%  6.75%                     7.50%  6.75%
Expected return on plan assets . . . . . . .              9.00%  9.00%                     8.50%  8.50%
Rate of compensation increase. . . . . . . .              4.50%  4.00%
</TABLE>
     FOR  MEASUREMENT PURPOSES, A 5.6 PERCENT ANNUAL RATE OF INCREASE IN THE PER
CAPITA  COST  OF  COVERED  MEDICAL  BENEFITS WAS ASSUMED FOR 1999.  THE RATE WAS
ASSUMED  TO  DECLINE  UNIFORMLY  TO 5.0 PERCENT FOR THE YEAR 2001 AND REMAINS 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 FOR ALL FUTURE YEARS WOULD
INCREASE  THE  ACCUMULATED  POSTRETIREMENT BENEFIT OBLIGATION AS OF DECEMBER 31,
1999  BY  $1.5 MILLION AND THE TOTAL OF THE SERVICE AND INTEREST COST COMPONENTS
OF  NET  PERIODIC  POSTRETIREMENT  COST  FOR THE YEAR ENDED DECEMBER 31, 1999 BY
$172,000.  DECREASING  THE  TREND  RATE  BY  ONE PERCENTAGE POINT FOR ALL FUTURE
YEARS  WOULD  DECREASE  THE  ACCUMULATED  POSTRETIREMENT  BENEFIT  OBLIGATION AT
DECEMBER  31,  1999  BY  $1.1 MILLION, AND THE TOTAL OF THE SERVICE AND INTEREST
COST  COMPONENTS  OF  NET  PERIODIC  POSTRETIREMENT  COST  FOR 1999 BY $139,000.
               IN 1999, THE COMPANY DEFERRED SPECIAL TERMINATION PENSION BENEFIT
COSTS  OF  $3,122,000  DUE  TO  AN  EARLY  RETIREMENT PROGRAM AND OTHER EMPLOYEE
SEPARATION  ACTIVITIES.  CURTAILMENT  AND  SETTLEMENT  GAINS OF $2.3 MILLION ARE
INCLUDED  IN  THE  SPECIAL  TERMINATION  PENSION  BENEFIT  COST.     THE SPECIAL
TERMINATION  BENEFIT  RECORDED IN 1998 RESULTED FROM THE EARLY RETIREMENT OPTION
OFFERED  TO  EMPLOYEES  IN  1998.  ALSO  IN  1999,  THE COMPANY DEFERRED SPECIAL
TERMINATION  POSTRETIREMENT BENEFIT COSTS OF $888,000 DUE TO AN EARLY RETIREMENT
PROGRAM.  MANAGEMENT  BELIEVES  THAT  THE  AMOUNTS  DEFERRED  ARE  PROBABLE  OF
RECOVERY.
          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".

                                       54
<PAGE>

I.     COMMITMENTS  AND  CONTINGENCIES

     1.  INDUSTRY  RESTRUCTURING.  THE  ELECTRIC  UTILITY  BUSINESS  IS  BEING
SUBJECTED  TO  RAPIDLY  INCREASING  COMPETITIVE  PRESSURES  STEMMING  FROM  A
COMBINATION  OF TRENDS, INCLUDING THE PRESENCE OF SURPLUS GENERATING CAPACITY, A
DISPARITY  IN  ELECTRIC  RATES  AMONG AND WITHIN VARIOUS REGIONS OF THE COUNTRY,
IMPROVEMENTS  IN  GENERATION  EFFICIENCY, INCREASING DEMAND FOR CUSTOMER CHOICE,
AND  NEW  REGULATIONS  AND  LEGISLATION  INTENDED  TO  FOSTER  COMPETITION.

     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.  WE BELIEVE THAT
WE  ARE IN SUBSTANTIAL COMPLIANCE WITH THOSE REQUIREMENTS, AND THAT THERE ARE NO
OUTSTANDING  MATERIAL COMPLAINTS ABOUT OUT COMPLIANCE WITH PRESENT ENVIRONMENTAL
PROTECTION REGULATIONS, EXCEPT FOR DEVELOPMENTS RELATED TO THE PINE STREET BARGE
CANAL  SITE.  THE  COMPANY  MAINTAINS AN ENVIRONMENTAL COMPLIANCE AND MONITORING
PROGRAM  THAT  INCLUDES  EMPLOYEE  TRAINING,  REGULAR  INSPECTION  OF  COMPANY
FACILITIES,  RESEARCH  AND  DEVELOPMENT  PROJECTS,  WASTE  HANDLING  AND  SPILL
PREVENTION  PROCEDURES  AND  OTHER  ACTIVITIES.
          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.
          IN  SEPTEMBER  1999,  WE NEGOTIATED A FINAL SETTLEMENT WITH THE UNITED
STATES,  THE  STATE OF VERMONT, AND OTHER PARTIES OVER TERMS OF A CONSENT DECREE
THAT  COVERS  CLAIMS ADDRESSED IN THE EARLIER NEGOTIATIONS AND IMPLEMENTATION OF
THE  SELECTED  REMEDY.  IN  NOVEMBER  1999,  THE CONSENT DECREE WAS FILED IN THE
FEDERAL DISTRICT COURT.  THE CONSENT DECREE ADDRESSES CLAIMS BY THE EPA FOR PAST
PINE  STREET  BARGE  CANAL SITE COSTS, NATURAL RESOURCE DAMAGE CLAIMS AND CLAIMS
FOR  PAST  AND FUTURE OVERSIGHT COSTS.  THE CONSENT DECREE ALSO PROVIDES FOR THE
DESIGN  AND  IMPLEMENTATION  OF  RESPONSE  ACTIONS  AT  THE  SITE.
          AS  OF  DECEMBER 31, 1999, THE COMPANY'S TOTAL EXPENDITURES RELATED TO
THE  PINE  STREET  BARGE CANAL SITE SINCE 1982 WERE APPROXIMATELY $22.2 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 PRP'S 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.
          WE  ESTIMATE  THAT  WE  HAVE  RECOVERED  OR  SECURED, OR WILL RECOVER,
THROUGH  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 RECENTLY
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  $8.7  TO  $12.5  MILLION,  RATHER  THAN  THE $5.0 TO $9.0 MILLION PREVIOUSLY
ESTIMATED.  IN  1998, WE RECORDED A LIABILITY OF $5 MILLION TO RECOGNIZE THE LOW
END  OF THIS RANGE OF COSTS. IN 1999 WE RECORDED AN ADDITIONAL LIABILITY OF $3.7
MILLION  TO  REFLECT  REVISED  ESTIMATES OF SITE MONITORING COSTS TO BE INCURRED
OVER  THE  NEXT  33 YEARS.  THE ESTIMATED LIABILITY IS NOT DISCOUNTED, AND IT IS
POSSIBLE  THAT  OUR  ESTIMATE OF FUTURE COSTS COULD CHANGE BY A MATERIAL AMOUNT.
WHILE  THE  VPSB  MAY  CHALLENGE  FULL RATE RECOVERY OF THE DEFERRED PINE STREET
COSTS,  AN OFFSETTING REGULATORY ASSET HAS BEEN RECORDED BECAUSE WE BELIEVE THAT
IT  IS  PROBABLE  THAT  THESE  COSTS  WILL  BE  RECOVERED  IN  FUTURE  REVENUES.

                                       55
<PAGE>

          CLEAN AIR ACT.     THE COMPANY PURCHASES MOST OF ITS POWER SUPPLY FROM
OTHER  UTILITIES  AND DOES NOT ANTICIPATE THAT IT WILL INCUR ANY MATERIAL DIRECT
COSTS  AS  A  RESULT  OF  THE  FEDERAL  CLEAN  AIR ACT OR PROPOSALS TO MAKE MORE
STRINGENT  REGULATIONS  UNDER  THAT  ACT.

     3.  OPERATING  LEASES.  THE  COMPANY  TERMINATED AN OPERATING LEASE FOR ITS
CORPORATE  HEADQUARTERS  BUILDING AND TWO OF ITS SERVICE CENTER BUILDINGS IN THE
FIRST  QUARTER  OF  1999.  DURING  1998,  THE  COMPANY  RECORDED  A  LOSS  OF
APPROXIMATELY  $1.9  MILLION  BEFORE  APPLICABLE  INCOME  TAXES  TO  REFLECT THE
PROBABLE  LOSS  RESULTING FROM THIS TRANSACTION.  THE COMPANY SOLD ITS CORPORATE
HEADQUARTERS  BUILDING  IN  1999,  BUT  RETAINED  OWNERSHIP  OF  THE TWO SERVICE
CENTERS.


     4.  JOINTLY-OWNED FACILITIES.  THE COMPANY HAS JOINT-OWNERSHIP INTERESTS IN
ELECTRIC  GENERATING  AND  TRANSMISSION  FACILITIES  AT  DECEMBER  31,  1999, AS
FOLLOWS:
<TABLE>
<CAPTION>


                          Ownership   Share of       Utility       Accumulated
                           INTEREST   CAPACITY        PLANT       DEPRECIATION
                          ----------  ---------  ---------------  -------------
<S>                       <C>         <C>        <C>              <C>
                              (In %)   (In MWh)   (In thousands)
Highgate . . . . . . . .        33.8       67.6  $        10,299  $       3,849
McNeil . . . . . . . . .        11.0        5.9            8,801          4,192
Stony Brook (No. 1). . .         8.8         31           10,331          7,194
Wyman (No. 4). . . . . .         1.1        6.8            1,980          1,129
Metallic Neutral Return.        59.4          -  $         1,563  $         556
</TABLE>
Metallic  Neutral  Return  is  a  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  ITS  OWN  FINANCING.

     5.  RATE  MATTERS.
     1997 RETAIL RATE CASE.  ON MARCH 2, 1998, THE VPSB RELEASED ITS ORDER DATED
FEBRUARY  27,  1998  IN  THE  THEN  PENDING  1997  RETAIL  RATE  CASE.  THE VPSB
AUTHORIZED  AN  INCREASE  IN THE COMPANY'S RATES BY 3.61 PERCENT, WHICH PROVIDED
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  A  PORTION  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 RETAIL RATE CASE.     IN ITS
FEBRUARY  27, 1998 ORDER, THE VPSB TALKED ABOUT 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

                                       56
<PAGE>

ORDER  TO  FUTURE  POWER  CONTRACT  COSTS IN OUR 1998 RETAIL RATE CASE, WE WOULD
LIKELY BE REQUIRED TO RECOGNIZE A CHARGE TO INCOME OF APPROXIMATELY $154 MILLION
BEFORE  INCOME  TAXES.   THE  $154  MILLION ESTIMATE REPRESENTS PRIMARILY THE 20
PERCENT  DISALLOWANCE  FOR  HYDRO-QUEBEC  POWER  COSTS  THAT THE VPSB CONSIDERED
IMPRUDENT IN ITS ORDER.  AT THIS TIME WE ARE UNABLE TO ESTIMATE THE LOSSES TO BE
RECORDED  FOR POWER PURCHASED BEYOND THE TEMPORARY SETTLEMENT PERIOD IN OUR 1998
RETAIL  RATE  CASE.
          IF  THE  VPSB  DOES  NOT  MODIFY  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 SFAS 71, 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.
          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 SPECIFIC COSTS DEFERRED ARE PROBABLE OF
FUTURE  RATE  RECOVERY.
          BASED  ON  THE DECEMBER 31, 1999 BALANCE SHEET, IF WE WERE REQUIRED TO
DISCONTINUE  THE  APPLICATION  OF  SFAS  71,  WE  WOULD BE REQUIRED TO RECORD AN
AFTER-TAX  CHARGE TO EARNINGS OF APPROXIMATELY $27.0 MILLION ATTRIBUTABLE TO NET
REGULATORY  ASSETS.
          WE FILED WITH THE VPSB A MOTION FOR RECONSIDERATION OF AND TO ALTER OR
AMEND  THE  VPSB'S ORDER RELEASED ON MARCH 2, 1998.     ON JUNE 8, 1998 THE VPSB
ISSUED  AN  ORDER  ON OUR MOTION FOR RECONSIDERATION WHICH MAINLY REAFFIRMED ITS
EARLIER ORDER.  WE THEN APPEALED THE VPSB'S FEBRUARY 27, 1998 ORDER AND THE JUNE
8,  1998  RECONSIDERATION  ORDER  TO  THE  VERMONT SUPREME COURT.  ORAL ARGUMENT
BEFORE  THE  SUPREME  COURT  WAS  HELD  ON  MARCH  16,  1999.
          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 ITS
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 HIGHER POWER COSTS, 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,  (THE DEPARTMENT), ARGUED FOR 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
                                       57
<PAGE>

HYDRO-QUEBEC  POWER  COSTS  IN THE AMOUNT OF $13 MILLION, AND THE ELIMINATION OF
THE  COMMON  STOCK  DIVIDEND.
          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
AGREEMENT TO SUSPEND OUR 1998 RATE CASE, DELAYED 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
CONTINUED  DISALLOWANCE  OF  HYDRO-QUEBEC POWER COSTS THROUGH DECEMBER 15, 1999.
THE  MOU PROVIDED A 5.5% TEMPORARY RETAIL RATE INCREASE, TO PRODUCE $8.9 MILLION
IN  ANNUALIZED  ADDITIONAL REVENUE, EFFECTIVE WITH SERVICE RENDERED DECEMBER 15,
1998.  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.  AT DECEMBER 31,
1999,  TOTAL  REVENUES  SUBJECT  TO  REFUND  ARE APPROXIMATELY $9.2 MILLION.  AN
ADDITIONAL  SURCHARGE  WAS  PERMITTED,  WITHOUT  FURTHER VPSB ORDER, IN ORDER TO
PRODUCE  ADDITIONAL  REVENUES NECESSARY TO PROVIDE THE COMPANY WITH THE CAPACITY
TO FINANCE 1999 PINE STREET BARGE CANAL SITE EXPENDITURES.  THE MOU WAS APPROVED
BY  THE  VPSB  ON  DECEMBER  11,  1998. THE MOU DID NOT PROVIDE FOR ANY SPECIFIC
DISALLOWANCE OF POWER COSTS UNDER OUR PURCHASE POWER CONTRACT WITH HYDRO-QUEBEC.
ISSUES  RESPECTING  RECOVERY  OF  SUCH  POWER  COSTS  WERE  PRESERVED FOR FUTURE
PROCEEDINGS.  THE  TEMPORARY  RATES INCLUDED $1.0 MILLION THAT IS TO BE USED FOR
ENHANCED  RIGHT  OF  WAY  MAINTENANCE  AND  POLE  TESTING  AND  TREATMENT.
     THE  STAY  AND  SUSPENSION OF THIS PENDING RATE CASE AND THE TEMPORARY RATE
LEVELS  AGREED  TO  IN  THE MOU WERE DESIGNED TO ALLOW US TO CONTINUE TO PROVIDE
ADEQUATE  AND  EFFICIENT  SERVICE  TO  OUR CUSTOMERS WHILE WE SEEK MITIGATION OF
POWER  SUPPLY  COSTS.
          THE  MOU  ALSO  PROVIDES  FOR AMORTIZATION OF REGULATORY ASSET ACCOUNT
BALANCES  OF  $5.1  MILLION,  WHICH  ARE SUBJECT TO RECOVERY IN THIS DOCKET 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.
          ON  SEPTEMBER  7  AND  DECEMBER 17, 1999, THE VPSB ISSUED ORDERS
APPROVING  TWO  AMENDMENTS TO THE MOU THAT THE COMPANY HAD ENTERED INTO WITH THE
DEPARTMENT  AND IBM.  THE TWO AMENDMENTS CONTINUED THE STAY OF PROCEEDINGS UNTIL
SEPTEMBER  1,  2000,  WITH  A FINAL DECISION EXPECTED BY DECEMBER 31, 2000.  THE
AMENDMENTS  MAINTAINED  THE  OTHER  FEATURES OF THE ORIGINAL MOU, AND THE SECOND
AMENDMENT  PROVIDES  FOR  A TEMPORARY RATE INCREASE OF 3 PERCENT, IN ADDITION TO
THE  CURRENT  TEMPORARY  RATE  LEVEL, TO BECOME EFFECTIVE AS OF JANUARY 1, 2000.
THE TEMPORARY RATES ARE STILL SUBJECT TO REFUND IN THE FINAL RATE CASE DECISION,
IF  THE  FINAL  RATES  SET ARE LOWER THAN THE TEMPORARY RATES.  ONE PARTY TO THE
RATE  CASE,  THE  AMERICAN  ASSOCIATION OF RETIRED PERSONS, (AARP), HAS FILED AN
APPEAL  TO  THE  VERMONT SUPREME COURT OF THE VPSB'S ORDER OF DECEMBER 17, 1999,
ARGUING  THAT  THE VPSB SHOULD HAVE ORDERED THE COMPANY TO POST A BOND OR ESCROW
FOR  THE  TEMPORARY RATE INCREASE.  THE COMPANY HAS MOVED TO DISMISS THE APPEAL.
AS  A  RESULT  OF  THE ORDERS, WE RECORDED AN ADDITIONAL LOSS OF $7.5 MILLION IN
1999,  REPRESENTING  THE  EFFECT  OF  THE CONTINUED DISALLOWANCE OF HYDRO-QUEBEC
POWER  COSTS  THROUGH  DECEMBER  31,  2000.
     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, ELIMINATING COMMON STOCK DIVIDENDS AND
THE  FILING  OF A PETITION FOR REORGANIZATION UNDER THE UNITED STATES BANKRUPTCY
CODE.

     6.  DEFERRED  CHARGES  NOT INCLUDED IN RATE BASE.  THE COMPANY HAS INCURRED
AND DEFERRED APPROXIMATELY $6.8 MILLION IN COSTS FOR TREE TRIMMING, STORM DAMAGE
AND  REGULATORY COMMISSION WORK OF WHICH $4.5 MILLION WILL BE AMORTIZED OVER SIX
YEARS  ENDING  IN  DECEMBER  2005.  CURRENTLY,  THE COMPANY AMORTIZES SUCH COSTS
BASED  ON HISTORICAL AVERAGES AND DOES NOT RECEIVE A RETURN ON AMOUNTS DEFERRED.
MANAGEMENT  EXPECTS  TO SEEK AND RECEIVE RATEMAKING TREATMENT FOR THESE COSTS IN
FUTURE  FILINGS.
                                       58
<PAGE>


     7.  OTHER  LEGAL  MATTERS.  THE  COMPANY  IS  INVOLVED  IN  LEGAL  AND
ADMINISTRATIVE PROCEEDINGS IN THE NORMAL COURSE OF BUSINESS AND DOES NOT BELIEVE
THAT  THE  ULTIMATE  OUTCOME OF THESE PROCEEDINGS WILL HAVE A MATERIAL EFFECT ON
THE  FINANCIAL  POSITION  OR  THE  RESULTS  OF  OPERATIONS  OF  THE  COMPANY.

J.     OBLIGATIONS  UNDER  TRANSMISSION  INTERCONNECTION  SUPPORT  AGREEMENT

          AGREEMENTS  EXECUTED IN 1985 AMONG THE COMPANY, VELCO AND OTHER NEPOOL
MEMBERS  AND  HYDRO-QUEBEC  PROVIDED  FOR  THE  CONSTRUCTION OF THE SECOND PHASE
(PHASE  II)  OF THE INTERCONNECTION BETWEEN THE NEW ENGLAND ELECTRIC SYSTEMS AND
THAT  OF  HYDRO-QUEBEC.  PHASE  II  EXPANDS  THE  PHASE  I  FACILITIES  FROM 690
MEGAWATTS TO 2,000 MEGAWATTS AND PROVIDES FOR TRANSMISSION OF HYDRO-QUEBEC POWER
FROM  THE  PHASE  I  TERMINAL  IN  NORTHERN  NEW  HAMPSHIRE  TO  SANDY  POND,
MASSACHUSETTS.  CONSTRUCTION  OF PHASE II COMMENCED IN 1988 AND WAS COMPLETED IN
LATE  1990.  THE COMPANY IS ENTITLED TO 3.2 PERCENT OF THE PHASE II POWER-SUPPLY
BENEFITS.  TOTAL  CONSTRUCTION  COSTS  FOR  PHASE  II  WERE  APPROXIMATELY  $487
MILLION.  THE  NEW  ENGLAND PARTICIPANTS, INCLUDING THE COMPANY, HAVE CONTRACTED
TO  PAY  MONTHLY  THEIR  PROPORTIONATE  SHARE OF THE TOTAL COST OF CONSTRUCTING,
OWNING  AND  OPERATING  THE  PHASE II FACILITIES, INCLUDING CAPITAL COSTS.  AS A
SUPPORTING PARTICIPANT, THE COMPANY MUST MAKE SUPPORT PAYMENTS UNDER THIRTY-YEAR
AGREEMENTS.  THESE  SUPPORT  AGREEMENTS  MEET  THE  CAPITAL  LEASE  ACCOUNTING
REQUIREMENTS  UNDER  SFAS  13.  AT  DECEMBER  31, 1999, THE PRESENT VALUE OF THE
COMPANY'S  OBLIGATION  IS  APPROXIMATELY  $7.0  MILLION.

          PROJECTED  FUTURE  MINIMUM  PAYMENTS  UNDER  THE  PHASE  II  SUPPORT
AGREEMENTS  ARE  AS  FOLLOWS
<TABLE>
<CAPTION>



                      Year ending December 31,
                     -------------------------
<S>                  <C>
2000. . . . . . . .  $                     440
2001. . . . . . . .                        440
2002. . . . . . . .                        440
2003. . . . . . . .                        440
2004. . . . . . . .                        440
Total for 2005-2020                      4,838
                     -------------------------
    Total . . . . .  $                   7,038
                     =========================
</TABLE>
     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 WHEN A
PRODUCTION  PLANT  IS  NOT OPERATING, IS REFLECTED AS "POWER SUPPLY EXPENSES" IN
THE  ACCOMPANYING  CONSOLIDATED  STATEMENTS  OF  INCOME.

          INFORMATION  (INCLUDING ESTIMATES FOR THE COMPANY'S PORTION OF CERTAIN
MINIMUM  COSTS AND ASCRIBED LONG-TERM DEBT) WITH REGARD TO SIGNIFICANT PURCHASED
POWER  CONTRACTS  OF  THIS  TYPE  IN  EFFECT  DURING  1999  FOLLOWS:
                                       59
<PAGE>

<TABLE>
<CAPTION>


                                                                STONY            VERMONT
                                                                BROOK             YANKEE
                                                       -----------------------  ----------
<S>                                <C>                 <C>                      <C>
                                                                  (Dollars in thousands)
Plant Capacity                                                       352.0 MW    531.0 MW
Company's share of output                                                4.40%      17.90%
Contract period                                                            (1)         (2)
Company's annual share of:
                                   Interest            $                  192   $   2,044
                                   Other debt service                     347
                                   Other capacity                         400      31,511
Total annual capacity                                  $                  939   $  33,555
                                                       =======================  ==========

Company's share of long-term debt                      $                3,609   $  17,425
</TABLE>
(1)  LIFE  OF  PLANT  ESTIMATED  TO  BE  1981  -  2006.
(2)  LICENSE  FOR  PLANT  OPERATIONS  EXPIRES  IN  2012.


     2.  HYDRO-QUEBEC SYSTEM POWER PURCHASE AND SALE COMMITMENTS.  UNDER VARIOUS
CONTRACTS,  THE  DETAILS  OF WHICH ARE DESCRIBED IN THE TABLE BELOW, THE COMPANY
PURCHASES  CAPACITY  AND  ASSOCIATED ENERGY PRODUCED BY THE HYDRO-QUEBEC SYSTEM.
SUCH  CONTRACTS OBLIGATE THE COMPANY TO PAY CERTAIN FIXED CAPACITY COSTS WHETHER
OR  NOT  ENERGY  PURCHASES  ABOVE A MINIMUM LEVEL SET FORTH IN THE CONTRACTS ARE
MADE.  SUCH  MINIMUM  ENERGY  PURCHASES  MUST BE MADE WHETHER OR NOT OTHER, LESS
EXPENSIVE  ENERGY  SOURCES  MIGHT BE AVAILABLE.  THESE CONTRACTS ARE INTENDED TO
COMPLEMENT  THE  OTHER  COMPONENTS  IN THE COMPANY'S POWER SUPPLY TO ACHIEVE THE
MOST  ECONOMIC  POWER-SUPPLY  MIX  REASONABLY  AVAILABLE.
          THE  COMPANY'S  CURRENT  PURCHASES  PURSUANT  TO  THE  CONTRACT  WITH
HYDRO-QUEBEC  ENTERED  INTO DECEMBER 4, 1987 (THE 1987 CONTRACT) ARE AS FOLLOWS:
(1)  SCHEDULE  B  --  68  MEGAWATTS OF FIRM CAPACITY AND ASSOCIATED ENERGY TO BE
DELIVERED  AT  THE  HIGHGATE  INTERCONNECTION  FOR  TWENTY  YEARS  BEGINNING  IN
SEPTEMBER  1995;  AND  (2)  SCHEDULE  C3  --  46  MEGAWATTS OF FIRM CAPACITY AND
ASSOCIATED  ENERGY  TO  BE DELIVERED AT INTERCONNECTIONS TO BE DETERMINED AT ANY
TIME  FOR  20  YEARS,  WHICH  BEGAN  IN  NOVEMBER  1995.
          DURING  1994,  THE COMPANY NEGOTIATED AN ARRANGEMENT WITH HYDRO-QUEBEC
THAT REDUCES THE COST IMPACTS ASSOCIATED WITH THE PURCHASE OF SCHEDULES B AND C3
UNDER THE 1987 CONTRACT, OVER THE NOVEMBER 1995 THROUGH OCTOBER 1999 PERIOD (THE
JULY  1994  AGREEMENT).  UNDER THE JULY 1994 AGREEMENT, THE COMPANY, IN ESSENCE,
WILL  TAKE  DELIVERY OF THE AMOUNTS OF ENERGY AS SPECIFIED IN THE 1987 CONTRACT,
BUT  THE  ASSOCIATED  FIXED  COSTS  WILL  BE  SIGNIFICANTLY  REDUCED  FROM THOSE
SPECIFIED  IN  THE  1987  CONTRACT.
          AS PART OF THE JULY 1994 AGREEMENT, WE WERE OBLIGATED TO PURCHASE $4.0
MILLION  (IN  1994  DOLLARS)  WORTH  OF  RESEARCH  AND  DEVELOPMENT  WORK  FROM
HYDRO-QUEBEC  OVER  A  PERIOD  ENDING  OCTOBER 1999, AND MADE AN ADDITIONAL $6.5
MILLION  (PLUS  ACCRUED INTEREST) 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.  THE  PERIOD  FOR  COMPLETING  THE RESEARCH AND DEVELOPMENT PURCHASE WAS
SUBSEQUENTLY  EXTENDED  TO  MARCH  2001.
          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 PAYMENTS TO HYDRO-QUEBEC, THE
COMBINED  UNIT  COSTS  WILL  BE LOWERED FROM 6.5 TO 5.9 CENTS PER KILOWATT-HOUR,
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:
                                       60
<PAGE>

<TABLE>
<CAPTION>


                                                                                    THE 1987 CONTRACT
                                                                              SCHEDULE B      SCHEDULE C3
                                                --------------------------------------       -------------
<S>                                 <C>                                     <C>            <C>
                                                                       (Dollars in thousands except per KWh)
Capacity acquired                                                               68 MW           47 MW
Contract period                                                             1995-2015       1995-2015
Minimum energy purchase                                                            75%             75%
(annual load factor)

Annual energy charge                      1999  $                              11,373    $      7,949
                          estimated  2000-2015                                 13,506 *         9,320*

Annual capacity charge                    1999                                 17,027           7,952
                                     2000-2015                                 16,686 *        11,523*

Average cost per KWh                      1999  $                               0.064    $      0.052
                                     2000-2015  $                               0.070**  $      0.070**
</TABLE>
*ESTIMATED  AVERAGE
**ESTIMATED  AVERAGE  IN  NOMINAL  DOLLARS  LEVELIZED  OVER THE PERIOD INDICATED
INCLUDES  AMORTIZATION  OF  PAYMENTS TO HYDRO-QUEBEC FOR THE JULY 1994 AGREEMENT

          UNDER  A  1996  ARRANGEMENT, THE COMPANY IS REQUIRED TO SHIFT UP TO 40
MEGAWATTS  OF  ITS  SCHEDULE  C3  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 WERE MADE.   THE
1996  ARRANGEMENT  ALSO  PROVIDES  FOR  MINIMUM  PAYMENTS  BY  THE  COMPANY  TO
HYDRO-QUEBEC  FOR  THE  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
BENEFIT  OF  APPROXIMATELY  $3.0  MILLION  ON  A  NET  PRESENT  VALUE  BASIS.
          UNDER  A SEPARATE AGREEMENT EXECUTED ON DECEMBER 5, 1997, HYDRO-QUEBEC
PROVIDED  A  PAYMENT OF $8.0 MILLION TO THE COMPANY IN 1997.  IN RETURN FOR THIS
PAYMENT,  THE  COMPANY  IS  PROVIDING HYDRO-QUEBEC AN OPTION FOR THE PURCHASE OF
POWER.  COMMENCING  APRIL  1,  1998,  AND  EFFECTIVE  THROUGH  OCTOBER  2015,
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 A TOTAL OF
600,000  MWH  AT  THE  1987 CONTRACT ENERGY PRICE.  HYDRO-QUEBEC CAN PURCHASE NO
MORE  THAN  200,000  MWH IN ANY GIVEN YEAR.  IN 1999, HYDRO-QUEBEC CALLED ON THE
COMPANY  TO  DELIVER 158,256 MWH TO A THIRD PARTY AT AN APPROXIMATE  NET COST OF
$5.4  MILLION, WHICH WAS DUE TO HIGHER ENERGY REPLACEMENT COSTS.  THE COMPANY IS
UNABLE TO ESTIMATE FUTURE COSTS FOR THIS AGREEMENT, WHICH ARE DEPENDENT UPON THE
TIMING  OF  ANY EXERCISE OF OPTIONS, AND THE MARKET PRICE FOR REPLACEMENT POWER.
HOWEVER,  THESE  COSTS  COULD  HAVE  A  MATERIAL ADVERSE EFFECT ON THE COMPANY'S
EARNINGS  AND  CASH  FLOWS.
     3.  MORGAN  STANLEY  AGREEMENT  -  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  HAS BEEN FULFILLED, CURRENTLY ANTICIPATED TO BE
JANUARY  31,  2002.  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,
WHICH  PROVIDES  UA  A  MEANS  OF  MANAGING PRICE RISKS ASSOCIATED WITH CHANGING
FOSSIL  FUEL  PRICES.
SALE  BY  THE  COMPANY  TO MS.-ON A DAILY BASIS, AND AT MS'S DISCRETION, WE WILL
SELL POWER TO MS FROM EITHER (I) ALL OR PART OF OUR PORTFOLIO OF POWER RESOURCES
AT  PREDEFINED  OPERATING  AND  PRICING  PARAMETERS  OR (II) ANY POWER RESOURCES
AVAILABLE  TO  US,  PROVIDED  THAT  SALES  OF  POWER  FROM  SOURCES  OTHER  THAN
COMPANY-OWNED  GENERATION  COMPLY  WITH  THE  PREDEFINED  OPERATING  AND PRICING
PARAMETERS.

                                       61
<PAGE>

SALE  BY  MS  TO THE COMPANY.- MS THEN SELLS TO US, AT A PREDEFINED PRICE, POWER
SUFFICIENT  TO  SERVE PRE-ESTABLISHED LOAD REQUIREMENTS.  MS IS ALSO RESPONSIBLE
FOR  BALANCING  SUPPLY RESOURCES WHEN ACTUAL LOADS VARY FROM THE PRE-ESTABLISHED
LOAD  REQUIREMENTS.  WE  REMAIN  RESPONSIBLE  FOR  RESOURCE  PERFORMANCE  AND
AVAILABILITY,  HOWEVER  MS  PROVIDES COVERAGE AGAINST MAJOR UNSCHEDULED OUTAGES,
CONTINGENT  UPON  BOTH  PRICE  AND  AVAILABILITY  OF  POWER  RESOURCES.

     L.  DISCONTINUED  OPERATIONS.
          THE COMPANY HAS DECIDED TO SELL OR OTHERWISE DISPOSE OF THE OPERATIONS
AND  ASSETS  OF  MEI,  WHICH  OWNS  AND  INVESTS  IN  ENERGY  GENERATION, ENERGY
EFFICIENCY,  AND  WASTEWATER  TREATMENT  PROJECTS.  MEI  HAS  BEEN REPORTED AS A
SEPARATE SEGMENT IN PRIOR YEARS, AND APPEARS AS A SEPARATE "EQUITY INVESTMENT IN
ENERGY  RELATED  BUSINESS" CAPTION IN THE NONUTILITY SECTION OF THE CONSOLIDATED
BALANCE  SHEET.  RESULTS  OF  OPERATIONS WERE PREVIOUSLY INCLUDED IN THE SECTION
OTHER  INCOME  IN  THE  CONSOLIDATING STATEMENTS OF INCOME.  IN 1999, ASSETS AND
LIABILITIES  ARE  PRESENTED  NET  IN THE NONUTILITY SECTION AS "BUSINESS SEGMENT
HELD  FOR  DISPOSAL".  THE  PROVISIONS  FOR  LOSS  FROM  DISCONTINUED OPERATIONS
REFLECT MANAGEMENT'S CURRENT ESTIMATE.  THE ULTIMATE LOSS REMAINS SUBJECT TO THE
CONSUMMATION  OF  A  SALE  OR  OTHER  DISPOSITION,  AND COULD EXCEED THE AMOUNTS
RECORDED.  THE  FOLLOWING ILLUSTRATES THE RESULTS AND FINANCIAL STATEMENT IMPACT
OF  MEI  DURING  AND  AT  THE  PERIODS  SHOWN:
<TABLE>
<CAPTION>



                                                                             1999                  1998     1997
                                                               --------------------------------  --------  -------
<S>                                   <C>                      <C>                               <C>       <C>
                                                                                   (In thousands except per share)
Revenues                                                       $                         2,296   $ 2,092   $ 4,500
Net income (loss) operations                                                              (603)   (2,086)      142
Provisions for loss on disposal and
                                      future operating losses                           (6,676)        -         -
Net income (loss)                                                                       (7,279)   (2,086)      142
Net income (loss) per share                                                              (1.36)    (0.40)     0.03
Assets                                                         $                        19,395   $26,810   $25,046
</TABLE>
AT  DECEMBER  31,  1999,  MEI  HAD UNSECURED LONG-TERM DEBT OF $1.2 MILLION, ALL
BECOMING  DUE  IN  THE  YEAR  2000.
INCOME  TAXES  FOR  MEI FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 ARE
SUMMARIZED  AS:
<TABLE>
<CAPTION>


                                             YEARS ENDED DECEMBER 31,
                                         1999               1998     1997
                              --------------------------  --------  ------
                                                    (In thousands)
<S>                           <C>                         <C>       <C>
State income taxes . . . . .  $                    (281)  $  (222)  $  98
Federal income taxes . . . .                     (1,371)   (1,130)     51
Investment tax credits . . .                          -      (111)    (45)
                              --------------------------  --------  ------
Income tax expense (benefit)  $                  (1,652)  $(1,463)  $ 104
                              ==========================  ========  ======
</TABLE>
M.  SUBSEQUENT  EVENTS.
          ON  JANUARY 31, 2000, THE COMPANY AMENDED ITS CONTRACT WITH MS.  SALES
UNDER  THE  AMENDED  AGREEMENT  BEGIN  FEBRUARY  15, 2000, AND WILL TERMINATE ON
JANUARY  31, 2002.  THE AMENDED AGREEMENT CONTAINS THE FEATURES, AS DISCUSSED IN
NOTE  K,  OF  THE  ORIGINAL  AGREEMENT AND ADDS SEVERAL SERVICES.  THE AMENDMENT
ASSIGNS  MS  THE  RESPONSIBILITIES  OF  SCHEDULING  THE  COMPANY'S RESOURCES AND
SEEKING  ECONOMICAL  ENERGY  TO MEET LOADS NOT COVERED BY THE BASE CONTRACT.  IT
ALSO  ADDS  A  PROVISION  THAT  GUARANTEES  A  PAYMENT TO THE COMPANY IN CASE OF
UNSCHEDULED  UNIT  OUTAGES  UP TO 114 MW DURING PERIODS OF HIGH REPLACEMENT COST
ENERGY.  THE  AMENDMENT  ALSO  REMOVES  ENERGY  FROM  THE  COMPANY'S  INTERNAL
COMBUSTION  UNITS  FROM  THE CONTROL OF MS, ALLOWING THE COMPANY TO RESERVE THAT
FOR  ITS  OWN  NEEDS.  THE COMPANY REMAINS RESPONSIBLE FOR PLANT PERFORMANCE NOT
COVERED  UNDER  THIS  PROVISION.
                                       62
<PAGE>


     N.  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.
<TABLE>
<CAPTION>


                                                                      1999 Quarter ended
                                                      MARCH            JUNE     SEPTEMBER    DECEMBER     TOTAL
                                               --------------------  --------  -----------  ----------  ---------
(Amounts in thousands except per share data)
<S>                                            <C>                   <C>       <C>          <C>         <C>
Operating Revenues. . . . . . . . . . . . . .  $            59,018   $59,535   $   68,478   $  64,017   $251,048
Operating Income. . . . . . . . . . . . . . .                3,906       977        1,412       1,651      7,946
Net Income (loss) from continuing operations.                3,170      (412)        (115)        418      3,061
Net Income (loss) from
 discontinued operations. . . . . . . . . . .                 (522)      (81)      (4,592)     (2,084)    (7,279)
Net Income (loss) applicable to common stock.                2,648      (493)      (4,707)     (1,666)    (4,218)
Earnings (loss) per average share
from: Continuing operations . . . . . . . . .                 0.60     (0.08)       (0.02)       0.07       0.57
Discontinued operations . . . . . . . . . . .                (0.10)    (0.02)       (0.85)      (0.39)     (1.36)
Basic and diluted . . . . . . . . . . . . . .  $              0.50   $ (0.10)  $    (0.88)  $   (0.31)  $  (0.79)
Weighted average common shares outstanding. .                5,318     5,344        5,374       5,291      5,361
</TABLE>


<TABLE>
<CAPTION>


                                                                    1998 Quarter ended
                                                      MARCH            JUNE     SEPTEMBER    DECEMBER     TOTAL
                                               --------------------  --------  -----------  ----------  ---------
                                                               (Amounts in thousands except per share data)
<S>                                            <C>                   <C>       <C>          <C>         <C>
Operating Revenues. . . . . . . . . . . . . .  $            46,932   $43,733   $   47,984   $  45,655   $184,304
Operating Income. . . . . . . . . . . . . . .                  316     2,811        3,147        (802)     5,472
Net Income (loss) from continuing operations.               (2,648)    1,286        1,811      (2,536)    (2,087)
Net Income (loss) from
discontinued operations . . . . . . . . . . .                 (757)     (355)        (178)       (796)    (2,086)
Net Income (loss) applicable to common stock.               (3,405)      931        1,633      (3,332)    (4,173)
Earnings (loss) per average share
from: Continuing operations . . . . . . . . .                (0.51)     0.25         0.34       (0.48)     (0.40)
Discontinued operations . . . . . . . . . . .                (0.15)    (0.06)       (0.03)      (0.16)     (0.40)
Basic and diluted . . . . . . . . . . . . . .  $             (0.66)  $  0.18   $     0.31   $   (0.63)  $  (0.80)
Weighted average common shares outstanding. .                5,196     5,222        5,261       5,291      5,243
</TABLE>


<TABLE>
<CAPTION>


                                                                          1997 Quarter ended
                                                      MARCH           JUNE    SEPTEMBER    DECEMBER    TOTAL
                                               --------------------  -------  ----------  ----------  --------
                                                             (Amounts in thousands except per share data)
<S>                                            <C>                   <C>      <C>         <C>         <C>
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 (loss) from continuing operations.                3,003       298       2,468      2,094      7,863
Net Income (loss) from
discontinued operations . . . . . . . . . . .                  (62)      558         554       (908)       142
Net Income (loss) applicable to common stock.                2,941       856       3,022      1,186      8,005
Earnings (loss) per average share
from: Continuing operations . . . . . . . . .                 0.60      0.06        0.48       0.41       1.54
Discontinued operations . . . . . . . . . . .                (0.01)     0.11        0.11      (0.18)      0.03
Basic and diluted . . . . . . . . . . . . . .  $              0.58   $  0.17  $     0.59  $    0.23   $   1.57
Weighted average common shares outstanding. .                5,044     5,096       5,138      5,168      5,112
</TABLE>

                                       63
<PAGE>




                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


TO  THE  BOARD  OF  DIRECTORS  OF
   GREEN  MOUNTAIN  POWER  CORPORATION:

WE  HAVE  AUDITED  THE ACCOMPANYING CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED
CAPITALIZATION  DATA OF GREEN MOUNTAIN POWER CORPORATION (A VERMONT CORPORATION)
AND  ITS  SUBSIDIARIES  AS  OF  DECEMBER  31,  1999  AND  1998,  AND THE RELATED
CONSOLIDATED STATEMENTS OF INCOME, RETAINED EARNINGS, AND CASH FLOWS FOR EACH OF
THE  THREE  YEARS  IN  THE  PERIOD  ENDED  DECEMBER  31,  1999.  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  AUDIT.

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  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 THAT WAS INITIATED IN 1998 AND IS
ANTICIPATED  TO  REACH  FINAL DECISION BY DECEMBER 31, 2000.  THE OUTCOME OF THE
APPEAL  PROCESS  AND THE RATE PROCEEDING COULD HAVE A SIGNIFICANT ADVERSE IMPACT
ON THE COMPANY'S REPORTED FINANCIAL CONDITION AND 2000 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 ASPECTS, THE FINANCIAL POSITION OF GREEN MOUNTAIN POWER
CORPORATION  AND  ITS  SUBSIDIARIES  AS  OF  DECEMBER 31, 1999 AND 1998, AND THE
CONSOLIDATED  RESULTS  OF  ITS  OPERATIONS  AND CASH FLOWS FOR EACH OF THE THREE
YEARS  IN  THE  PERIOD  ENDED  DECEMBER  31,  1999, IN CONFORMITY WITH GENERALLY
ACCEPTED  ACCOUNTING  PRINCIPLES.




/S/  ARTHUR  ANDERSEN  LLP


BOSTON,  MASSACHUSETTS
FEBRUARY  4,  2000

                                       64
<PAGE>

<TABLE>
<CAPTION>

Schedule  II
GREEN  MOUNTAIN  POWER  CORPORATION
VALUATION  AND  QUALIFYING  ACCOUNTS  AND  RESERVES
For  the  Years  Ended  December  31,  1999,  1998  and  1997

                           Balance at       Additions         Additions                   Balance at
                          Beginning of      Charged to        Charged to                    End of
                             Period      Cost & Expenses    Other Accounts   Deductions     Period
                          -------------  ----------------  ----------------  -----------  -----------
<S>                       <C>            <C>               <C>               <C>          <C>
Injuries and Damages (1)
1999 . . . . . . . . . .  $   7,898,785  $        100,000  $     3,814,874   $ 1,684,529  $10,129,130
1998 . . . . . . . . . .  $     663,785  $      2,735,000  $     5,000,000   $   500,000  $ 7,898,785
1997                      $     237,892  $        427,546             ----   $     1,653  $   663,785
Bad Debt Reserve
1999 . . . . . . . . . .  $     400,000  $        261,697  $        12,762   $   283,964  $   390,495
1998(2). . . . . . . . .  $     493,405  $        393,949  $        83,299   $   570,653  $   400,000
1997(2). . . . . . . . .  $     498,024  $        637,010  $    173,899 (3)  $   815,528  $   493,405
</TABLE>


(1)  Includes  Pine  Street  Barge  Canal  reserves
(2)  Includes  non-utility  bad  debt  reserve.
(3)  Represents  collection  of  accounts  previously  written  off.

                                       65
<PAGE>

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

     NONE


                                    PART III

ITEMS  10,  11,  12  &  13

     CERTAIN  INFORMATION  REGARDING  EXECUTIVE  OFFICERS CALLED FOR BY ITEM 10,
"DIRECTORS  AND  EXECUTIVE  OFFICERS  OF THE REGISTRANT," IS FURNISHED UNDER THE
CAPTION,  "EXECUTIVE  OFFICERS"  IN  ITEM 1 OF PART I OF THIS REPORT.  THE OTHER
INFORMATION  CALLED  FOR BY ITEM 10, AS WELL AS THAT CALLED FOR BY ITEMS 11, 12,
AND  13,  "EXECUTIVE  COMPENSATION,"  "SECURITY  OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS  AND  MANAGEMENT"  AND  "CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,"
WILL  BE  SET  FORTH  UNDER  THE  CAPTIONS  "ELECTION  OF  DIRECTORS,"  BOARD
COMPENSATION,  OTHER  RELATIONSHIP,  MEETINGS  AND  COMMITTEES,  "SECTION  16(A)
BENEFICIAL  OWNERSHIP  REPORTING  COMPLIANCE,"  "EXECUTIVE  COMPENSATION,"
COMPENSATION  COMMITTEE  REPORT  ON  EXECUTIVE COMPENSATION, PERFORMANCE GRAPHS,
"PENSION  PLAN  INFORMATION"  AND  "SECURITIES  OWNERSHIP  OF CERTAIN BENEFICIAL
OWNERS  AND  MANAGEMENT" IN THE COMPANY'S DEFINITIVE PROXY STATEMENT RELATING TO
ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD ON MAY 18, 2000.  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  2000.


                                     PART IV

ITEM  14.  EXHIBITS,  FINANCIAL  STATEMENT  SCHEDULES  AND  REPORTS  ON
          FORM  8-K
ITEM  14(A)1.  FINANCIAL  STATEMENTS AND SCHEDULES. THE FINANCIAL STATEMENTS AND
FINANCIAL  STATEMENT  SCHEDULES  OF  THE  COMPANY  ARE  LISTED  ON  THE INDEX TO
FINANCIAL  STATEMENTS  SET  FORTH  IN  ITEM  8  HEREOF.

ITEM  14(B)     A  REPORT  ON  FORM 8-K WAS FILED ON DECEMBER 8, 1999 ANNOUNCING
AGREEMENT  WITH  THE  VERMONT  DEPARTMENT  OF  PUBLIC  SERVICE AND INTERNATIONAL
BUSINESS MACHINES ON A TEMPORARY 3 PERCENT RATE INCREASE, SUBJECT TO THE VERMONT
PUBLIC  SERVICE BOARD APPROVAL. IN ADDITION, IT WAS ANNOUNCED THAT THE COMPANY'S
LENDING  ARRANGEMENTS,  SPECIFICALLY  THE TOTAL AMOUNT AVAILABLE OF $15 MILLION,
WERE  CONTINUED  AFTER  EXTENSIVE  DISCUSSIONS  WITH  THE  BANKS  INVOLVED.

     A  REPORT ON FORM 8-K WAS FILED ON DECEMBER 17, 1999 ANNOUNCING THE VERMONT
PUBLIC  SERVICE BOARD APPROVAL OF A 3 PERCENT TEMPORARY RATE INCREASE, EFFECTIVE
FOR  SERVICE  RENDERED  AFTER  DECEMBER  31,  1999.


                                       66
<PAGE>

                                                                  EXHIBIT 23-A-1

                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





AS INDEPENDENT PUBLIC ACCOUNTANTS, WE HEREBY CONSENT TO THE INCORPORATION OF OUR
REPORTS  DATED  FEBRUARY  4,  2000 INCLUDED IN THIS FORM 10-K INTO THE COMPANY'S
PREVIOUSLY  FILED  REGISTRATION  STATEMENTS  ON FORM S-3, FILE NOS. 33-58411 AND
33-59383,  AND  INTO  THE  COMPANY'S PREVIOUSLY FILED REGISTRATION STATEMENTS ON
FORM  S-8,  FILE  NOS.  33-58413  AND  33-60511.




BOSTON,  MASSACHUSETTS
MARCH  21,  2000                              /S/  ARTHUR  ANDERSEN  LLP






                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS





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 4, 2000. 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 ACCOMPANYING INDEX TO
CONSOLIDATED  FINANCIAL  STATEMENTS  AND  SCHEDULES IS PRESENTED FOR PURPOSES OF
COMPLYING WITH THE SECURITIES AND EXCHANGE COMMISSION'S RULES AND IS NOT PART OF
THE BASIC CONSOLIDATED FINANCIAL STATEMENTS. THIS SCHEDULE HAS BEEN SUBJECTED TO
THE AUDITING PROCEDURES APPLIED IN THE AUDIT OF THE BASIC CONSOLIDATED FINANCIAL
STATEMENTS,  AND  IN  OUR  OPINION, FAIRLY STATES, IN ALL MATERIAL RESPECTS, THE
FINANCIAL  DATA  REQUIRED  TO  BE  SET  FORTH  THEREIN  IN RELATION TO THE BASIC
CONSOLIDATED  FINANCIAL  STATEMENTS  TAKEN  AS  A  WHOLE.




BOSTON,  MASSACHUSETTS
FEBRUARY  4,  2000                         /S/  ARTHUR  ANDERSEN  LLP



                                       67
<PAGE>

<TABLE>
<CAPTION>


            Item 14(a)3 and Item 14(c).  Exhibits                                        SEC Docket
   Form                                                                                incorporated by
 Exhibit                                                                                reference or
  Number    Description                                                  Exhibit     Page filed herewith
----------  ----------------------------------------------------------  ----------  ---------------------
<C>         <S>                                                         <C>         <C>
       3-a  Restated Articles of Association, as certified . . . . . .         3-a  Form 10-K 1993
            June 6, 1991.                                                                        (1-8291)
     3-a-1  Amendment to 3-a above, dated as of May 20, 1993.. . . . .       3-a-1  Form 10-K 1993
                                                                                                 (1-8291)
     3-a-2  Amendment to 3-a above, dated as of October 11, 1996.. . .       3-a-2  Form 10-Q Sept. 1996
                                                                                                 (1-8291)
       3-b  By-laws of the Company, as amended . . . . . . . . . . . .         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 September
            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(a)  Amendment to Exhibit 4-b-18. . . . . . . . . . . . . . . .   4-b-18(a)  Form 10-Q Sept. 1998
                                                                                                 (1-8291)
      10-a  Form of Insurance Policy issued by Pacific . . . . . . . .        10-a               33-8146
            Insurance Company, with respect to
            indemnification of Directors and Officers.


                                       68
<PAGE>
    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(a)  Amendment, dated April 15, 1983, to Power. . . . . . . . .   10-b-3(a)               33-8164
            Contract between the Company and Vermont
            Yankee Nuclear Power Corporation.
 10-b-3(b)  Additional Power Contract, dated . . . . . . . . . . . . .   10-b-3(b)               33-8164
            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.

                                       69
<PAGE>
   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-Qubec.
   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-Qubec.
   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-Qubec.
   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-Qubec.
   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-Qubec.
   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-Qubec.
   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-Qubec, 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-Qubec.
   10-b-43  Interconnection Agreement dated March 21, 1983,. . . . . .     10-b-43               33-8164
            between Hydro-Qubec 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-Qubec.
                                       70
<PAGE>

   10-b-44  Energy Contract dated March 21, 1983, between. . . . . . .     10-b-44               33-8164
            Hydro-Qubec and participating New England
            utilities acting by and through the NEPOOL
            Management Committee for purchase of
            surplus energy from Hydro-Qubec.
   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-Qubec 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-Qubec + 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.
                                       71
<PAGE>

   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-Qubec 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(a)  Amendment to 10-b-70.. . . . . . . . . . . . . . . . . . .  10-b-70(a)  Form 10-K 1992
                                                                                                 (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-Qubec.
   10-b-72  Participation Agreement dated as of April 1, 1988, . . . .     10-b-72  Form 10-Q
            between Hydro-Qubec 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(a)  Restatement of the Participation Agreement filed . . . . .  10-b-72(a)  Form 10-K 1988
            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                          September. 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                        September. 1988
            Company, for sale of electric capacity and                                           (1-8291)
            associated energy.
10-b-74(a)  Amendment to Exhibit 10-b-74.. . . . . . . . . . . . . . .  10-b-74(a)  Form 10-Q
                                                                                    September 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,                         September. 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-Qubec and participating                                          (1-8291)
            Vermont utilities, including the Company, for the
            purchase of up to 54 MW of firm power and energy.
                                       72
<PAGE>

   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  Form 10-K 1998
            Morgan Stanley Capital Group Inc. and the                                            (1-8291)
            Company
            MANAGEMENT CONTRACTS OR COMPENSATORY PLANS OR ARRANGEMENTS
            REQUIRED TO BE FILED AS EXHIBITS TO THIS FORM 10-K
            PURSUANT TO ITEM 14(C)., ALL UNDER SEC DOCKET 1-8291
   10-d-1b  Green Mountain Power Corporation Second Amended. . . . . .     10-d-1b  Form 10-K 1993
            and Restated Deferred Compensation Plan for
            Directors.
   10-d-1c  Green Mountain Power Corporation Second Amended. . . . . .     10-d-1c  Form 10-K 1993
            and Restated Deferred Compensation Plan for
            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.
   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
                                       73
<PAGE>

    10-d-2  Green Mountain Power Corporation Medical Expense . . . . .      10-d-2  Form 10-K 1991
            Reimbursement Plan.
    10-d-4  Green Mountain Power Corporation Officer . . . . . . . . .      10-d-4  Form 10-K 1991
            Insurance Plan.
   10-d-4a  Green Mountain Power Corporation Officers' . . . . . . . .     10-d-4a  Form 10-K 1990
            Insurance Plan as amended.
    10-d-8  Green Mountain Power Corporation Officers' . . . . . . . .      10-d-8  Form 10-K 1990
            Supplemental Retirement Plan.
  10-d-15b  Green Mountain Power Corporation Compensation Program. . .    10-d-15b  Form 10-K 1997
            for Officers and Key Management Personnel as amended
            August 4, 1997
   10-d-21  Severance Agreement with N. R. Brock . . . . . . . . . . .     10-d-21  Form 10-K 1998
   10-d-22  Severance Agreement with C. L. Dutton. . . . . . . . . . .     10-d-22  Form 10-K 1998
   10-d-23  Severance Agreement with R. J. Griffin . . . . . . . . . .     10-d-23  Form 10-K 1998
   10-d-24  Severance Agreement with J. J. Lampron . . . . . . . . . .     10-d-24  Form 10-K 1998
   10-d-25  Severance Agreement with M. H. Lipson. . . . . . . . . . .     10-d-25  Form 10-K 1998
   10-d-26  Severance Agreement with C. T. Myotte. . . . . . . . . . .     10-d-26  Form 10-K 1998
   10-d-27  Severance Agreement with W. S. Oakes . . . . . . . . . . .     10-d-27  Form 10-K 1998
   10-d-28  Severance Agreement with M. G. Powell. . . . . . . . . . .     10-d-28  Form 10-K 1998
   10-d-29  Severance Agreement with S. C. Terry . . . . . . . . . . .     10-d-29  Form 10-K 1998
   10-d-30  Severance Agreement with J. H. Winer . . . . . . . . . . .     10-d-30  Form 10-K 1998
        21  Subsidiaries of the Registrant . . . . . . . . . . . . . .          21  Form 10-K 1996
   *23-a-1  Consent of Arthur Andersen LLP
       *27  Financial Data Schedule
</TABLE>
                                       74
<PAGE>


                                   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  28,  2000

     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 28, 2000
   -------------------------
   Christopher  L.  Dutton      (Principal  Executive  Officer)


 _/s/Nancy R. Brock_______    Vice President, Treasurer and       March 28, 2000
  ---------------------
   Nancy  R.  Brock             Chief  Financial  Officer  (Principal
                              Financial  Officer)


 /s/Robert  J.  Griffin_    Controller                          March  28,  2000
 -----------------------
   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 28, 2000
       ---------------------------
     Christopher  L.  Dutton
     (Attorney  -  in  -  Fact)


                                       75
<PAGE>